**UNITEDSTATES**

**SECURITIESAND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

 

**FORM 10-Q**

 

**QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OFTHE SECURITIES**

**EXCHANGE ACT OF 1934**

 

**Forthe quarterly period ended March 31, 2008**

 

**CommissionFile No. 001-32920**

 

(Exactname of registrant as specified in its charter)

 
| **Yukon Territory**                                               | ** ** | **N/A**                                 |
|-------------------------------------------------------------------|------------|-----------------------------------------|
| (State  or other jurisdiction of incorporation   or organization) |       | (I.R.S.  Employer   Identification No.) |

 

**1625 Broadway, Suite 250**

**Denver, Colorado 80202**

(Addressof principal executive offices, including zip code)

 

**303-592-8075**

(Registrant’stelephone number, including area code)

 

Indicate bycheck mark whether the registrant (1) has filed all reports required to befiled by Section 13 or 15(d) of the Securities Exchange Act of 1934during the preceding 12 months (or for such shorter period that the registrantwas required to file such reports), and (2) has been subject to suchfiling requirements for the past 90 days.

Yes  x     No   o

 

Indicate bycheck mark whether the registrant is a large accelerated filer, an acceleratedfiler, a non-accelerated filer or a smaller reporting company.  See definition of “accelerated filer”, largeaccelerated filer” and “smaller reporting company” in Rule 12b-2 of theExchange Act.

 
|   | Large  accelerated filer o | Accelerated  filer x | Non-accelerated  filer o | Smaller  reporting company o |
|--------|----------------------------|----------------------|--------------------------|------------------------------|

 

Indicate bycheck mark whether the registrant is a shell company (as defined in Rule 12b-2of the Exchange Act).

Yes  o      No  x

 

        88,030,431 shares of no par value of theRegistrant’s Common Stock were issued and outstanding as of April 30,2008.

 

 

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**KODIAKOIL & GAS CORP.**

 

**INDEX**

 
| PART 1 — FINANCIAL INFORMATION | 2                                                                                                              |
|------------------------------------------|----------------------------------------------------------------------------------------------------------------|
|                                     |                                                                                                           |   |
| ITEM 1. FINANCIAL STATEMENTS             | 2                                                                                                              |
|                                     |                                                                                                           |   |
|                                     | Condensed  Consolidated Balance Sheets as of March 31, 2008 &  December 31, 2007            | 2 |
|                                     | Condensed Consolidated  Statement of Operations for the Three Months Ended March 31, 2008 & 2007 | 3 |
|                                     | Condensed Consolidated  Statement of Cash Flows for the Three Months Ended March 31, 2008 & 2007 | 4 |
|                                     | Notes to Condensed Consolidated Financial Statements                                                           | 5 |
|                                     |                                                                                                           |   |
| ITEM 2.                                  | MANAGEMENT’S  DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS                    | 14 |
|                                     |                                                                                                           |   |
| ITEM 3.                                  | QUANTITATIVE  AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                                                    | 24 |
|                                     |                                                                                                           |   |
| ITEM 4.                                  | CONTROLS AND  PROCEDURES                                                                                       | 25 |
|                                     |                                                                                                           |   |
| PART II — OTHER  INFORMATION   | 25                                                                                                             |
|                                     |                                                                                                           |   |
| ITEM 1.                                  | LEGAL PROCEEDINGS                                                                                              | 25 |
|                                     |                                                                                                           |   |
| ITEM 1A.                                 | RISK  FACTORS                                                                                                  | 25 |
|                                     |                                                                                                           |   |
| ITEM 2.                                  | UNREGISTERED  SALES OF EQUITY SECURITIES AND USE OF PROCEEDS                                                   | 25 |
|                                     |                                                                                                           |   |
| ITEM 3.                                  | DEFAULTS  UPON SENIOR SECURITIES                                                                               | 25 |
|                                     |                                                                                                           |   |
| ITEM 4.                                  | SUBMISSION  OF MATTERS TO A VOTE OF SECURITY HOLDERS                                                           | 26 |
|                                     |                                                                                                           |   |
| ITEM 5.                                  | OTHER INFORMATION                                                                                              | 26 |
|                                     |                                                                                                           |   |
| ITEM  6. EXHIBITS                        | 27                                                                                                             |
|                                     |                                                                                                           |   |
| SIGNATURES                               | 28                                                                                                             |

 

i

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# **PART 1 -FINANCIAL INFORMATION**

# ** **

# **ITEM 1.FINANCIAL STATEMENTS**

# ** **

**KODIAKOIL & GAS CORP.**

**CONDENSED CONSOLIDATED BALANCE SHEETS**

 
| ** **                                                                                             | ** ** | **(UNAUDITED)**    | ** ** | **(AUDITED)**         | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|--------------------|------------|-----------------------|------------|
| ** **                                                                                             | ** ** | **March 31,** | ** ** | **December 31,** | ** ** |
| ** **                                                                                             | ** ** | **2008**           | ** ** | **2007**              | ** ** |
| **ASSETS**                                                                                             |       |               |       |                  |       |
| Current Assets:                                                                                        |       |               |       |                  |       |
| Cash and cash equivalents                                                                              |       | $                  | 9,904,019  |                  | $          | 13,015,318 |   |
| Accounts receivable                                                                                    |       |               |       |                  |       |
| Trade                                                                                                  |       | 1,099,043          |       | 1,373,843             |       |
| Accrued sales revenues                                                                                 |       | 799,611            |       | 789,652               |       |
| Prepaid expenses and other                                                                             |       | 118,458            |       | 198,996               |       |
| Total Current Assets                                                                                   |       | 11,921,131         |       | 15,377,809            |       |
|                                                                                                   |       |               |       |                  |       |
| Property and equipment (full cost method), at cost:                                                    |       |               |       |                  |       |
| Proved oil and gas properties                                                                          |       | 77,791,640         |       | 77,272,437            |       |
| Unproved oil and gas properties                                                                        |       | 21,666,305         |       | 21,904,737            |       |
| Wells in progress                                                                                      |       | 309,278            |       | 414,074               |       |
| Less-accumulated depletion, depreciation, amortization, accretion and  asset impairment                |       | (42,347,333        | )          | (41,204,821           | )          |
| Net oil and gas properties                                                                             |       | 57,419,890         |       | 58,386,427            |       |
| Other property and equipment, net of accumulated depreciation of  $198,204 in 2008 of $176,458 in 2007 |       | 299,043            |       | 312,017               |       |
| Restricted Investments                                                                                 |       | 258,272            |       | 255,068               |       |
| **Total Assets**                                                                                       |       | $                  | 69,898,336 |                  | $          | 74,331,321 |   |
|                                                                                                   |       |               |       |                  |       |
| **LIABILITIES AND STOCKHOLDERS’  EQUITY**                                                         | ** ** | ** **         | ** ** | ** **            | ** ** |
| Current Liabilities:                                                                                   |       |               |       |                  |       |
| Accounts payable and accrued liabilities                                                               |       | $                  | 1,975,800  |                  | $          | 5,163,457 |   |
|                                                                                                   |       |               |       |                  |       |
| Noncurrent Liabilities:                                                                                |       |               |       |                  |       |
| Asset retirement obligation                                                                            |       | 742,396            |       | 874,498               |       |
| Total Liabilities                                                                                      |       | 2,718,196          |       | 6,037,955             |       |
|                                                                                                   |       |               |       |                  |       |
| Commitments and Contingenicies - Note 5                                                                |       |               |       |                  |       |
| Stockholders’ Equity:                                                                             |       |               |       |                  |       |
| Common stock, no par value; unlimited authorized                                                       |       |               |       |                  |       |
| Issued: 87,992,931 shares in 2008 and 87,992,931 shares in 2007                                        |       |               |       |                  |       |
| Contributed surplus                                                                                    |       | 116,613,733        |       | 115,094,923           |       |
| Accumulated deficit                                                                                    |       | (49,433,593        | )          | (46,801,557           | )          |
| Total Stockholders’ Equity                                                                        |       | 67,180,140         |       | 68,293,366            |       |
| **Total Liabilities and Stockholders’ Equity**                                                    |       | $                  | 69,898,336 |                  | $          | 74,331,321 |   |

 

SEE ACCOMPANYING NOTES

 

2

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**KODIAKOIL & GAS CORP.**

**CONDENDSED CONSOLIDATED STATEMENTS OFOPERATIONS**

**(UNAUDITED)**

 
| ** **                                                          | ** ** | **Three months ended March 31,** | ** ** |
|---------------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                          | ** ** | **2008**                                             | ** ** | **2007** | ** ** |
|                                                                |       |                                                 |       |   |   |
| Revenues:                                                           |       |                                                 |       |   |   |
| Gas production                                                      |       | $                                                    | 465,865    |   | $ | 299,498 |   |
| Oil production                                                      |       | 1,412,306                                            |       | 1,277,319 |   |
| Interest                                                            |       | 83,366                                               |       | 563,710 |   |
| Total revenue                                                       |       | 1,961,537                                            |       | 2,140,527 |   |
|                                                                |       |                                                 |       |   |   |
| Cost and expenses:                                                  |       |                                                 |       |   |   |
| Oil and gas production                                              |       | 982,951                                              |       | 390,775 |   |
| Depletion, depreciation, amortization and accretion                 |       | 1,097,299                                            |       | 1,039,246 |   |
| Asset impairment                                                    |       | —                                               |       | 14,000,000 |   |
| General and administrative                                          |       | 2,495,042                                            |       | 1,262,960 |   |
| Loss/(gain) on currency exchange                                    |       | 18,281                                               |       | (97,621 | ) |
|                                                                |       |                                                 |       |   |   |
| Total costs and expenses                                            |       | 4,593,573                                            |       | 16,595,360 |   |
|                                                                |       |                                                 |       |   |   |
| Net loss                                                            |       | $                                                    | (2,632,036 | ) | $ | (14,454,833 | ) |
|                                                                |       |                                                 |       |   |   |
| Basic & diluted weighted-average common shares outstanding |       | 87,992,931                                           |       | 87,549,815 |   |
|                                                                |       |                                                 |       |   |   |
| Basic & diluted net loss per common share                  |       | $                                                    | (0.03      | ) | $ | (0.17 | ) |

