UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2007

Commission File No. 001-32920

Kodiak Oil & Gas Corp.

(Exact name of registrant as specified in its charter)

1625 Broadway, Suite 250

Denver, Colorado 80202

(Address of principal executive offices, including zip code)

303-592-8075

(Registrant’s telephone number, including area code)

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

Yes x    No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act.

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

87,931,926 shares of no par value of the Registrant’s Common Stock were issued and outstanding as of October 31, 2007.

KODIAK OIL & GAS CORP.

INDEX

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PART 1 - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED BALANCE SHEETS

SEE ACCOMPANYING NOTES

3

KODIAK OIL & GAS CORP.

CONDENDSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

SEE ACCOMPANYING NOTES

4

KODIAK OIL & GAS CORP.

STATEMENT OF STOCKHOLDERS’ EQUITY

(UNAUDITED)

SEE ACCOMPANYING NOTES

5

KODIAK OIL & GAS CORP.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

SEE ACCOMPANYING NOTES

6

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - Organization

Description of Operations

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

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

Note 2 – Basis of Presentation and Significant Accounting Policies

Basis of Presentation

The condensed consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc.  All significant inter-company balances and transactions have been eliminated. Substantially all of the Company’s business is transacted in U.S. dollars and, accordingly, the financial statements are expressed in U.S. dollars. The accompanying unaudited condensed consolidated financial statements have been prepared 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. In the opinion of management, the condensed consolidated financial statements contain all adjustments (consisting of normal recurring adjustments) considered necessary for a fair presentation of the Company’s results for the periods presented. These unaudited condensed consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements included in the Annual Report on Form 10-K for the fiscal year ended December 31, 2006. Operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year.

Certain amounts in the 2006 unaudited condensed consolidated financial statements have been reclassified to conform to the 2007 unaudited consolidated financial statement presentation; such reclassifications had no effect on the 2006 net loss.

Use of Estimates in the Preparation of Financial Statements

The preparation of the financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  The Company bases its estimates on historical experience and on various other assumptions it believes to be reasonable under the circumstances. Although

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actual results may differ from these estimates under different assumptions or conditions, the Company believes that its estimates are reasonable.

Cash and Cash Equivalents

Cash and cash equivalents consist of all highly liquid investments that are readily convertible to cash and have maturities of three months or less when purchased.  The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.

Restricted Investment

The restricted investment balance as of September 30, 2007 is comprised of: (a) $183,542 certificate of deposit to collateralize a surety bond to provide for state bonding requirements for plugging and abandonment liabilities; and (b) a $69,797 certificate of deposit to collateralize the costs of the new office floor improvements that will be released over four years at $17,449 per year.  The restricted investment balance as of December 31, 2006 is comprised of: (a) $182,052 certificate of deposit to collateralize a surety bond to provide for state bonding requirements for plugging and abandonment liabilities; and (b) $42,400 certificate of deposit to collateralize the costs of office improvements.

Concentration of Credit Risk

The Company’s cash equivalents and short-term investments are exposed to concentrations of credit risk.  The Company manages and controls this risk by investing these funds with major financial institutions.

The Company’s receivables are comprised of oil and gas revenue receivables and joint interest billings receivable.  The amounts are due from a limited number of entities.  Therefore, the collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners.   To date the Company has had minimal bad debts. The receivables are not collateralized.

Oil and Gas Producing Activities

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center (“full cost pool”).  Such costs include land acquisition costs, geologic and geophysical expenses, carrying charges on non-producing properties, and costs of drilling directly related to acquisition and exploration activities. Proceeds from property sales are generally credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs.  A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.  The Company had no property sales for the three and nine month periods ended September 30, 2007.

Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on estimated gross proved reserves.  Relative volumes of oil and gas production and reserves are converted at the energy equivalent rate of six thousand cubic feet of natural gas to one barrel of crude oil.  Gross proved reserves are estimated

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annually by independent petroleum engineers and updated throughout the year by the Company as new wells are drilled and as more current information is obtained.  When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.  Costs of unproved properties are withheld from the depletion base until they are developed, abandoned, or impaired.

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

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

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

The optimal method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data. The accuracy of the decline analysis method generally increases with the length of the production history. Most of the Company’s wells have been producing less than six years and for some, less than a year.  Because of this short production history, other generally less accurate methods such as volumetric analysis and analogy to the production history of wells of ours and other operators in the same reservoir were used in conjunction with the decline analysis method to determine the Company’s estimates of proved reserves including developed  producing, developed non-producing and undeveloped. As the Company’s wells are produced over time and more data is available, the estimated proved reserves will be re-determined at least on an annual basis and may be adjusted based on that data.  As noted below, because of significant exploration activity and additional well data, the Company updated its reserves as of September 2007.

Actual future production, gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable gas and oil reserves most likely will vary from the Company’s estimates.  Any significant variance could materially affect the quantities and present value of the Company’s reserves. For example, a decrease in price of $0.10 per Mcf for natural gas and $1.00 per barrel of oil would result in a decrease in the

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Company’s December 31, 2006 present value of future net cash flows of approximately $763,000. In addition, the Company may adjust estimates of proved reserves to reflect production history, acquisitions, divestitures, ownership interest revisions, results of exploration and development and prevailing gas and oil prices.  The Company’s reserves may also be susceptible to drainage by operators on adjacent properties.

