- Annual Report (10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2009

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

For the transition period from _________________ to__________________

Commission File number 333-38558

KODIAK ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware		65-0967706
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

833 4 th Avenue S.W., Suite 1120, Calgary, AB		T2P 3T5
(Address of principal executive offices)		(Zip code)

(403) 262-8044

(Registrant's telephone number, including area code)

Securities registered under Section 12(b) of the Exchange Act: None

Securities registered under Section 12(g) of the Exchange Act: Common Stock, $0.001 par value

Indicate by checkmark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [ ] No [X]

Indicate by checkmark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [X]

Indicate by check mark whether the issuer (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. [X] Yes [ ] No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). [ ] Yes [ ] No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this Chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K [X]

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.

Large accelerated filer [ ]	Accelerated filer [ ]
Non-accelerated filer [ ] (Do not check if a smaller reporting company)	Smaller reporting company [X]

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

[ ] Yes [X] No

The market value of the voting and non-voting common equity held by non-affiliates as of the last business day of the most recently completed second fiscal quarter was $29,809,940.

The number of shares outstanding of each of the registrant’s classes of common equity, as of March 19, 2010: [110,407,186] Common Shares, $0.001 par value.

DOCUMENTS INCORPORATED BY REFERENCE: None.

KODIAK ENERGY, INC.

Form 10-K

For the Fiscal Year Ended December 31, 2009

TABLE OF CONTENTS

PART I

ITEM 1.	BUSINESS	3

ITEM 1A.	RISK FACTORS	13

ITEM 1B.	UNRESOLVED STAFF COMMENTS	20

ITEM 2.	PROPERTIES	20

ITEM 3.	LEGAL PROCEEDINGS	29

ITEM 4.	[RESERVED]	29

PART II

ITEM 5.	MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	30

ITEM 6.	SELECTED FINANCIAL DATA	31

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	31

ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	41

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	42

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	68

ITEM 9A.	CONTROLS AND PROCEDURES	68

ITEM 9B.	OTHER INFORMATION	69


PART III

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	70

ITEM 11.	EXECUTIVE COMPENSATION	73

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	75

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS, AND DIRECTOR INDEPENDENCE	76

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	77


PART IV

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	77

PART I

ITEM 1. BUSINESS

HISTORY

The Company was incorporated in Delaware on December 15, 1999. On December 22, 1999, we merged with Island Critical Care Corp., an inactive Florida corporation. The purpose of this merger was to effect a change in the domicile of the Florida corporation to Delaware. Island Critical Care Corp. (a Florida corporation) was originally incorporated on March 15, 1996 under the name 9974 Holdings Inc., and subsequently changed its name from 9974 Holdings Inc. to Ontario Midwestern Railway Co. Inc, and finally the Florida corporation's name was changed to Midwestern Railway Co. Inc. All three changes in name of the Florida corporation were completed prior to its merger with the Delaware corporation. On January 13, 2000, we merged with Island Critical Care Corporation, an Ontario corporation. On February 5, 2003, the Company filed a petition for bankruptcy in the District of Prince Edward Island, Division No. 01, Prince Edward Island Court (No. 1713, Estate No. 51-104460). The Company emerged from bankruptcy pursuant to a court order on April 7, 2004 with no assets and no liabilities. Upon emergence from bankruptcy, the Company adopted Fresh Start Accounting pursuant to SOP 90-7 "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code." On December 27, 2004, we changed our name from Island Critical Care Corporation to Kodiak Energy, Inc. ("Kodiak" or “Company”).

GENERAL

Kodiak Energy, Inc. is a development stage oil and gas company that is engaged in the development and exploration for natural resources. Since 2005 and until the fourth quarter of 2009, the Company has been active in Canada and the United States in acquiring properties that are prospective for petroleum and natural gas and related hydrocarbons. The prospects the Company holds are generally under leases and include partial and full working interests. In all of the core properties, Kodiak is the operator and majority interest owner. In two properties, we have the option to perform certain exploratory drilling to earn additional interests. The prospects are subject to varying royalties due to the state, province, territory, or federal governments and, in some instances, to other royalty owners in the prospect.