 

SEEACCOMPANYING NOTES

 

3

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**KODIAK OIL & GASCORP.**

**CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS**

**(UNAUDITED)**

 
| ** **                                                                                | ** ** | **Three Months Ended March 31,** | ** ** |
|-------------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                                                | ** ** | **2008**                                             | ** ** | **2007** | ** ** |
|                                                                                      |       |                                                 |       |   |   |
| **Cash flows from operating activities:**                                                 |       |                                                 |       |   |   |
| Net loss                                                                                  |       | $                                                    | (2,632,036 | ) | $ | (14,454,833 | ) |
| Reconciliation of net loss to net cash (used in) operating activities:                    |       |                                                 |       |   |   |
| Depletion, depreciation, amortization and accretion                                       |       | 1,097,299                                            |       | 1,039,246 |   |
| Asset impairment                                                                          |       | —                                               |       | 14,000,000 |   |
| Stock based compensation                                                                  |       | 1,518,810                                            |       | 275,580 |   |
| Changes in currrent assets and liabilites:                                                |       |                                                 |       |   |   |
| Accounts receivable-trade                                                                 |       | 274,800                                              |       | 520,389 |   |
| Accounts receivable-accrued sales revenue                                                 |       | (9,958                                               | )          | (99,852 | ) |
| Prepaid expenses and other                                                                |       | 60,350                                               |       | 38,983 |   |
| Accounts payable and accrued liabilities                                                  |       | (2,738,207                                           | )          | (4,415,048 | ) |
| **Net cash (used in) operating activities**                                               |       | (2,428,942                                           | )          | (3,095,535 | ) |
|                                                                                      |       |                                                 |       |   |   |
| Cash flows from investing activities:                                                     |       |                                                 |       |   |   |
| Oil and gas properties                                                                    |       | (3,128,461                                           | )          | (13,341,387 | ) |
| Sale of oil and gas properties                                                            |       | 2,437,892                                            |       | — |   |
| Equipment                                                                                 |       | 11,416                                               |       | (26,840 | ) |
| Restricted investment                                                                     |       | (3,204                                               | )          | — |   |
|                                                                                      |       |                                                 |       |   |   |
| **Net cash (used in) investing activities**                                               |       | (682,357                                             | )          | (13,368,227 | ) |
|                                                                                      |       |                                                 |       |   |   |
| Cash flows from financing activity:                                                       |       |                                                 |       |   |   |
| Proceeds from the issuance of shares                                                      |       | —                                               |       | 27,000 |   |
| **Net cash provided by financing activities**                                             |       | —                                               |       | 27,000 |   |
| Net change in cash and cash equivalents                                                   |       | (3,111,299                                           | )          | (16,436,762 | ) |
|                                                                                      |       |                                                 |       |   |   |
| Cash and cash equivalents at beginning of the period                                      |       | 13,015,318                                           |       | 58,469,263 |   |
|                                                                                      |       |                                                 |       |   |   |
| **Cash and cash equivalents at end of the period**                                        |       | $                                                    | 9,904,019  |   | $ | 42,032,501 |   |
|                                                                                      |       |                                                 |       |   |   |
| **Supplemental cash flow information**                                                    |       |                                                 |       |   |   |
| Oil & gas property accrual included in Accounts payable and  accrued liabilities |       | $                                                    | 1,095,418  |   | $ | 1,362,000 |   |
|                                                                                      |       |                                                 |       |   |   |
| Asset retirement obligation                                                               |       | $                                                    | (65,143    | ) | $ | 33,675 |   |

 

SEE ACCOMPANYING NOTES

 

4

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**KODIAK OIL & GAS CORP.**

NOTES TO CONSOLIDATEDFINANCIAL STATEMENTS

 

**Note1 - Organization**

** **

*Descriptionof Operations*

* *

Kodiak Oil & Gas Corp. and itssubsidiary (“Kodiak” or the “Company”) is a public company listed for tradingon the American Stock Exchange (AMEX) and whose corporate headquarters arelocated in Denver, Colorado, USA.  TheCompany is an independent energy company engaged in the exploration,exploitation, development, acquisition and production of natural gas and crudeoil entirely in the western United States.

 

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

 

**Note2 – Basis of Presentation and Significant Accounting Policies**

** **

*Basisof Presentation*

* *

The condensed consolidated financial statements include the accounts ofthe Company and its wholly-owned subsidiary, Kodiak Oil & Gas (USA)Inc.  All significant inter-companybalances and transactions have been eliminated. The majority of the Corporation’s business is transacted in US dollarsand, accordingly, the financial statements are expressed in US dollars.  The accompanying unaudited condensed consolidated financial statements have beenprepared in accordance with U.S. generally accepted accounting principles for interim financial information. Accordingly,they do not include all of the information and footnotes required by U. S.generally accepted accounting principles for complete financial statements. Inthe opinion of management, the condensed consolidated financial statements contain all adjustments (consisting ofnormal recurring adjustments) considered necessary for a fair presentation ofthe Company’s results for the periods presented. These unaudited condensedconsolidated financial statementsshould be read in conjunction with the Company’s audited consolidated financialstatements included in the Annual Report on Form 10-K for the fiscal yearended December 31, 2007. Operating results for the periods presented arenot necessarily indicative of the results that may be expected for the fullyear.  Certain amounts in the 2007unaudited condensed consolidatedfinancial statements have been reclassified to conform to the 2008 unauditedconsolidated financial statement presentation; such reclassifications had noeffect on the 2007 net loss.

 

*Useof Estimates in the Preparation of Financial Statements*

* *

The preparation of the financial statements in conformity withgenerally accepted accounting principles requires management to make estimatesand assumptions that affect the reported amounts of oil and gas reserves,assets and liabilities and disclosure of contingent assets and liabilities atthe date of the financial statements and the reported amounts of revenues andexpenses during the reporting period. The Company bases its estimates on historical experience and on variousother assumptions it believes to be reasonable under the circumstances.  Although actual results may differ from theseestimates under different assumptions or conditions, the Company believes thatits estimates are reasonable.

 

5

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* *

*Cashand Cash Equivalents*

* *

Cash and cash equivalents consist of allhighly liquid investments that are readily convertible to cash and havematurities of three months or less when purchased.  The carrying value of cash and cashequivalents approximates fair value due to the short-term nature of theseinstruments.

 

*RestrictedInvestment*

* *

The restricted investment balance as of March 31, 2008, iscomprised of: (a) $188,475 certificate of deposit to collateralize asurety bond to provide for state bonding requirements for plugging andabandonment liabilities; and (b) $69,797 certificate of deposit tocollateralize the costs of office improvements that will be released over thefour year remaining term of the lease at $17,450 per year.

 

*Concentration of Credit Risk*

* *

The Company’s cash equivalents and short-terminvestments are exposed to concentrations of credit risk.  The Company manages and controls this risk byinvesting these funds with major financial institutions.  The Company may at times have balances inexcess of the federally insured limits.

 

The Company’s receivables are comprised ofoil and gas revenue receivables and joint interest billings receivable.  The amounts are due from a limited number ofentities.  Therefore, the collectabilityis dependent upon the general economic conditions of the few purchasers andjoint interest owners.  The receivablesare not collateralized.  However, to datethe Company has had minimal bad debts.

 

*Oiland Gas Producing Activities*

* *

The Company follows the full cost method ofaccounting for oil and gas operations whereby all costs related to theexploration and development of oil and gas properties are initially capitalizedinto a single cost center (“full cost pool”). Such costs include land acquisition costs, geological and geophysicalexpenses, carrying charges on non-producing properties, and costs of drillingdirectly related to acquisition and exploration activities.  Proceeds from property sales are generallycredited to the full cost pool, with no gain or loss recognized, unless such asale would significantly alter the relationship between capitalized costs andthe proved reserves attributable to these costs.  A significant alteration would typicallyinvolve a sale of 25% or more of the proved reserves related to a single fullcosts pool.

 

Capitalized costs, together with the costs ofproduction equipment, are depleted and amortized on the unit-of-productionmethod based on the estimated gross proved reserves as determined by theCompany’s engineers and audited annually by independent petroleumengineers.  The costs of unprovedproperties are withheld from the depletion base until such time as they areeither developed or abandoned.  Whenproved reserves are assigned or the property is considered to be impaired, thecost of the property or the amount of the impairment is added to costs subjectto depletion calculations.

 

Estimated reserve quantities and future net cash flows have the mostsignificant impact on the Company because these reserve estimates are used inproviding a measure of the Company’s overall value.  These estimates are also used in thequarterly calculations of depletion, depreciation and impairment of the Company’sproved properties.

 

6

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Estimating accumulations of gas and oil iscomplex and is not exact because of the numerous uncertainties inherent in theprocess.  The process relies oninterpretations of available geological, geophysical, engineering andproduction data. The extent, quality and reliability of this technical data canvary. The process also requires certain economic assumptions, some of which aremandated by the Securities and Exchange Commission (the “SEC”), such as gas andoil prices, drilling and operating expenses, capital expenditures, taxes andavailability of funds. The accuracy of a reserve estimate is a function of thequality and quantity of available data; the interpretation of that data; theaccuracy of various mandated economic assumptions; and the judgment of thepersons preparing the estimate.