Because of significant exploration activity during late 2006 and 2007 and the short production history on many existing wells at the time of the preparation of the December 31, 2006 reserve report, the Company updated its reserves as of September 30, 2007. Commodity prices used in this analysis include the Plains Marketing West Texas Intermediate crude oil posted price of $78.25 per barrel, the Platts Gas Daily Northern, Ventura midpoint price of $5.63 per MMBtu, and the Platts Gas Daily Questar Rocky Mountain midpoint price of $0.98 per MMBtu.  All prices are as of September 30, 2007, and are further adjusted for transportation and quality differentials.  The resulting weighted average realized oil and gas prices for the production of proved reserves at September 30, 2007, was $71.59 per barrel of crude oil and $3.96 per Mcf of natural gas.  Wells with gas sold based on the Questar Rocky Mountain price are largely uneconomic and therefore have little effect on the weighted average sales price.  Based on this analysis, the Company’s full cost pool exceeded the ceiling limitation by approximately $20.0 million and an impairment expense was recorded for this amount during the quarter ended September 30, 2007.

As of December 31, 2006, based on realized oil and gas prices of $50.37 per barrel and $4.53 per Mcf, the full cost pool exceeded the ceiling by approximately $5.2 million. However, in early 2007, oil and gas prices increased and the Company completed a well with additional reserves.  Using the price on the subsequent remeasurement date, the Company’s full cost pool did not exceed the ceiling limitation and therefore, the Company did not record an impairment of its oil and gas properties at December 31, 2006.  As of March 31, 2007, the Company’s full cost pool exceeded the ceiling limitation based on oil and gas prices at March 31, 2007 of $55.12 per barrel and $4.47 per Mcf and an impairment expense of $14.0 million was recorded during the quarter ended March 31, 2007.

The year-to-date impairment of $34,000,000 is primarily the result of the Company’s inability to establish production and qualified reserves in its deep Vermillion Basin project, continued low natural gas prices in Wyoming, and the impairment of certain undeveloped properties in Wyoming and North Dakota.

As with many resource plays in the early stages of development, significant expenditures have been and will continue to be required to understand the parameters of the deep Vermillion Basin play.  As of September 30, 2007, Kodiak has drilled four exploratory wells in the Baxter, Frontier, and Dakota Formations to better understand the resource potential.  In the second half of 2007, Kodiak has focused on acquiring additional geologic and geophysical data from these wells and the acquisition and interpretation of an extensive seismic study over the northern portion of its acreage.  While the Company is optimistic about the long-term potential of this prospect Kodiak has not established significant proved reserves for the deep Vermillion Basin.  As a result, the value of the development to date calculated under SEC guidelines does not offset the cost of the wells and related acreage in the full cost pool.  For further detail of activities in this area see management’s discussion in Item 2 of this filing.

Kodiak has drilled three non-commercial wells on its Great Bear prospect in northern North Dakota since late 2005.  As a result and because of Management’s reduced drilling plans

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in the southern portion of this acreage, the Company has impaired approximately half of this acreage in the third quarter 2007.  The Company has also impaired certain acreage in Wyoming unrelated to its Vermillion play due to reduced expectations.

Other Property and Equipment

Other property and equipment such as office furniture and equipment, vehicles, and computer hardware and software are recorded at cost.  Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized.  Maintenance and repair costs are expensed when incurred.  Depreciation is recorded using the straight-line method over the estimated useful lives of three years for computer equipment, and five years for office equipment and vehicles.  When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.

Fair Value of Financial Instruments

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

Stock-Based Compensation

The Company historically accounted for stock-based compensation under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123, “Accounting for Stock-Based Compensation.” SFAS No. 123 required us to record an expense associated with the fair value of stock-based compensation.

On January 1, 2006, we adopted SFAS No. 123(R), “Accounting for Stock-Based Compensation,” using the modified prospective method. Under the modified prospective method, the adoption of SFAS No. 123(R) applies to new awards and to awards modified, repurchased, or cancelled after December 31, 2005, as well as to the unvested portion of awards outstanding as of January 1, 2006. In accordance with the modified prospective method, Kodiak has not adjusted the financial statements for periods ended prior to January 1, 2006. The Company did not recognize any one-time effects of the adoption and continued to use similar option valuation models and assumptions as were used prior to January 1, 2006. There is no fair-value-based compensation expense associated with prior awards that were not vested on the date of the adoption of SFAS No. 123(R).

Kodiak currently use the Black-Scholes option valuation model to calculate stock-based compensation at the date of grant.  Option pricing models require the input of highly subjective assumptions, including the expected price volatility.  Changes in these assumptions can materially affect the fair value estimate.