 

 Theoptimal method of determining proved reserve estimates is based upon a declineanalysis method, which consists of extrapolating future reservoir pressure andproduction from historical pressure decline and production data. The accuracyof the decline analysis method generally increases with the length of theproduction history. Most of the Company’s wells have been producing for aperiod 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 analogyto the production  history of wells ofours 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. Asthe Company’s wells are produced over time and more data is available, theestimated proved reserves will be re-determined at least on an annual basis andmay be adjusted based on that data.

 

Under the full cost method of accounting,capitalized oil and gas property costs less accumulated depletion and net ofdeferred income taxes may not exceed an amount equal to the present value,discounted at 10%, of estimated future net revenues from proved oil and gasreserves plus the cost, or estimated fair value, if lower of unprovedproperties.  Should capitalized costsexceed this ceiling, an impairment is recognized.  The present value of estimated future netrevenues is computed by applying current prices of oil and gas to estimatedfuture production of proved oil and gas reserves as of period-end, less estimatedfuture expenditures to be incurred in developing and producing the provedreserves assuming the continuation of existing economic conditions.

 

Primarily as the result of the Company’s inability to establishproduction and qualified reserves in its deep Vermillion Basin project, lownatural gas prices in Wyoming, and the impairment of certain undevelopedproperties in Wyoming and North Dakota, the Company recorded an impairmentexpense of $34.0 million in 2007 including $14.0 million in the first quarterof 2007.

 

*Wellsin Progress*

* *

Wells in progress at March 31, 2008 and December 31,2007, represent the costs associated with the drilling of wells inWyoming.  Since the wells have notreached total depth or been completed as of period end they were classified aswells in progress and were withheld from the depletion calculation and theceiling test.  The costs for these wellswill be transferred to proved property when the wells reach total depth and arecased and will become subject to depletion and the ceiling test calculation infuture periods.

 

7

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* *

*Impairmentof Long-lived Assets*

* *

*TheCompany’s unproved properties are evaluated quarterly for the possibility ofpotential impairment.  In the threemonths ended March 31, 2008, the Company did not recognize any impairmentlosses. *As of March 31, 2007, theCompany’s full cost pool exceeded the ceiling limitation based on oil and gasprices of $55.12 per barrel and $4.16 per mcf. Subsequent commodity price increases were not sufficient to eliminatethe need for the impairment and therefore, impairment expense of $14,000,000was recorded during the quarter ended March 31, 2007.

* *

*OtherProperty and Equipment*

* *

Other property and equipment such as officefurniture and equipment, vehicles, and computer hardware and software arerecorded at cost.  Costs of renewals andimprovements that substantially extend the useful lives of the assets arecapitalized.  Maintenance and repaircosts are expensed when incurred. Depreciation is recorded using the straight-line method over theestimated useful lives of three years for computer equipment, and five yearsfor office equipment and vehicles.  Whenother property and equipment is sold or retired, the capitalized costs andrelated accumulated depreciation are removed from the accounts.

 

*FairValue of Financial Instruments*

* *

The Company’s financial instruments,including cash and cash equivalents, accounts receivable and accounts payable,are carried at cost, which approximates fair value due to the short-termmaturity of these instruments.

 

*RevenueRecognition*

* *

*TheCompany records revenues from the sales of natural gas and crude oil when theyare produced and sold.  The Company mayhave an interest with other producers in certain properties, in which case theCompany uses the sales method to account for gas imbalances.  Under this method, revenue is recorded on thebasis of gas actually sold by the Company. In addition, the Company records revenue for its share of gas sold byother owners that cannot be volumetrically balanced in the future due toinsufficient remaining reserves.  TheCompany also reduces revenue for other owners’ gas sold by the Company thatcannot be volumetrically balanced in the future due to insufficient remainingreserves.  The Company’s over and underproduced gas balancing positions are considered in the Company’s proved oil andgas revenues.  Gas imbalances at March 31,2008, and December 31, 2007 were not significant.*

* *

*AssetRetirement Obligation*

* *

The Company follows SFAS No. 143, “Accountingfor Asset Retirement Obligations,” which requires that the fair value of aliability for an asset retirement obligation be recognized in the period inwhich it was incurred if a reasonable estimate of fair value could bemade.  The associated asset retirement costsare capitalized as part of the carrying amount of the long-lived asset.  The increase in carrying value of a propertyassociated with the capitalization of an asset retirement cost is included inproved oil and gas properties in the condensed consolidated balancesheets.  The Company depletes the amountadded to proved oil and gas property costs. The future cash outflows associated with settling the asset retirementobligations that have been accrued in the accompanying balance sheets areexcluded from the ceiling test calculations. The Company also depletes the estimated dismantlement and abandonmentcosts, net of salvage values, associated with future development activitiesthat have not yet been capitalized as asset retirement obligations.  These costs are also included in the ceilingtest calculation.  The asset 

 

8

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retirement liability will beallocated to operating expense by using a systematic and rational method.  As of March 31, 2008, and December 31,2007, the Company has recorded a net asset of $608,838 and $660,986 and arelated liability of $742,396 and $874,498, respectively.  In December 2007, the Company revisedits estimated dismantlement and abandonment costs based upon the actual costsof recently plugged and abandoned wells. The information below reconciles the value of the asset retirementobligation for the periods presented.

 
| ** **                         | ** ** | **For the Three  Months Ended  March 31,** | ** ** | **For the Year Ended  December 31,** | ** ** |
|------------------------------------|------------|----------------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                         | ** ** | **2008**                                                       | ** ** | **2007**                                                 | ** ** |
| Balance  beginning of period       |       | $                                                              | 874,498    |                                                     | $          | 249,695 |   |
| Liabilities  incurred              |       | 0                                                              |       | 60,289                                                   |       |
| Liabilities  settled               |       | (147,252                                                       | )          | (3,021                                                   | )          |
| Revisions  in estimated cash flows |       | 0                                                              |       | 482,544                                                  |       |
| Accretion  expense                 |       | 15,150                                                         |       | 84,991                                                   |       |
| Balance  end of period             |       | $                                                              | 742,396    |                                                     | $          | 874,498 |   |

 

*RecentlyIssued Accounting Pronouncements:*

* *

In September 2006, the Financial AccountingStandards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”)No. 157, “Fair Value Measurements.”  The statement defines fairvalue, establishes a framework for measuring fair value in generally acceptedaccounting principles, and expands disclosures about fair value measurements.In February 2008, the FASB issued Staff Position No. FAS 157-2 whichproposed a one year deferral for the implementation of SFAS 157 fornon-financial assets and liabilities that are recognized or disclosed at fairvalue on a nonrecurring basis (less frequent than annually).

 

On January 1, 2008 we elected to implement thisStatement with the one-year deferral. The adoption of SFAS No. 157 did nothave a material impact on our financial position, results of operations or cashflows. Beginning January 1, 2009, we will adopt the provisions fornonfinancial assets and nonfinancial liabilities that are not required orpermitted to be measured at fair value on a recurring basis. We are in theprocess of evaluating this standard with respect to our effect on nonfinancialassets and liabilities and have not yet determined the impact that it will haveon our financial statements upon full adoption in 2009.

 

SFAS No. 157 (as amended), defines fair value,establishes a framework for measuring fair value, outlines a fair valuehierarchy based on inputs used to measure fair value and enhances disclosurerequirements for fair value measurements.  Fair value is defined as theprice at which an asset could be exchanged in a current transaction betweenknowledgeable, willing parties. A liability’s fair value is defined as theamount that would be paid to transfer the liability to a new obligor, not theamount that would be paid to settle the liability with the creditor. Whereavailable, fair value is based on observable market prices or parameters orderived from such prices or parameters. Where observable prices or inputs arenot available, use of unobservable prices or inputs are used to estimate thecurrent fair value, often using an internal valuation model. These valuationtechniques involve some level of management estimation and judgment, the degreeof which is dependent on the item being valued.

 

9

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Beginning January 1, 2008, assets and liabilitiesrecorded at fair value in the consolidated balance sheets are categorized basedupon the level of judgment associated with the inputs used to measure theirfair value. Hierarchical levels—defined by SFAS 157 and directly related to theamount of subjectivity associated with the inputs to fair valuation of theseassets and liabilities—are as follows:

 

·                  LevelI—Inputs are unadjusted, quoted prices in active markets for identical assetsor liabilities at the measurement date.

 

·                  LevelII—Inputs (other than quoted prices included in Level I) are either directly orindirectly observable for the asset or liability through correlation withmarket data at the measurement date and for the duration of the instrument’santicipated life.

 

·                  LevelIII—Inputs reflect management’s best estimate of what market participants woulduse in pricing the asset or liability at the measurement date. Consideration isgiven to the risk inherent in the valuation technique and the risk inherent inthe inputs to the model.

 

Our asset retirement obligation is measuredusing primarily Level III inputs. The significant unobservable inputs to thisfair value measurement include estimates of plugging and abandonment costs,inflation rate and well life. The inputs are calculated based on historicaldata as well as current estimated costs.

 

In February 2007, the FASB issued SFAS No. 159,“The Fair Value Option for Financial Assets and Financial Liabilities-Includingan Amendment of FASB Statement No. 115” (“FAS 159”). This Statement allowsan entity the option to elect fair value for the initial and subsequentmeasurement for certain financial instruments and other items that are notcurrently required to be measured at fair value. If a company chooses to recordeligible items at fair value, the company must report unrealized gains andlosses on those items in earnings at each subsequent reporting date.   FAS 159 also prescribes presentation anddisclosure requirements for assets and liabilities that are measured at fairvalue pursuant to this standard. FAS 159 was effective for the Company as of January 1,2008.  The adoption of FAS 159 did nothave a material impact on the Company’s financial position or results ofoperations.

 

In December 2007, theFASB issued SFAS No. 141-R, “Business Combinations” (“FAS 141R”) whichrevised SFAS No. 141, “Business Combinations” (“FAS 141”). This pronouncementis effective for the Company’s financial statements issued after January 1,2009. Under FAS 141, organizations utilized the announcement date as themeasurement date for the purchase price of the acquired entity. FAS 141Rrequires measurement at the date the acquirer obtains control of the acquiree,generally referred to as the acquisition date. FAS 141R will have a significantimpact on the accounting for transaction costs, restructuring costs as well asthe initial recognition of contingent assets and liabilities assumed during abusiness combination. Under FAS 141R, adjustments to the acquired entity’sdeferred tax assets and uncertain tax position balances occurring outside themeasurement period are recorded as a component of the income tax expense,rather than goodwill. As the provisions of FAS 141R are applied prospectively,the impact to the Company cannot be determined until the transactions occur. interimperiods within those fiscal years, beginning on or after December 15,2008.  Earlier adoption isprohibited.  The Company does not expectthat the adoption of FAS 160 will have a material effect on its financialposition or results of operations.

 

In December 2007, theFASB issued SFAS No. 160, “Noncontrolling Interests in ConsolidatedFinancial Statements, an amendment of ARB No. 51” (“FAS 160”).  This Statement establishes accounting andreporting standards for the noncontrolling interest in a subsidiary and for thedeconsolidation of a subsidiary. FAS 160 is effective for fiscal years, and 

 

10

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interim periods within thosefiscal years, beginning on or after December 15, 2008.  Earlier adoption is prohibited.  The Company does not expect that the adoptionof FAS 160 will have a material effect on its financial position or results ofoperations.

 

**Note3 – Wells in Progress**

** **

The following table reflects the net changesin capitalized additions to wells in progress during the three months ended March 31,2008, and the year ended December 31, 2007, and does not include amountsthat were capitalized and reclassified to producing wells in the same period.

 
| ** **                                                                                                              | ** ** | **For the Three  Months Ended  March 31,** | ** ** | **For the Year  Ended  December 31,** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                                                                              | ** ** | **2008**                                                       | ** ** | **2007**                                             | ** ** |
|                                                                                                                    |       |                                                           |       |                                                 |       |
| Beginning  balance                                                                                                      |       | $                                                              | 414,074    |                                                 | $          | 7,700,415 |   |
| Additions  to capital wells in progress costs pending the determination of proved  reserves                             |       | 44,714                                                         |       | 414,074                                              |       |
| Reclassifications  to wells, facilities, and equipment based on the determination of proved  reserves to full cost pool |       | (149,510                                                       | )          | (7,700,415                                           | )          |
|                                                                                                                    |       |                                                           |       |                                                 |       |
| Ending  balance                                                                                                         |       | $                                                              | 309,278    |                                                 | $          | 414,074 |   |

 

**Note4 – Stock-based Compensation Plan**

** **

In 2007 the Company adopted the 2007 StockIncentive Plan (the “2007 Plan”), which replaced the Incentive Share OptionPlan (the “Pre-existing Plan”).  The 2007Plan authorizes the Company to issue stock options, stock appreciation rights(SARs), restricted stock and restricted stock units, performance awards, stockor property, stock awards and other stock-based awards may be granted to anyemployee, consultant, independent contractor, director or officer of theCompany.  A total of 8,000,000 shares ofcommon stock may be issued under the 2007 Plan, which includes shares issuableunder the Pre-existing Plan pursuant to options outstanding as of the effectivedate of the 2007 Plan.  No more than8,000,000 shares may be used for stock issued pursuant to incentive stockoptions and the number of shares available for granting restricted stock andrestricted stock units shall not exceed 1,000,000, subject to adjustment asdefined in the 2007 Plan.  The Companygranted 965,000 stock options in the three-month period ended March 31,2008.

 

Compensation expense charged against incomefor all stock-based awards during the three months ended March 31, 2008,and March 31, 2007, was $1,518,810 and $275,580, respectively.  This increase is primarily due to additionalstock-based awards granted since March 31, 2007, as well as the true up ofthe cumulative expense as a result of comparing the assumed forfeiture rate toactual forfeitures.

 

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

 

11

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| ** **                                                                                    | ** ** | **For the Periods Ended** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|------------------------------------------|------------|
| ** **                                                                                    | ** ** | **March 31, 2008**             | ** ** | **December 31, 2007** | ** ** |
|                                                                                          |       |                                     |       |   |   |
| Risk  free rates                                                                              |       | 4.47-4.53                                | %          | 4.46-5.89 | % |
| Dividend  yield                                                                               |       | 0                                        | %          | 0 | % |
| Expected  volatility                                                                          |       | 54.37-63.02                              | %          | 53.46-56.26 | % |
| Weighted  average expected stock option life                                                  |       | 3.67 yrs                                 |       | 5.86 yrs |   |
|                                                                                          |       |                                     |       |   |   |
| The  fair value at the date of grant for stock options granted in each period is  as follows: |       |                                     |       |   |   |
| Weighted  average fair value per option                                                       |       | $                                        | 1.00       |   | $ | 3.33 |   |
| Total  options granted                                                                        |       | 965,000                                  |       | 2,044,000 |   |
| Total  fair value of options granted                                                          |       | $                                        | 962,962    |   | $ | 6,800,579 |   |

 

 

A summary of the stockoptions outstanding as of March 31, 2008, is as follows:

 
| ** **                                    | ** ** | ** **          | ** ** | **Weighted** | ** ** |
|-----------------------------------------------|------------|---------------------|------------|--------------|------------|
| ** **                                    | ** ** | ** **          | ** ** | **Average**  | ** ** |
| ** **                                    | ** ** | **Number**          | ** ** | **Exercise** | ** ** |
| ** **                                    | ** ** | **of Options** | ** ** | **Price**    | ** ** |
| Balance outstanding at December 31, 2007 |       | 6,112,000           |       | $            | 3.25       |   |
|                                          |       |                |       |         |       |
| Granted                                       |       | 965,000             |       | $            | 2.20       |   |
| Exercised                                     |       | 0                   |       | $            | 0.00       |   |
|                                          |       |                |       |         |       |
| Balance outstanding at March 31, 2008    |       | 7,077,000           |       | $            | 3.11       |   |
|                                          |       |                |       |         |       |
| Options exercisable at March 31, 2008    |       | 4,061,331           |       | $            | 2.28       |   |

 

 

At March 31, 2008,stock options outstanding are as follows:

 

| **Exercise Price** | ** ** | **Number of   Shares** | ** ** | **Weighted   Average   Remaining   Contractual   Life (Years)** | ** ** |
|-------------------------|------------|----------------------------------|------------|------------------------------------------------------------------------------------------|------------|
| $0.45-$1.00             |       | 1,338,000                        |       | 1.0                                                                                      | ** ** |
| $1.01-$2.00             |       | 875,000                          |       | 2.5                                                                                      | ** ** |
| $2.01-$3.00             |       | 1,015,000                        |       | 5.9                                                                                      |       |
| $3.01-$4.00             |       | 1,844,000                        |       | 4.2                                                                                      |       |
| $4.01-$5.00             |       | 285,000                          |       | 3.2                                                                                      |       |
| $5.01-$6.26             |       | 1,720,000                        |       | 9.1                                                                                      |       |
|                    |       | 7,077,000                        |       | 4.8                                                                                      |       |

 

12

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The aggregate intrinsic value of both outstanding and vested options asof March 31, 2008, was $1,996,510, based on the Company’s March 31,2008, closing common stock price of $1.67. This amount would have been received by the option holders had all optionholders exercised their options as of that date.  The total grant date fair value of the sharesvested during the three months ended March 31, 2008 was $414,600.  As of March 31, 2008, there was$5,201,895 of total unrecognized compensation cost related to unamortizedoptions.  That cost is expected to berecognized over a period of approximately three years.

 

As of March 31, 2008, there were 61,000 unvested shares ofrestricted stock grants with a weighted-average grant date fair value of $4.91per share.   Total unrecognizedcompensation cost of $206,657 related to non-vested restricted stock isexpected to be recognized over a three-year period.  The Company recognizes compensation cost overthe requisite service period for the entire award.  The fair value of restricted stock grants isbased on the stock price on the grant date and the Company assumes no annualforfeiture rate.

 

**Note5 - Commitments and Contingencies**

** **

The Company leases office facilities under an operating lease agreementthat expires on June 30, 2012.  Rentexpense was $78,737 and $21,555 for the three month periods ended March 31,2008 and 2007, respectively.

 

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

 

| **Years ending December 31,** | ** ** | ** ** | ** ** |
|----------------------------------------------|------------|------------|------------|
| 2008                                         |       | $          | 194,182    |   |
| 2009                                         |       | 264,929    |       |
| 2010                                         |       | 276,347    |       |
| 2011                                         |       | 289,257    |       |
| 2012                                         |       | 147,080    |       |
| Total                                        |       | $          | 1,171,796  |   |

 

As is customary in the oil and gas industry,the Company may at times have commitments in place to reserve or earn certainacreage positions or wells.  If theCompany does not pay such commitments, the acreage positions or wells may belost.