Asset Retirement Obligation

The Company follows SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset

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retirement cost is included in proved oil and gas properties in the condensed consolidated balance sheets.  The Company depletes the amount added to proved oil and gas property costs.  The future cash outflows associated with settling the asset retirement obligations that have been accrued in the accompanying balance sheets are excluded from the ceiling test calculations.  The Company also depletes the estimated dismantlement and abandonment costs, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations.  These costs are also included in the ceiling test calculation.  The asset retirement liability will be allocated to operating expense by using a systematic and rational method.  A reconciliation of our asset retirement liability for the nine months ended September 30, 2007 and 2006 is as follows:

Recently Issued Accounting Pronouncements:

The Company adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”) on January 1, 2007.  FIN 48 provides detailed guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in the financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes”.   Tax positions must meet a “more-likely-than-not” recognition threshold at the effective date to be recognized upon the adoption of FIN 48 and in subsequent periods. The adoption of FIN 48 had an immaterial impact on the Company’s consolidated financial position and did not result in unrecognized tax liabilities or benefits being recorded. Accordingly, no corresponding interest and penalties have been accrued. The Company files returns in Canada, in which the Company has net operating loss positions.  The Company also files income tax returns in the U.S. federal jurisdiction and various states. There are currently no federal or state income tax examinations underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue service for tax years before 2003 and for state and local tax authorities for years before 2002. The Company does, however, have prior year net operating losses which remain open for examination.

On February 15, 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities.”  This Statement establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for the Company’s financial statements issued in 2008. The Company is currently evaluating the impact that the adoption of SFAS No. 159 might have on its financial position or results of operations.

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Note 3 – Compensation Plan

Stock-based Compensation Plan

Under the Company’s 2007 Stock Incentive Plan (the “2007 Plan”), which replaced the Company’s Incentive Share Option Plan (the “Pre-existing Plan”), stock options, stock appreciation rights (SARs), restricted stock and restricted stock units, performance awards, stock or property, stock awards and other stock-based awards may be granted to any employee, consultant, independent contractor, director or officer of the Company. A total of 8,000,000 shares of common stock may be issued under the 2007 Plan, which includes shares issuable under the Pre-existing Plan pursuant to options outstanding as of the effective date of the 2007 Plan. No more than 8,000,000 shares may be used for stock issued pursuant to incentive stock options and the number of shares available for granting restricted stock and restricted stock units shall not exceed 1,000,000, subject to adjustment as defined in the 2007 Plan. The Company granted 1,930,000 stock options and 81,000 shares of restricted stock in the nine-month period ended September 30, 2007.

Compensation expense charged against income for all stock-based awards during the nine months ended September 30, 2007 and September 30, 2006 was $1.7 million and $1.4 million, pre-tax, respectively, which is included in general and administrative expense in the Consolidated Statements of Operations.

The following assumptions were used for the Black-Scholes model to value options granted in the periods presented:

A summary of the stock options outstanding as of September 30, 2007 is as follows:

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At September 30, 2007, stock options outstanding are as follows:

The aggregate intrinsic value of outstanding and vested options as of September 30, 2007 was $5,823,055 and $5,784,618, respectively, based on the Company’s September 30, 2007 closing common stock price of $3.30. This amount would have been received by the option holders had all option holders exercised their options as of that date.

The total grant date fair value of the shares vested during the three and nine months ended September 30, 2007 was $624,600 and $1,519,200, respectively. As of September 30, 2007, there was $5,824,085 of total unrecognized compensation cost related to unamortized options. That cost is expected to be recognized over a period of three years.

The Company granted 81,000 restricted stock awards in the nine months ended September 30, 2007. Of these awards, 60,000 vest on a graded-vesting basis of one-third immediately and one-third at each anniversary date over a two year service period and 20,000

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vest on a graded-vesting basis of one-third at each anniversary date over a three year service period. The Company recognizes compensation cost over the requisite service period for the entire award with the expense recognized upon vesting. The fair value of restricted stock grants is based on the stock price on the grant date and the Company assumed no annual forfeiture rate. As of September 30, 2007, there were 61,000 unvested shares with a weighted-average grant date fair value of $4.91 per share and $299,680 of total unrecognized compensation cost related to non-vested restricted stock which is expected to be recognized over a three-year period.

Note 4 - Commitments and Contingencies

The Company leases office facilities under an operating lease agreement that expires on June 30, 2012. Rent expense was $102,314 and $47,546 for the nine month periods ended September 30, 2007 and 2006, respectively.

The following table shows the annual rentals per year for the life of the lease as of September 30, 2007:

The Company has no other capital leases and no other operating lease commitments.

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

Note 5 - Differences between Canadian and United States Accounting Principles

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America which differ in certain respects with those principles and practices that the Company would have followed had its financial statements been prepared in accordance with accounting principles and practices generally accepted in Canada. Management does not believe that the financial statements would vary materially had they been prepared in accordance with Canadian GAAP and that any recently issued, not yet effective, Canadian accounting standards, if currently adopted, would not have a material effect on the accompanying financial statements.

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Forward-Looking Statements

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

•                  the Company’s future financial position, including working capital and anticipated cash flow;

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

•                  market demand;

•                  risks and uncertainties involving geology of oil and gas deposits;

•                  the uncertainty of reserve estimates and reserves life;

•                  the uncertainty of estimates and projections relating to production, costs and expenses;

•                  potential delays or changes in plans with respect to exploration or development projects or capital expenditures;

•                  fluctuations in oil and gas prices, foreign currency exchange rates and interest rates;

•                  health, safety and environmental risks;

•                  uncertainties as to the availability and cost of financing; and

•                  the possibility that government policies or laws may change or governmental approvals may be delayed or withheld.