 

**Note6 – Differences Between Canadian and United States Accounting Principles**

** **

These financial statements have been preparedin accordance with accounting principles generally accepted in the UnitedStates of America which differ in certain respects with those principles andpractices that the Company would have followed had its financial statementsbeen prepared in accordance with accounting principles and practices generallyaccepted in Canada.  Management does notbelieve the financial statements would vary materially had they been preparedin accordance with Canadian GAAP or that any recently issued, not yeteffective, Canadian accounting standards if currently adopted could have amaterial effect on the accompanying financial statements.

 

13

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# **ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION AND RESULTS OF OPERATIONS**

# ** **

**Forward-LookingStatements**

 

This Quarterly Report includes certain statements thatmay be deemed to be “forward-looking statements” within the meaning of Section 27Aof the Securities Act of 1933, as amended, and Section 21E of theSecurities Exchange Act of 1934, as amended. All statements included in thisQuarterly Report, other than statements of historical facts, address mattersthat the Company reasonably expects, believes or anticipates will or may occurin the future. Forward-looking statements may relate to, among other things:

 

·                  theCompany’s future financial position, including working capital and anticipatedcash flow;

 

·                  therisks of the oil and gas industry, such as operational risks in exploring for,developing and producing crude oil and natural gas;

 

·                  marketdemand;

 

·                  risksand uncertainties involving geology of oil and gas deposits;

 

·                  theuncertainty of reserve estimates and reserves life;

 

·                  theuncertainty of estimates and projections relating to production, costs andexpenses;

 

·                  potentialdelays or changes in plans with respect to exploration or development projectsor capital expenditures;

 

·                  fluctuationsin oil and gas prices, foreign currency exchange rates and interest rates;

 

·                  health,safety and environmental risks;

 

·                  uncertaintiesas to the availability and cost of financing; and

 

·                  thepossibility that government policies or laws may change or governmentalapprovals may be delayed or withheld.

 

Other sections of the Quarterly Report may include additional factorsthat could adversely affect our business and financial performance.  Moreover, we operate in a very competitiveand rapidly changing environment.  Newrisk factors emerge from time to time and it is not possible for our managementto predict all risk factors, nor can we assess the impact of all factors on ourbusiness or the extent to which any factor, or combination of factors, maycause actual results to differ materially from those contained in anyforward-looking statements.

 

Our forward-looking statements contained in this Quarterly Report aremade as of the respective dates set forth in this Quarterly Report.  Such forward-looking statements are based onthe beliefs, expectations and opinions of management as of the date thestatements are made.  We do not intend toupdate these forward-looking statements, except as otherwise required bylaw.  For the reasons set forth above,investors should not place undue reliance on forward-looking statements.

 

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**Overview**

 

KodiakOil & Gas Corp. is an independent energy company focused on theexploration, exploitation, acquisition and production of natural gas and crudeoil in the United States.  Our oil andnatural gas reserves and operations are primarily concentrated in two RockyMountain basins – the Green River Basin of Wyoming and Colorado and theWilliston Basin of North Dakota and Montana. Kodiak’s corporate strategy is to internally identify prospects, acquirelands encompassing those prospects and evaluate those prospects usingsubsurface geology and geophysical data and exploratory drilling.  Using this strategy, we have developed an oiland natural gas portfolio of proved reserves, as well as conventional andunconventional prospects, that we have the opportunity to explore, drill anddevelop.

 

**First Quarter 2008 Highlights**

 

Kodiak’s results of operations and financial condition aresignificantly affected by the success of our exploration and land leasingactivity, the resulting production and reserves, oil and natural gas commodityprices, and the costs related to operating our properties.  In the first quarter of 2008, our oil and gasrevenue increased by 16% from the first quarter of 2007.  This increase is largely the result of higherrealized prices received for both our crude oil and natural gas productionoffset by a decrease in our crude oil production.  The decrease in our crude oil production wasa result of oil producing wells that were shut in for repair and workoverprocedures.  Total costs and expensesdecreased to $4.6 million in the first quarter of 2008 from $16.6 million inthe first quarter of 2007 largely due to an asset impairment in 2007 of $14.0million related to the full cost ceiling test. Costs and expenses in the first quarter of 2007 were impacted by higheroil and gas production costs and general and administrative expenses.  Included in the oil and gas production costsfor the first quarter of 2007 was approximately $467,000 of expenses related torepair work on a producing well.  Theincrease in general and administrative expenses included an increase in thenon-cash charge for stock based compensation of $1.2 million.  This increase is due to additional optionsand restricted stock issued since March 31, 2007, and a change in theforfeiture rate assumed for future vested options.

 

In the first quarter of 2008, we have continued to add to our acreageposition in the Bakken play on the Fort Berthold Indian Reservation throughcontinual leasing negotiations and final approval from the Bureau of IndianAffairs.  We believe that we have madesignificant progress in procuring the necessary permit to drill our first wellon the Reservation.  Whilethis process took longer than expected, the absence ofestablished protocols meant that we and the applicable agencies wererequired to work cooperatively to establish procedures forthe industry andregulatory agencies to follow as oil and gas development progresses.  Additionally, we have continued to evaluateour exploration activities related to our prospective land positions byinterpreting additional geological and geophysical data in both the WillistonBasin and Vermillion Basin properties. We expect that completed 3-D seismicstudies, acquired in both Basins in 2007, will prove useful well into thefuture as we seek to expand our production base through additional drilling.

 

In January 2008,we entered into the Devon Agreement with Devon Energy Production Company, L.P.,a wholly owned subsidiary of Devon Energy Corp (“Devon”) under which Devonearned an interest in our leasehold interests in the Vermillion Basin inexchange for, among other things, drilling up to three wells at Devon’s solecost and risk by November 15, 2009.

 

15

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As part of the Devon Agreement, we and Devon have set forth terms andconditions that create an Area of Mutual Interest (AMI) for the exploration,leasing, and development of certain of our Vermillion Basin properties.  Upon completion of each of the three wells,we will have a 50% working interest in each well, proportionately reduced inthe event of third-party interest.  Bydrilling the three wells, Devon will earn, among other considerations, 50% ofour leasehold interest to all depths within the AMI, excluding any leaseholdalready jointly held by and between us and Devon and any existing Kodiakwellbores.  Through reimbursement ofcosts totaling approximately $1.2 million, Devon also earned ownership in twoexisting wells, the Horseshoe Basin 5-3 and Whiskey Canyon Unit #3, so thatDevon will own the same interest as Kodiak in these wells.  Underthe terms of the agreement, Devon will serve as operator but both parties willcollaborate by each providing technical input and drilling and completionexpertise in order to best develop the AMI properties. With this agreement,we believe that development will continue to move ahead in this play and ourcapital requirements will be limited in the short-term.

 

Kodiak ended the first quarter of 2008 with cash and cash equivalentsof $9.9 million down from $13.0 million at year-end 2007.  Total working capital was also $9.9 millionat March 31, 2008, as compared to $10.2 million at December 31,2007.  Cash flow used in operatingactivities for the first quarter of 2008 was $2.4 million which was largely theresult of a $2.7 million reduction in current assets and liabilities.  Cash used as capital expenditures for our oiland gas activities totalled $3.1 million for the first quarter of 2008 and wasoffset by $2.4 million in proceeds from sales of oil and gas properties.  Our estimated capital expenditures for theremainder of 2008 of $12.4 million is expected to be funded by existing workingcapital and other sources of capital including debt or equity financings or byentering into additional joint venture agreements.  We can give no assurance that these financingsources will be available under acceptable terms or at all.

 

**Liquidity and Capital Resources**

 

Due to our active oil and natural gas exploration program, we haveexperienced, and expect to continue to experience, substantial working capitalrequirements.  As a result of the DevonAgreement, we expect to maintain a high level of activity in the VermillionBasin, without the need for Kodiak to undertake significant capital expendituresin the short-term.  Based on our currentexploration program and depending on the success in this play, we anticipateadditional capital requirements by late 2008 and into 2009.  By reducing the immediate capitalrequirements of the continuing Vermillion Basin exploration, we intend to allocateour existing capital to the Bakken play on the Fort Berthold Indian Reservationin North Dakota.  Through an explorationagreement with a joint venture partner in this play, we have limited ourinitial capital exposure to an approximate 50% working interest in each of theearly wells.  On other acreage in thesame play, we have a higher working interest and may seek to reduce thisownership through further joint ventures which would provide additional capitaland reduce Kodiak’s total requirements.

 

In the first quarter of 2008, we incurred capital expenditures ofapproximately $176,000, net of proceeds from property divestitures and theDevon transaction and including accruals. As of March 31, 2008, our working capital is $9.9 million and wecontinue to have no long-term debt.  Ourcapital expenditure budget for 2008 is unchanged at a total of $12.6 millionwhich is also net of proceeds from limited divestitures and joint venturearrangements that have occurred or are planned. In addition to this $12.6million budget, we have other prospects that are in the early stages ofexploration.  Further spending on theseprospects is contingent on the success of 

 

16

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the currently budgeted expenditures. As our anticipated funds fromoperations are expected to provide only a limited amount of additional workingcapital, we believe that it is likely that we will need to obtain additionalsources of capital to fund further growth and development, theamount and timing of which will depend on the success and timing of ourexploration activities.  We anticipatethat we would seek to obtain additional funding either by means of debt orequity financings or by entering into additional joint venture agreements, theavailability of which there can be no assurance.

 

Our ability to fund our operations in future periods will depend uponour future operating performance, and more broadly, on the availability ofequity and debt financing, which will be affected by prevailing economicconditions in our industry and financial, business and other factors, some ofwhich are beyond our control.  We cannotbe certain that additional funding will be available on acceptable terms, or atall.  If we are unable to raiseadditional capital when required or on acceptable terms, we may have tosignificantly delay, scale back or discontinue our drilling or explorationprogram, seek to enter into additional joint venture arrangements with thirdparties, or seek to sell one or more of our properties.