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

Our forward-looking statements contained in this Quarterly Report are made as of the respective dates set forth in this Quarterly Report. Such forward-looking statements are based on the beliefs, expectations and opinions of management as of the date the statements are made. We do not intend to update these forward-looking statements, except as otherwise required by law.

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For the reasons set forth above, investors should not place undue reliance on forward-looking statements.

Overall Performance

Kodiak Oil & Gas Corp. is a public company listed on the American Stock Exchange (AMEX), under the trading symbol “KOG”, and is engaged in the business of exploration and development of oil and gas properties. The Company’s principal focus is on the exploration and development of oil and gas properties within two producing basins in the Rocky Mountain Region. The Company is exploring for and developing natural gas in the Green River Basin in southwestern Wyoming and oil in the Williston Basin in Montana and North Dakota.

Kodiak’s results of operations and financial condition are significantly affected by the success of its exploration activity, the resulting production, oil and natural gas commodity prices, and the costs related to operating its properties. As is common with companies engaged in the exploration of early resource plays, Kodiak’s financial position and results of operations change significantly from period to period. During the nine month period ended September 30, 2007, we incurred capital expenditures of approximately $40 million largely related to our oil and gas drilling operations.  Except for wells currently in progress, these expenditures increased the Company’s full cost pool, but did not add significantly to our reserves. As of September 30, 2007, the value of Kodiak’s proved reserves as calculated under SEC guidelines, did not support the costs included in the full cost pool, based on oil and gas prices of $71.59 per barrel of crude oil and $3.96 per Mcf of natural gas.  Consequently the Company recorded a cumulative asset impairment of $34 million during the nine month period ended September 30, 2007.

Our working capital of $18.6 million as of September 30, 2007 may not be sufficient to support all of our potential exploration opportunities in 2008, depending on the nature and extent of our final capital expenditure budget and the terms of potential joint venture arrangements into which the company may enter. As our anticipated funds from operations are expected to provide only a limited amount of additional working capital, it is likely that we will need to obtain alternative sources of capital to fund our growth and development. We anticipate that we would seek to obtain additional funding either by means of debt or equity financings or by entering into additional joint venture agreements with other companies, the availability of which there can be no assurance.

Exploratory Activity

Williston Basin

Mission Canyon/Red River Formations—Sheridan County, Montana and Divide County, North Dakota

The primary producing objectives in this prospect area are the Mission Canyon and the Red River formations at approximate depths of 8,000 feet and 11,000 feet, respectively. In the third quarter of 2007, the Company completed one well in the Mission Canyon Formation. The well was put on production at the end of September and a pumping unit is currently being installed. During the nine-month period ended September 30, 2007, Kodiak has participated in the drilling of five geologic prospects that were defined by 3-D seismic. The Company has completed two of these wells and three were dry holes. Kodiak will monitor the production from the recently drilled wells before further stepouts are drilled. The Company has identified

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several additional prospects within its acreage that may be drilled during 2008 subject to the results of seismic evaluation. Kodiak is currently permitting an approximate 18 square mile 3-D seismic program over some of its acreage.

Bakken Formation—McKenzie and Dunn Counties, North Dakota

Kodiak has three wells in McKenzie County producing from the Bakken Formation near the North Dakota and Montana state line. The three wells were put on production in late 2006 and early 2007 and have produced 35,605 barrels of oil through September 30, 2007. One of the three wells has never been fracture stimulated and we would expect such procedure to be completed in early 2008. The Company has at least two undeveloped locations offsetting these wells which could be drilled in 2008.

The Company has continued its ongoing acreage acquisition program in Dunn County, North Dakota where the primary objective is the Bakken shale.  Kodiak has acquired leasehold acreage in a trend bordered by producing wells drilled by, among others, EOG Resources, Inc. and Whiting Petroleum Corp. to the north and Marathon Oil Corp. and ConocoPhillips to the west and south. The Company is presently awaiting approval of a permit to drill from the Bureau of Land Management and the Bureau of Indian Affairs on its most southern block of acreage in the area that encompasses approximately 9,000 gross acres. Subject to obtaining a permit to drill from the Bureau of Land Management and the Bureau of Indian Affairs, drilling activity should commence in early 2008.

In the third quarter of 2007, the Company entered into a letter of intent with a private, independent exploration and production company to jointly lease and develop certain prospective lands north and northwest of our original acreage block noted above. Under this letter of intent and subsequent participating agreement, the Company and its partner each will have an undivided 50% working interest in the properties. Under the participating agreement, the Company has committed to participate in the drilling of two horizontal wells that will evaluate the Bakken formation at an approximate vertical depth of 10,000 feet. We expect the permitting procedures will begin in the fourth quarter of 2007 with drilling scheduled for the first half of 2008. The two companies will share operations with each entity operating certain properties.

Green River Basin - Vermillion Basin, Sweetwater County, Wyoming

Vermillion Basin Deep – Baxter Shale and Frontier and Dakota Sandstone

The primary deeper natural gas targets of the Vermillion Basin area are the over-pressured Baxter Shale and Frontier sands at depths to approximately 15,000 feet. In the first half of 2007, the Company horizontally drilled the first gaseous interval in the Baxter Formation, at an approximate vertical depth of 11,700 feet, on its NT Federal #4-35H well (100% working interest (“WI”), 82.5% net revenue interest (“NRI”), Kodiak operated). While the well encountered gas shows in several fractures that were intercepted by the 1,655 feet of horizontal lateral in one of the targets within the Baxter shale, the production results were not commercial and this lateral has been abandoned. The Company re-entered the NT Federal #4-35H well bore during the third quarter of 2007, sidetracked and vertically drilled the Baxter, Frontier and Dakota Formations to a total depth of 14,434 feet. The Company obtained full cores over five sixty-foot intervals throughout the Baxter Formation. These cores are currently being evaluated

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for a number of factors including gas in place, rock properties and mechanics and fracture orientation. This process should be completed during the fourth quarter of 2007. Completion work on this well will continue during the fourth quarter with the fracture stimulation of the Frontier and Dakota Sands and the Baxter Shale. Stimulation of the Frontier and Dakota sands has been completed with the Baxter Shale to be stimulated in late November 2007.

Kodiak completed drilling operations on its HB #5-3 well (80% WI, 68% NRI, Kodiak operated) located on the western edge of the prospective producing area. The well was drilled vertically to a depth of 13,534 feet to evaluate the potential of the Mesaverde formations, the Baxter shale and the Frontier sandstone. Completion procedures are underway and are expected to be completed in early November 2007.

During the third quarter, the Company completed the acquisition of approximately 43-square-mile 3-D seismic program on the northern block of its acreage which includes portions of its Chicken Springs and Chicken Ranch Federal Units, as well as land currently not included in federal units. Processing and interpretation should be completed in the fourth quarter of 2007 which will assist the Company as it begins to outline its 2008 drilling program in the Vermillion Basin.

Kodiak’s operated wells in the Vermillion Basin were shut in during the 2007 summer and fall months due to adverse gas prices. The Company expects to commence production on these wells in December 2007 as stronger gas prices are anticipated during the winter months. Additionally, the completion of the Rockies Express Pipeline is scheduled to go into service during the first quarter of 2008 which is expected to improve natural gas prices in the Rockies production area.

Product Prices and Production

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

The Company’s production volumes are a direct result of the success of its exploratory and acquisition activities. Production volumes may vary monthly as various wells are completed or maintained to provide optimal flows.

Oil and gas sales volume and price realization comparisons for the indicated periods are set forth below:

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Results of Operations - Three Months Ended September 30, 2007 and 2006

The Company reported a net loss for the three months ended September 30, 2007 of $21,984,875 compared with a net loss of $389,288 for the same period in 2006. The increased loss was largely due to the $20 million impairment related to the full-cost ceiling test; increased depletion, depreciation, amortization expense related to additional wells drilled and impairment of acreage; and general and administrative costs as the result of higher stock based compensation expense. Increased revenues from higher production volumes and prices were more than offset by the increase in these non-cash expenses.

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In evaluating its business, Kodiak considers earnings before interest, taxes, depreciation, depletion, amortization, gain on foreign currency and stock-based compensation (“Adjusted EBITDA”) as a key indicator of financial operating performance and as a measure of the ability to generate cash for operational activities and future capital expenditures. The Company’s “Adjusted EBITDA” increased 133% to $815,569 for the three months ended September 30, 2007 from the same period in 2006. The increase in Adjusted EBITDA was largely the result of increased production from additional drilling and higher commodity prices offset to a lesser extent by increased oil and gas production expense. Adjusted EBITDA is not a Generally Accepted Accounting Principle (“GAAP”) measure of performance. The Company uses this non-GAAP measure primarily to compare its performance with other companies in the industry that make a similar disclosure and as a measure of its current liquidity. The Company believes that this measure may also be useful to investors for the same purpose and for an indication of the Company’s ability to generate cash flow at a level that can sustain or support our operations and capital investment program. Investors should not consider this measure in isolation or as a substitute for operating income or loss, cash flow from operations determined under GAAP, or any other measure for determining the Company’s operating performance that is calculated in accordance with GAAP. In addition, because EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies. Reconciliation between EBITDA and net income for the three months ended September 30, 2007 is provided in the table below:

Natural gas production volumes increased 78% and oil production volumes increased 93% for the three month periods ended September 30, 2007 compared to the same period in 2006. Total gas price realizations decreased 11.2% to $4.28 per Mcf for the three month period ended September 30, 2007 compared to the same period in 2006. Oil price realizations were $71.65 per barrel for the three month period ended September 30, 2007 compared to $62.66 for the same period in 2006. The net effect of the pricing and volume changes resulted in an increase of oil and gas revenues of $1,159,660 to $2,200,249 for the three month periods ended September 30, 2007 compared to the same period in 2006.