 

**Oil and Gas Properties**

 

Asof March 31, 2008, we had several hundred lease agreements representingapproximately 148,481 gross and 91,306 net acres primarily in the Green Riverand Williston Basins.

 

Asof March 31, 2008, we had acquired 38,686 gross acres and 28,957 net acresin the Bakken oil play in Dunn County, North Dakota.  An additional estimated 8,800 net acres havebeen leased and are in the approval process with the Bureau of Indian Affairs (“BIA”).  We cannot be assured that we will receivetitle to these lands until final approval is received.  The majority of our lands in this prospectarea are administered by the BIA on behalf of the individual members of theThree Affiliated Tribes Fort Berthold Indian Reservation.  Typically these lands are acquired through aprivate negotiation with the individual land owners or the Three AffiliatedTribes and have a primary lease term of five years.  The land owner typically retains an 18%landowner royalty.  In most cases, theselands require an annual delay rental of $2.50 per net acre.

 

As aresult of the Devon Agreement, our leasehold interests in the Vermillion Basintotal approximately 39,093 gross (14,421 net) acres.  The AMI with Devon will expire after a periodof five years, unless extended by mutual agreement of both parties.  Each party has agreed to a proportionateshare of any interest or lease acquired within the participating area.

 

In January 2008, we completed the sale of 4,784 gross and netacres in an exploratory Mancos Shale gas prospect located in the Sand WashBasin in Moffat County, Colorado for $1.2 million.  We retained a 5% overriding royalty in theseproperties as well as 100% working interest ownership in the remaining 3,770acres.  We believe the remaining acreageis prospective for production from the Mancos Shale and Niobrara Formation at ashallower depth than that divested.

 

Thefollowing table sets forth our gross and net acres of developed and undevelopedoil and natural gas leases as of March 31, 2008.

 

17

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| ** **            | ** ** | **Undeveloped   Acreage(1)** | ** ** | **Developed   Acreage(2)** | ** ** | **Total Acreage** | ** ** |
|-----------------------|------------|-----------------------------------|------------|---------------------------------|------------|------------------------|------------|
| ** **            | ** ** | **Gross**                         | ** ** | **Net**                         | ** ** | **Gross**              | ** ** | **Net** | ** ** | **Gross** | ** ** | **Net** | ** ** |
| **Green River Basin** |       |                              |       |                            |       |                   |       |   |   |   |   |   |   |
| Wyoming(3)            |       | 39,369                            |       | 16,484                          |       | 1,400                  |       | 848 |   | 40,769 |   | 17,332 |   |
| Colorado              |       | 7,847                             |       | 5,129                           |       | —                 |       | — |   | 7,847 |   | 5,129 |   |
| **Williston Basin**   |       |                              |       |                            |       |                   |       |   |   |   |   |   |   |
| Montana               |       | 37,721                            |       | 22,476                          |       | 800                    |       | 400 |   | 38,681 |   | 22,958 |   |
| North  Dakota         |       | 46,735                            |       | 34,364                          |       | 3,040                  |       | 1,800 |   | 49,775 |   | 36,164 |   |
| **Other Basins**      |       |                              |       |                            |       |                   |       |   |   |   |   |   |   |
| Wyoming               |       | 11,409                            |       | 9,723                           |       | —                 |       | — |   | 11,409 |   | 9,723 |   |
|                  |       |                              |       |                            |       |                   |       |   |   |   |   |   |   |
| **Acreage Totals**    | ** ** | **143,081**                       | ** ** | **88,176**                      | ** ** | **5,240**              | ** ** | **3,048** | ** ** | **148,481** | ** ** | **91,306** | ** ** |

 

----

(1) Undeveloped acreage is lease acreage onwhich wells have not been drilled or completed to a point that would permit theproduction of commercial quantities of oil and natural gas regardless ofwhether such acreage includes proved reserves.

(2) Developed acreage is the number of acresthat are allocated or assignable to producing wells or wells capable ofproduction.

(3) Excludes 10,261 gross (6,127 net) acres thatcan be earned pursuant to existing farm-in agreements.

 

**Exploratory Activity**

 

**Operationsin the Williston Basin of Montana and North Dakota**

** **

***Bakken Formation—McKenzie andDunn Counties, North Dakota***

 

We have continued our ongoing acreage acquisition program in DunnCounty, North Dakota where the primary objective is the dolomitic, sandyinterval layered between the two Bakken Shales at an approximate vertical depthof 10,000 feet.  This acreage is in atrend bordered by producing wells drilled by, among others, EOG Resources, Inc.and Whiting Petroleum Corp. to the north and Marathon Oil Corp. andConocoPhillips to the west and south.

 

Subject to obtaining a permit to drill from the Bureau of LandManagement (BLM) and the BIA and obtaining a drilling rig and equipment,drilling activity should commence in the second quarter of 2008.  On April 7, 2008, we received a Findingof No Significant Impact (FONSI) and the necessary approval of theenvironmental assessment (EA) with respect to the Tall Bear #16-15H well onthis prospect.  Upon FONSI approval, theEA is subject to a 30 day comment period that will expire in early May 2008,at which time we would expect both final BIA and BLM approval.  The EA approval is a key step in the drillingpermit process and, while this permit is being processed, Kodiak is preparingto submit additional drilling permits for other wellsites.  The Tall Bear #16-15H is a horizontal welltargeting oil potential in the Bakken shale and is being permitted to aproposed total depth of 15,600 feet.  Wewill operate and currently own an approximate 70% working interest in theproposed drill site and acreage block, but we may seek to reduce our workinginterest to approximate 50%.

 

18

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In early April 2008, we also enteredinto a long-term contract for a new-build rig from a large land-drillingcontractor.  The rig is designed to ourspecifications to optimally drill horizontal Bakken shale wells and otherWilliston Basin formations.  We expectthe rig to be delivered in the third quarter of 2008 and it will be usedexclusively for our Williston Basin operations, including Red River and MissionCanyon prospects.  In order to expediteour Bakken drilling operations on the Tall Bear #16-15H well, we are activelyseeking a one-well window for a sub-contracted rig from a drilling contractoror operator in the area.

 

In the first quarter of 2008, we beganworkover operations on our producing Bakken oil wells in McKenzie County nearthe North Dakota and Montana state line. In this play, we intend to clean out and fracture stimulate one well andre-fracture stimulate two wells.  As partof this program, in the first quarter of 2008, we performed required repairwork on the casing of one well in preparation of the workover operations.  This work to repair the casing was completedand the well is capable of producing pending the workover.  The net cost of approximately $467,000related to the repair work was charged to oil and gas production costs andexpenses in the first quarter of 2008.

 

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

 

Theprimary producing objectives in this prospect area are the Mission Canyon andthe Red River formations at approximate depths of 8,000 feet and 11,000 feet,respectively.  We have recently completedinterpreting an approximate 18 square mile 3-D seismic program over a portionof this acreage.  The Company hasidentified two prospects within its acreage that it intends to drill during2008.  The Company has identified seismicleads on other blocks of its acreage that we expect to drill during 2008.

 

**Operationsin the Green River Basin of Wyoming and Colorado**

** **

***Vermillion Basin Deep – BaxterShale and Frontier and Dakota Sandstone***

 

Our primary leaseholdings in the Green River Basin are located in anarea referred to as the Vermillion Basin. In this geologic region, we believe there is natural gas trapped invarious sands, coals and shales at depths ranging from 2,000 feet to nearly15,000 feet.  The primary target of ourcurrent exploration efforts in this area is the over-pressured Baxter Shale atdepths to approximately 13,000 feet.

 

In late 2007, we completeddrilling operations on the Horseshoe Basin #5-3 well (50% WI, 42% NRI, operatedby Devon) located on the western edge of the prospective producing area.  This well was drilled vertically to a depthof 13,534 feet to evaluate the potential of the Almond and Ericson formations,the Baxter Shale and the Frontier Formation. The well was a significant step out and it is approximately 6 miles fromthe closest producing well.  Followingfracture stimulation of the Baxter shale in November, the initial twenty-fourhour flowback rate was estimated at 3.0 million cubic feet (MMcf) of naturalgas on a 16/64” choke and 3,500 psia of flowing casing pressure.  Subsequently, the well was tested for 48hours through a test separator and stabilized at approximately 2.0 MMcf per daywith 350 barrels of condensate per 

 

19

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day.  Thewell is currently waiting on the completion of a gathering pipeline which isexpected to be in place by mid-summer 2008. Although Kodiak drilled and completed this well, as part of the DevonAgreement, Devon earned an increased ownership in this well and now operatesthe well.

 

Our 2008 exploration efforts in the Vermillion Basin prospect area willlargely be driven by Devon. It is currently expected that the first drillingactivities will be conducted on the western portion of our acreage in theHorseshoe Basin Unit in an effort to extend the reservoir as found in of theHorseshoe Basin #5-3 well.  Drilling isanticipated to commence in the second quarter 2008 and continue into the fallmonths as lease stipulations expire and the locations are accessible.  While drilling plans are still beingfinalized, we anticipate the first well will be a vertical well to evaluateonly the Baxter Shale.  The wells will beengineered to allow re-entry for horizontal drilling applications at a laterdate, if desired.  Concurrently with thedrilling activity we anticipate the acquisition of 3-D seismic covering theHorseshoe Basin Unit to help facilitate a development program in 2009 andbeyond. We have completed the processing and interpretation of approximately 43square miles of 3-D seismic on the northern block of our acreage which includesportions of our Chicken Springs and Chicken Ranch Federal Units, as well asland currently not included in federal units. While no specific drillinglocations have yet been determined, we anticipate that additional wells will bedrilled under the Devon Agreement in this area as a result of the seismicevaluation.

 

**Production, Average Sales Prices, and ProductionCosts**

 

Kodiak’s results of operations and financial condition aresignificantly affected by oil and natural gas commodity prices, which canfluctuate dramatically.  The commodityprices are beyond our control and are difficult to predict. Market pricesreflect worldwide concerns about producer ability to ensure sufficient supplyto meet increasing demand amid a host of uncertainties caused by politicalinstability, a weaker U.S. dollar and crude oil refining constraint.  We receive lower prices for our oil and gasthan what is posted on the New York Mercantile Exchange (NYMEX).  The price differentials received for ourproducts vary from month to month and the Company does not currently havehedges of its commodity sales in place.

 

The Company’s oil and gas sales volumes are adirect result of the success of its exploratory and acquisitionactivities.  Production volumes may varymonthly as various wells are completed or maintained to provide optimal flows.

 

Sales volumes, prices received, andproduction costs are summarized in the following table for the three-monthperiods ending March 31, 2008, and March 31, 2007.  In the first quarter of 2008, we beganpreparations to perform workovers on our producing Bakken oil wells in McKenzieCounty, North Dakota.  Although this workis expected to improve the production capabilities and increase theirrecoverable reserves, while the project is in progress, the wells’ productionwill be negatively impacted.  As part ofthis preparation work, we performed repairs on the casing of one well and thatwell and another were shut in intermittently during the first quarter of 2008.As a result, our oil production for the quarter decreased significantly and theexpenses that were incurred for repair work increased operating expenses by approximately$467,000.  The sales volume andproduction cost metrics shown below reflect the effect of the reducedproduction and increased expenses.

 

20

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| ** **                               | ** ** | **For the Three Months   Ended March 31,** | ** ** |
|------------------------------------------|------------|--------------------------------------------------------------------------|------------|
| ** **                               | ** ** | **2008**                                                                 | ** ** | **2007** | ** ** |
|                                     |       |                                                                     |       |   |   |
| **Sales Volume:**                        |       |                                                                     |       |   |   |
| Gas  (Mcf)                               |       | 66,600                                                                   |       | 45,915 |   |
| Oil  (Bbls)                              |       | 15,848                                                                   |       | 25,266 |   |
|                                     |       |                                                                     |       |   |   |
| **Price:**                               |       |                                                                     |       |   |   |
| Gas  ($/Mcf)                             |       | $                                                                        | 6.99       |   | $ | 6.52 |   |
| Oil  ($/Bbls)                            |       | $                                                                        | 89.12      |   | $ | 50.55 |   |
|                                     |       |                                                                     |       |   |   |
| **Production costs ($/BOE):**            |       |                                                                     |       |   |   |
| Lease  operating expenses                |       | $                                                                        | 29.48      |   | $ | 7.04 |   |
| Production  and property taxes           |       | $                                                                        | 5.87       |   | $ | 4.35 |   |
| Gathering,  Transportation and Marketing |       | $                                                                        | 1.13       |   | $ | 0.48 |   |

 

**Capital Expenditures**

** **

We anticipate net capital expenditures of$12.6 million in 2008.   The followingtables set forth our capital expenditures for the three months ended March 31,2008, and our planned capital expenditures for our principal properties in2008.  Net capital expenditures includeboth cash and accrued expenditures and are net of proceeds from divestitures.  The 2008 estimated expenditures do notinclude the costs to drill additional wells that will help further evaluate ourproperties in the Vermillion Basin. These wells are to be drilled at the sole cost of Devon under the DevonAgreement.

 
| **Project Location**                                  | ** ** | **Net Capital  Expenditures  for the Three  Months ended  March 31,  2008 ($ 000)(1)** | ** ** | **Total 2008  Estimated  Net Capital  Expenditures  ($ 000)(1)** | ** ** |
|------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------|------------|
| **Wyoming**                                                |       |                                                                                                                      |       |                                                                            |       |
| Vermillion  Basin wells and related infrastructure         |       | $                                                                                                                         | 275        |                                                                            | $          | 743 |   |
| Other  Wyoming wells and related infrastructure            |       | 33                                                                                                                        |       | (845                                                                            | )          |
| Acreage/Seismic                                            |       | (957                                                                                                                      | )          | 1,350                                                                           |       |
| **Total Wyoming**                                          |       | (649                                                                                                                      | )          | 1,248                                                                           |       |
| **Williston Basin**                                        |       |                                                                                                                      |       |                                                                            |       |
| Mission  Canyon/Red River wells and related infrastructure |       | 105                                                                                                                       |       | 1,127                                                                           |       |
| Bakken  wells and related infrastructure                   |       | 80                                                                                                                        |       | 9,616                                                                           |       |
| Acreage/Seismic                                            |       | 640                                                                                                                       |       | 621                                                                             |       |
| **Total Williston Basin**                                  |       | 825                                                                                                                       |       | 11,363                                                                          |       |
| **Total All Areas**                                        |       | $                                                                                                                         | 176        |                                                                            | $          | 12,612 |   |

 

----

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

 

 

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**Resultsof Operations**

 

**ThreeMonths Ended March 31, 2008 Compared to Three Months Ended March 31,2007**

** **
| ** **                                                                                        | ** ** | **Three months ended March 31,** | ** ** |
|---------------------------------------------------------------------------------------------------|------------|------------------------------------------------------|------------|
| ** **                                                                                        | ** ** | **2008**                                             | ** ** | **2007** | ** ** |
|                                                                                              |       |                                                 |       |   |   |
| Financial  Results                                                                                |       |                                                 |       |   |   |
| Total  revenue                                                                                    |       | $                                                    | 1,961,537  |   | $ | 2,140,527 |   |
| Total  costs and expenses                                                                         |       | 4,593,573                                            |       | 16,595,360 |   |
| Net  loss                                                                                         |       | (2,632,036                                           | )          | (14,454,833 | ) |
| Diluted  net loss per common share                                                                |       | $                                                    | (0.03      | ) | $ | (0.17 | ) |
|                                                                                              |       |                                                 |       |   |   |
| Operating  Results                                                                                |       |                                                 |       |   |   |
| Production  volumes (BOE)                                                                         |       | 26,948                                               |       | 32,919 |   |
|                                                                                              |       |                                                 |       |   |   |
| Capital  Resources and Liquidity                                                                  |       |                                                 |       |   |   |
| Cash and  cash equivalents at end of the period                                                   |       | $                                                    | 9,904,019  |   | $ | 42,032,501 |   |
|                                                                                              |       |                                                 |       |   |   |
| Net  cash provided by (used in) operating activities                                              |       | (2,428,942                                           | )          | (3,095,535 | ) |
| Capital  expenditures - oil and gas properties excluding accruals and proceeds from  divestitures |       | 690,569                                              |       | 13,341,387 |   |
| Adjusted  EBITDA (see below discussion)                                                           |       | 2,354                                                |       | 762,372 |   |

 

The Company reported a netloss for the three months ended March 31, 2008, of $2,632,036 comparedwith a net loss of $14,454,833 for the same period in 2007.   Included in the net loss for the quarterended March 31, 2007 is a $14,000,000 loss attributable to our full costpool write-down during this period.  TheCompany’s net loss for the three months ended March 31, 2008, was impactedby the reduced crude oil production and increased operating expenses as aresult of workover and repair procedures on its producing Bakken oil wells inMcKenzie County, North Dakota.

 

In evaluating its business,Kodiak considers earnings before interest, taxes, depreciation, depletion, amortization,gain on foreign currency and stock-based compensation (“Adjusted EBITDA”) as akey indicator of financial operating performance and as a measure of theability to generate cash for operational activities and future capitalexpenditures. The Company’s Adjusted EBITDA decreased 99% to $2,354 for thethree months ended March 31, 2008 from the same period in 2007. Thedecrease in Adjusted EBITDA was largely the result of decreased oil productionas a result of workover preparation and repair work on producing wells.  The repair costs increased operating expensesin the first quarter of 2008 and reduced Adjusted EBITDA by approximately$467,000.  Adjusted EBITDA is not a GenerallyAccepted Accounting Principle (“GAAP”) measure of performance. The Company usesthis non-GAAP measure primarily to compare its performance with other companiesin the industry that make a similar disclosure and as a measure of its currentliquidity. The Company believes that this measure may also be useful toinvestors for the same purpose and for an indication of the Company’s abilityto generate cash flow at a level that can sustain or support our operations andcapital investment program. Investors should not consider this measure inisolation or as a substitute for operating income or loss, cash flow fromoperations determined under GAAP, or any other measure for determining 

 

22

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the Company’s operatingperformance that is calculated in accordance with GAAP. In addition, becauseEBITDA is not a GAAP measure, it may not necessarily be comparable to similarlytitled measures employed by other companies. Reconciliation between EBITDA andnet income for the three months ended March 31, 2008 and 2007, is providedin the table below:

 
| ** **                                            | ** ** | **Three Months ending March 31,** | ** ** |
|-------------------------------------------------------|------------|-------------------------------------------------------|------------|
| ** **                                            | ** ** | **2008**                                              | ** ** | **2007** | ** ** |
| **Reconciliation of adjusted EBITDA:** |       |                                                  |       |   |   |
| ** **                                            |       |                                                  |       |   |   |
| Net  Loss                                             |       | $                                                     | (2,632,036 | ) | $ | (14,454,833 | ) |
| Add  back:                                            |       |                                                  |       |   |   |
| Depreciation,  depletion, amortization and accretion  |       | 1,097,299                                             |       | 1,039,246 |   |
| Asset  impairment                                     |       | 0                                                     |       | 14,000,000 |   |
| (Gain)  / loss on foreign currency exchange           |       | 18,281                                                |       | (97,621 | ) |
| Stock  based compensation expense                     |       | 1,518,810                                             |       | 275,580 |   |
|                                                  |       |                                                  |       |   |   |
| Adjusted  EBITDA                                      |       | $                                                     | 2,354      |   | $ | 762,372 |   |

 

Natural gas production volumes increased 45% and oil production volumesdecreased 37% for the three month periods ended March 31, 2008, comparedto the same period in 2007.  Natural gasproduction increased as new wells were placed on production in 2007.  Oil production decreased due to workoveroperations on producing wells which is expected to improve flow rates andextend the lives of the wells.  Total gasprice realizations increased 7.2% to $6.99 per Mcf for the three month periodended March 31, 2008, compared to the same period in 2007.  Oil price realizations were $89.12 per barrelfor the three month period ended March 31, 2007, compared to $50.55 forthe same period in 2007. The net effect of the pricing and volume changesresulted in an increase of oil and gas revenues of $301,354 to $1,878,171 forthe three month periods ended March 31, 2008, compared to the same periodin 2007.