The Company recorded lease operating and production tax expense of $460,867 during the three month period ended September 30, 2007, as compared to $194,021 during the same period in 2006. Depreciation, depletion, amortization and abandonment liability accretion, or DD&A, was $2,036,384 for the three month period ended September 30, 2007 compared to $494,829 for the same period in 2006. The changes in these expenses reflect the Company’s

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growing production base, number of producing wells and, because of revenue-based production taxes, the increase in sales revenues. DD&A expense also increased during the quarter due to the impairment of certain undeveloped properties and reclassification of three wells whose costs were previously classified as wells in progress thus increasing the amortization pool and the DD&A rate. DD&A is expected to decline to similar of that recorded in previous quarters of 2007 subsequent to the recording of the impairment in the third quarter of 2007.

The Company’s general and administrative costs of $2,091,145 during the three months ended September 30, 2007 compares to $980,100 for the same period in 2006. Included in the general and administrative expense for this period is a stock-based compensation charge of $861,583 and $251,059 for 2007 and 2006, respectively, for options and restricted stock issued to officers, directors and employees. The overall increase in general and administrative expenses is a result of the Company’s increased staffing requirements and level of activity. The Company currently has sixteen full time and three contract employees compared to nine full time employees in September 2006.

Based on the Company’s evaluation of its oil and gas reserves at September 30, 2007, using weighted average realized oil and gas prices of $71.59 per barrel of crude oil and $3.96 per Mcf of natural gas, the Company’s full cost pool exceeded the ceiling limitation by approximately $20.0 million and an impairment expense was recorded for this amount during the quarter ended September 30, 2007.

Results of Operations - Nine Months Ended September 30, 2007 and 2006

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The Company reported a net loss for the nine months ended September 30, 2007 of $36,888,954 compared with a net loss of $1,402,912 for the same period in 2006. Included in the 2007 loss is $34,000,000 attributable to the full cost pool write-down during the first and third quarters of 2007. Excluding the impairment, the net loss increased by $1,486,042 to $2,888,954 due to higher DD&A expense and general and administrative costs that more than offset increased revenues. The Company’s Adjusted EBITDA increased to $2,081,844 for the nine months ended September 30, 2007 compared to $968,489 for the same period in 2006. Reconciliation between EBITDA and net loss for the nine months ended September 30, 2007 is provided in the table below:

Gas production volumes were 150,977 and 93,721 Mcf and oil production volumes were 79,689 and 38,223 barrels for the nine month periods ended September 30, 2007 and 2006, respectively. Total gas price realizations decreased 17% to $4.97 per Mcf for the nine month period ended September 30, 2007 compared to the same period in 2006. Oil price realizations were $61.44 per barrel for the nine month period ended September 30, 2007 compared to $58.93 for the same period in 2006. The net effect of the pricing and volume changes resulted in an increase of oil and gas revenues of $2,835,401 to $5,646,668 for the nine month period ended September 30, 2007 compared to the same period in 2006. The increase in production and revenues is largely the result of the Company’s activities in the Williston Basin. Many of the wells in this area began producing in late 2006 and did not contribute to that year’s production volumes or revenue.

The Company recorded lease operating and production tax expense of $1,197,640 during the nine month period ended September 30, 2007, as compared to $543,682 during the same period in 2006. DD&A expense was $4,062,397 for the nine month period ended September 30, 2007 compared to $1,374,019 for the same period in 2006. As with the three-month period comparison above, the changes in these expenses reflect the Company’s growing production base, number of producing wells and, because of revenue-based production taxes, the increase in sales revenues. DD&A expense was also impacted by the impairment of certain acreage and the reclassification of three wells from wells-in-progress to the amortization pool which increases the DD&A rate.

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The Company’s general and administrative costs of $5,380,549 during the nine months ended September 30, 2007 compares to $3,270,534 for the same period in 2006. Included in the general and administrative expense is stock-based compensation expense of $1,689,377 and $1,372,152 for the nine month periods ending September 30, 2007 and 2006, respectively, for options and restricted stock issued to officers, directors and employees. The overall increase in general and administrative expenses is a result of the Company’s increased staffing requirements and level of activity. The Company currently has sixteen full time employees, an increase of five from the same period in 2006.

As of March 31, 2007, based on current oil and gas prices of $55.12 per barrel and $4.47 per Mcf, the Company’s full cost pool exceeded the present value of the Company’s estimated future net revenue discounted at 10%. Therefore, impairment expense of $14,000,000 was recorded during the quarter ended March 31, 2007. Based on the Company’s evaluation of oil and gas reserves at September 30, 2007, using weighted average realized oil and gas prices of $71.59 per barrel of crude oil and $3.96 per Mcf of natural gas, the Company’s full cost pool exceeded the ceiling limitation by approximately $20.0 million and an impairment expense was recorded for this amount during the quarter ended September 30, 2007.

The year-to-date impairment of $34,000,000 is primarily the result of the Company’s inability to establish production and qualified reserves in its deep Vermillion Basin project, continued uneconomic natural gas prices in Wyoming, and the impairment of certain undeveloped properties in Wyoming and North Dakota.

As with most resource plays in the early stages of development, significant expenditures have been and continue to be required to understand the parameters of the deep Vermillion Basin play. As of September 30, 2007, Kodiak has drilled four exploratory wells in the Baxter, Frontier, and Dakota Formations to better understand the resource potential. In the second half of 2007, Kodiak has focused on acquiring additional geologic and geophysical data from these wells and the acquisition and interpretation of an extensive seismic study over the northern portion of its acreage. Kodiak believes the long-term potential of this play is substantial and will ultimately prove profitable but at September 30, 2007, the Company is unable to substantiate proved reserves for this play. Without proved reserves in the play, the value of the development to date calculated under SEC guidelines does not offset the cost of the wells and related acreage in the full cost pool.