 

The Company recorded lease operating and production tax expense of$982,951 during the three month period ended March 31, 2008, as comparedto $390,775 during the same period in 2007. In the first quarter of 2008, webegan workover operations on our producing Bakken oil wells in McKenzie Countynear the North Dakota and Montana state line. In this play, we intend to clean out and fracture stimulate one well andre-fracture stimulate two wells.  As partof this program, in the first quarter of 2008, we performed required repairwork on the casing of one well in preparation of the workover operations.  This work to repair the casing was completedand the well is back on production pending the workover.  The net cost of approximately $467,000related to the repair work was charged to oil and gas production costs andexpenses in the first quarter of 2008.

 

Depreciation, depletion, amortization and abandonment liabilityaccretion, or DD&A, was $1,097,299 for the three month period ended March 31,2008, compared to $1,039,246 for the same period in 2007.  DD&A expense increased during the quarterdue to the reclassification of wells whose costs were previously classified aswells in progress thus increasing the amortization pool and the DD&Arate.  This increase was partially offsetby the reduced crude oil volume produced due to the workover operations onproducing oil wells.

 

The Company’s general and administrative costs of $2,495,042 during thethree months ended March 31, 2008, compares to $1,262,960 for the sameperiod in 2007.  Included in the generaland administrative expense for this period is a stock-based compensation chargeof $1,518,810 and $275,580 for 2008 and 2007, respectively, for options andrestricted stock issued 

 

23

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to officers, directors and employees. This increase is the result of options and restricted stock grantedsubsequent to March 31, 2007, and the true-up of stock-based compensationexpense for the difference between actual forfeitures and assumed forfeitureswhen the awards were granted.  Theoverall increase in general and administrative expenses is a result of theCompany’s increased staffing requirements and level of activity.  The Company currently has seventeen full timeand three contract employees compared to twelve full time and one part timeemployee in March 2007.

 

**CriticalAccounting Policies and Estimates**

 

We refer you to the corresponding section in Part II, Item 7 ofour Annual Report on Form 10-K for the year ended December 31, 2007.

 

**Recently Issued Accounting Pronouncements**

 

In December 2007, the FASB issued SFAS No. 141-R,“Business Combinations” (“FAS 141R”) which revised SFAS No. 141, “BusinessCombinations” (“FAS 141”). This pronouncement is effective for the Company’sfinancial statements issued after January 1, 2009. Under FAS 141,organizations utilized the announcement date as the measurement date for thepurchase price of the acquired entity. FAS 141R requires measurement at thedate the acquirer obtains control of the acquiree, generally referred to as theacquisition date. FAS 141R will have a significant impact on the accounting fortransaction costs, restructuring costs as well as the initial recognition ofcontingent assets and liabilities assumed during a business combination. UnderFAS 141R, adjustments to the acquired entity’s deferred tax assets anduncertain tax position balances occurring outside the measurement period are recordedas a component of the income tax expense, rather than goodwill. As theprovisions of FAS 141R are applied prospectively, the impact to the Companycannot be determined until the transactions occur.

 

In December 2007, the FASB issued SFAS No. 160, “NoncontrollingInterests in Consolidated Financial Statements, an amendment of ARB No. 51”(“FAS 160”).  This Statement establishesaccounting and reporting standards for the noncontrolling interest in asubsidiary and for the deconsolidation of a subsidiary. FAS 160 is effectivefor fiscal years, and interim periods within those fiscal years, beginning onor after December 15, 2008.  Earlieradoption is prohibited.  The Company doesnot expect that the adoption of FAS 160 will have a material effect on itsfinancial position or results of operations.

 

**Off-BalanceSheet Arrangements**

 

We do not haveany off-balance sheet financing arrangements at March 31, 2008 other thanlease committments as disclosed elsewhere in this 10-Q.

 

# **ITEM 3.                 **QUANTITATIVE ANDQUALITATIVE DISCLOSURES ABOUT MARKET RISK

# ** **

# ** **

**Oiland Gas Price Fluctuations**

 

Our primary market risk is market changes in oil and natural gasprices.  Prospective revenues from the sale of products or properties willbe impacted by oil and natural gas prices.  A $1.00 per mcf change in themarket price of natural gas will result in approximately a $66,600 change inour gross gas production revenue.  A $1.00 per barrel change in the marketprice of oil will result in approximately a $15,900 change in our gross oil productionrevenue. The impact on any potential sale of property cannot be readilydetermined.

 

**InterestRate Fluctuations**

 

We currently maintain some of our available cash in redeemable shortterm investments, classified as cash equivalents, and our reported interestincome from these short term investments could be adversely affected by anymaterial changes in US dollar interest rates.  A 1% change in the interestrate would have approximately a $101,744 annual impact if all of our cash wasinvested in interest bearing notes.

 

24

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# **ITEM 4.                  CONTROLSAND PROCEDURES**

# ** **

Under thesupervision and with the participation of our management, we evaluated thedesign and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and15d-15(e) of the Securities Exchange Act of 1934, or the “Exchange Act”)as of March 31, 2008.  On the basisof this review, our management concluded that our disclosure controls andprocedures are effectively designed to give reasonable assurance that theinformation we are required to disclose in reports that we file under theExchange Act is recorded, processed, summarized and reported within the timeperiods specified in the rules and forms of the SEC and to ensure thatinformation required to be disclosed in the reports filed or submitted underthe Exchange Act is accumulated and communicated to our management, includingour Chief Executive Officer, in a manner that allows timely decisions regardingrequired disclosure.

 

There were no changes in the Company’s internal controls over financialreporting that occurred in the first fiscal quarter of 2008 that materiallyaffected, or were reasonably likely to materially affect, its internal controlover financial reporting.

 

# **PART II— OTHER INFORMATION**

# ** **

# **ITEM 1.                  LEGALPROCEEDINGS**

# ** **

**               **None.

 

# **ITEM 1A.               RISK FACTORS**

# ** **

Informationabout material risks related to the Company’s business, financial condition andresults of operations for the three months ended March 31, 2008 does notmaterially differ from the information set forth under the heading “RiskFactors” in Part I, Item 1A in the Company’s Annual Report on Form 10-Kfor the year ended December 31, 2007. The risk factors disclosed in Part I, Item 1A to our Annual Reporton Form 10-K for the fiscal year ended December 31, 2007, in additionto the other information set forth in this quarterly report, could materiallyaffect our business, financial condition or results of operations. Additionalrisks and uncertainties not currently known to us or that we deem to beimmaterial could also materially adversely affect our business, financialcondition or results of operations.

# ** **

# **ITEM 2.                  UNREGISTEREDSALES OF EQUITY SECURITIES AND USE OF PROCEEDS**

# ** **

                None.

 

# **ITEM 3.                  DEFAULTSUPON SENIOR SECURITIES**

# ** **

                None.

 

25

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# **ITEM 4.                  SUBMISSIONOF MATTERS TO A VOTE OF SECURITY HOLDERS**

 

None

 

# **ITEM 5.                  OTHERINFORMATION**

# ** **

None.

 

26

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# **ITEM 6.  EXHIBITS**

 
| **Exhibit Number** | ** ** | **Description**                                                                                           |
|-------------------------|------------|-----------------------------------------------------------------------------------------------------------|
| ** **              | ** ** | ** **                                                                                                |
| 3.3                     |       | **Amended and Restated By-Law No. 1 of the Company**                                                 |
| 31.1                    |       | Certification of the Principal Executive Officer pursuant to §302 of  theSarbanes-Oxley Act of 2002  |
| 31.2                    |       | Certification of the Principal Financial Officer pursuant to §302 of  the Sarbanes-Oxley Act of 2002 |
| 32.1                    |       | Certification  of the Principal Executive Officer pursuant to 18 U.S.C. Section1350                       |
| 32.2                    |       | Certification of the Principal Financial Officer Pursuant to 18  U.S.C. Section1350                       |

 

27

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# ** **

# **SIGNATURES**

# ** **

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

 
|              | **KODIAK OIL & GAS CORP.**    |
|-------------------|----------------------------------------|
|              | ** **                             |
|              |                                   |
| May 8,  2008 | /s/ Lynn A.  Peterson                  |
|              | Lynn A.  Peterson                      |
|              | President  and Chief Executive Officer |
|              |                                   |
|              |                                   |
| May 8,  2008 | /s/ James P.  Henderson                |
|              | James P.  Henderson                    |
|              | Chief  Financial Officer               |
|              | (principal  financial officer)         |

 

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