Kodiak has drilled three non-commercial wells on its Great Bear prospect in northern North Dakota since late 2005. As a result and because of Management’s reduced drilling plans in the southern portion of this acreage, the Company has impaired approximately half of this acreage in the third quarter 2007. The Company has also impaired certain acreage in Wyoming unrelated to its Vermillion play due to reduced expectations.

Liquidity and Capital Resources

As of September 30, 2007, the Company had cash and cash equivalents of approximately $19.4 million, working capital of $18.6 million and no long term debt. During the nine month periods ended September 30, 2007 and 2006, the Company’s share of exploration and development costs was $39.9 million and $22.1 million, respectively.

The Company has budgeted total capital expenditures in the Vermillion Basin of approximately $4.0 million for the fourth quarter of 2007 for well completions and geological

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and geophysical activities. The Company has allocated another $3.0 million to additional completion work and acreage acquisition in the Williston Basin through year end 2007. Based upon these anticipated expenditures through 2007, the Company anticipates approximately $12.0 million in working capital at year end. Kodiak expects that such capital will be sufficient to commence our 2008 drilling program in the Williston Basin, where the Company’s expected share of each drilled and completed Bakken well is expected to be approximately $2.5 million to $3.0 million. In the Vermillion Basin, our exploration activity will be based upon the completion results of the two wells being completed, our seismic processing and interpretation work, and our core analysis work that we anticipate will be completed before year end. The actual amount, timing and allocation of the Company’s capital expenditures are dependant on the results of the Company’s ongoing exploration and drilling programs, the Company’s evaluation of the technical and geological data obtained in the course of its operations and certain other factors, such as the market price for oil and gas and the availability and cost of oil field services. The Company adjusted and reallocated its exploration program during the third quarter due to commodity prices and exploration results. Management will continue to closely monitor expenditures through the fourth quarter of 2007 and into 2008.

Our working capital of $18.6 million as of September 30, 2007 may not be sufficient to support all of our potential exploration opportunities in 2008, depending on the nature and extent of our final capital expenditure budget and the terms of potential joint venture arrangements into which the company may enter. As our anticipated funds from operations are expected to provide only a limited amount of additional working capital, it is likely that we will need to obtain alternative sources of capital to fund our growth and development. We anticipate that we would seek to obtain additional funding either by means of debt or equity financings or by entering into additional joint venture agreements with other companies, the availability of which there can be no assurance. In a majority of our operating areas, we have maintained high working interests in our properties thereby providing us with the opportunity to enter such agreements with industry partners for participation in drilling activities. During the quarter ended September 30, 2007, we entered into an agreement with a private, independent exploration and production company to jointly lease and develop certain prospective lands in North Dakota, whereby we retained an undivided 50% working interest in the properties. This agreement allows the Company to share the exploratory risk with an industry partner while retaining a significant working interest in the properties. In our Vermillion Basin prospect in Wyoming, we are currently engaged in ongoing discussions to enter into a joint venture agreement with an exploration and production company to develop the potential gas resource. The Company will continue to evaluate additional joint venture and partnership opportunities as a means to provide potential alternative sources of funding.

The Company currently has no lines of credit or other bank financing arrangements. The Company has no defined benefit plan and no obligation for post retirement employee benefits.

Financial Instruments and Other Instruments

As of September 30, 2007 the Company had cash, accounts receivable, accounts payable and accrued liabilities which are carried at approximate fair value because of the short maturity date of those instruments. Unless otherwise noted, it is management’s opinion that the Company is not exposed to significant interest, currency or credit risks arising from these financial instruments.

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Critical Accounting Policies and Estimates

Please refer to the corresponding section in Part I, Item 5 of our Annual Report on Form 10-K for the year ended December 31, 2006.

Recently Issued Accounting Pronouncements:

In June 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes. The interpretation clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting for interim periods, disclosure and transition of uncertain tax positions. The interpretation is effective for fiscal years beginning after December 15, 2006. The adoption of FIN 48 did not have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

The Company adopted the provisions of FIN 48 on January 1, 2007. FIN 48 provides detailed guidance for the financial statement recognition, measurement and disclosure of uncertain tax positions recognized in the financial statements in accordance with SFAS 109. Tax positions must meet a “more-likely-than-not” recognition threshold at the effective date to be recognized upon the adoption of FIN 48 and in subsequent periods. The adoption of FIN 48 had an immaterial impact on the Company’s consolidated financial position and did not result in unrecognized tax liabilities or benefits being recorded. Accordingly, no corresponding interest and penalties have been accrued. The Company files returns in Canada, in which the Company has net operating loss positions. The Company also files income tax returns in the U.S. federal jurisdiction and various states. There are currently no federal or state income tax examinations underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue service for tax years before 2003 and for state and local tax authorities for years before 2002. The Company does, however, have prior year net operating losses that remain open for examination.

On February 15, 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities.”  This Statement establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for the Company’s financial statements issued in 2008. The Company is currently evaluating the impact that the adoption of SFAS No. 159 might have on its financial position or results of operations.

Off-Balance Sheet Arrangements

Kodiak did not have any off-balance sheet financing arrangements at September 30, 2007.

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Oil and Gas Price Fluctuations

The Company’s primary market risk is market changes in oil and natural gas prices.  Prospective revenues from the sale of products or properties will be impacted by oil and natural gas prices.  A $1.00 per Mcf change in the market price of natural gas will result in approximately $135,500 change in the annual gross gas production revenue.  A $1.00 per barrel change in the market price of oil will result in approximately $79,700 change in our annual gross oil production revenue. The impact on any potential sale of property cannot be readily determined.

Interest Rate Fluctuations

Kodiak currently maintains some of its available cash in redeemable short-term investments, classified as cash equivalents, and the reported interest income from these short-term investments could be adversely affected by any material changes in U.S. dollar interest rates.  A 1% change in the interest rate would have approximately $410,400 annual impact if all of the Company’s cash was invested in interest-bearing notes.

We carried out an evaluation required by the Securities and Exchange Act of 1934 (the “1934 Act”), under the supervision and with the participation of our principal executive officer and principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) of the 1934 Act, as of the end of the period covered by this report. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the 1934 Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2007 that have materially affected or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

                                              None.

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Other than the following updates, there have been no material changes to the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2006, as filed with the SEC on March 27, 2007.

Risks Relating to the Company

We have historically incurred losses and expect to incur additional losses in the future. It is difficult for us to forecast when we will achieve profitability, if ever.

Historically, we have incurred losses from operations during our limited history in the oil and natural gas business. We had a cumulative deficit of $8.6 million as at December 31, 2006 and a cumulative deficit of $45.6 million as at September 30, 2007. While we have developed some of our properties, most of our properties are in the exploration stage and to date we have established a limited volume of proved reserves on our properties. To become profitable, we would need to be successful in our acquisition, exploration, development and production activities, all of which are subject to many risks beyond our control. We cannot assure you that we will successfully implement our business plan or that we will achieve commercial profitability in the future. Even if we become profitable, we cannot assure you that our profitability will be sustainable or increase on a periodic basis. In addition, should we be unable to continue as a going concern, realization of assets and settlement of liabilities in other than the normal course of business may be at amounts significantly different from those in the financial statements included in this Form 10-Q. Finally, due to our limited history in the oil and natural gas business, we have limited historical financial and operating information available to help you evaluate our performance or an investment in our common stock.

We will require significant additional working capital, which may not be available to us on favorable terms, or at all.

Our working capital decreased from $53.2 million as of December 31, 2006 to $18.6 million as of September 30, 2007. Future acquisitions and future exploration, development and production activities will require a substantial amount of additional working capital and cash flow. We expect that our current cash balances and cash flow from operations will be sufficient only to provide a limited amount of working capital, and the revenues generated from our properties will not alone be sufficient to fund our operations or planned growth. These conditions will require us to seek alternative sources of capital by means of entering into joint ventures with other exploration and production companies or by undertaking financing activities. However, future financing may not be available in amounts or on terms acceptable to us, if at all. If we borrow additional funds, we will likely be obligated to make periodic interest or other debt service payments and may be subject to additional restrictive covenants. Should we elect to raise additional capital through the issuance and sale of equity securities, the sales may be at prices below the market price of our stock, and our shareholders may suffer significant dilution. Our failure to obtain financing on a timely basis or on favorable terms could result in the loss or substantial dilution of our interests in our properties.

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Pipeline Capacity in the Rocky Mountain region may be inadequate, and consequently, a price decrease may more adversely affect the price received for our Rocky Mountain production than production in other U.S. regions.

                                                Natural gas prices are critical to our business, and the marketability of our production will depend on the capacity of oil and natural gas gathering systems and pipelines. Oftentimes, the market price for natural gas in the Rocky Mountain region differs from the market indices for natural gas in other regions of the United States. Management believes the current differential is due, in large part, to insufficient pipeline capacity in the Rocky Mountain region. Therefore, a price decrease may more adversely affect the price received for our Rocky Mountain production than production in the other U.S. regions. From time to time, new pipeline projects have been announced, including the Rockies Express Pipeline, to transport natural gas production from the Rocky Mountain region to other markets. However, there can be no assurance that such infrastructures will be built, or that if built, they would prevent large basis differentials from occurring in the future. The unavailability or insufficient capacity of pipeline facilities could force us to shut-in producing wells, delay the commencement of production, or discontinue development plans for some of our properties, which would adversely affect our financial condition and performance.

In December 2006, we raised net proceeds of $46,672,213 in a public offering of 12,075,000 shares of common stock, all of which shares were sold. The registration statements to register the shares became effective on December 15, 2006 (commission file number 333-138932) and December 18, 2006 (commission file number 333-139441). We have used approximately $40,000,000 of the net proceeds from the offering for exploration and drilling activities. We expect to use the remainder of our net proceeds to fund a portion of our 2007 and 2008 exploration and drilling programs and for working capital and general corporate purposes.

None.

None.

                                              None.

Additional information relating to the Company is available on the U.S. Securities & Exchange Commission website at www.sec.gov.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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