As at December 31, 2009, the Company had three wholly-owned subsidiaries: Kodiak Petroleum ULC (“KULC”), an inactive Alberta company; Kodiak Petroleum (Montana), Inc. (“KPMI”), a Delaware company that operates Kodiak’s projects in New Mexico and Montana; and Kodiak Petroleum (Utah), Inc. (“KPUI”), a Delaware company and holding company holding the shares of Kodiak Petroleum (Montana), Inc.; and one majority owned subsidiary, 1438821 Alberta Ltd.(”1438821”), an Alberta company incorporated in November, 2008. In January 2009, the Company vended its Lucy, British Columbia and CREEnergy Project, Alberta projects into 1438821 for financing purposes. In February 2009, 1438821 changed its name to Cougar Energy, Inc. (“Cougar”). Through the Company’s private subsidiary, Cougar Energy, Inc., and that entity’s acquisition of producing properties effective September 30, 2009 and October 1, 2009, the Company became a development company with oil and gas reserves, production, and recognized revenue as a result of operations effective October 2009.

The Company’s principal executive offices are located at 833 4th Avenue S.W., Suite 1120, Calgary, AB, Canada and our telephone number is (403) 262-8044.

The information in these consolidated financial statements should be read in conjunction with the December 31, 2009 consolidated financial statements.

The accompanying consolidated financial statements in this annual report on Form 10-K include the accounts of the Company and its wholly-owned subsidiaries, Kodiak Petroleum ULC, Kodiak Petroleum (Montana), Inc., Kodiak Petroleum (Utah), Inc. (collectively “Kodiak”, the “Company”, “we”, “us” or “our”) and its 84.6% owned subsidiary Cougar Energy, Inc. (formerly “1438821 Alberta Ltd.”) as at December 31, 2009, and are presented in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”). In British Columbia, Canada, the Company operates under the assumed name of Kodiak Bear Energy, Inc. All intercompany accounts and transactions have been eliminated.

OIL AND GAS PRODUCTION

As of December 31, 2009, the Company had net production of approximately 125 barrels of oil per day (bbl/d). The production was from 11 wells in the Company’s Trout properties and 1 well in the Crossfield property. Produced water was disposed of in two of the Company’s operated water disposal wells.

COMPETITIVE STRENGTHS

Dominant Position in the Trout Area, Alberta

The Company has acquired a strategically valuable core area in the Trout properties. By acquiring operatorship of wells, facilities, pipelines and roads, the Company can set the pace for the development rather than be dependent on other non-receptive operators.

Attractive Underlying Economics

The Company currently has net crude oil production of approximately 125 barrels per day (bbl/d). The majority of the production consists of light sweet crude oil and has an average operating cost of $25/bbl. Cdn This results in a substantial netback at the current and forecast commodity prices. These attractive economics are a result of acquiring an extensive production infrastructure including wells, pipelines, treating facilities, roads, and access to power.

Stable Base Production

The majority of the Company’s current producing properties are located in mature reservoirs with predictable lower annual decline rates. This allows the Company to more accurately predict cash flow and plan development and exploration opportunities.

Commodity Position

All the Company’s current proved and probable production in the Trout Area is light sweet crude oil, which receives the going price for crude without discounts.

Valuable Acreage Positions

Trout Area, Alberta

As described above, the Trout land position.

New Mexico, United States

Excellent land position – large contiguous block with long term leases – straddling the Sheep Mountain Pipeline and giving access to markets for the CO2 found on the properties for enhanced recovery in the Permian Basin.

Development and Exploration Opportunities

Core Trout Project, Alberta

The infrastructure will support substantially increased production levels (up to 2,500bbl/d) from the area with nominal increases in costs – providing opportunities to consolidate other properties into this Core Project, which the Company is actively working on.

The existing land base provides many opportunities for drilling programs to add reserves and production. The Company has acquired 2D and 3D seismic on much of these lands. In addition, the existing suspended wells provide many opportunities for workovers to add reserves and production at much lower than drilling or acquisition costs, which has been demonstrated with the current programs initiated.

The CREEnergy Project provides additional drilling and development opportunities with adjacent land to our Core Trout Project that may use the existing infrastructure.

Lucy, British Columbia

Our Muskwa Shale project in the Horn River Basin of north east British Columbia has prospects for natural gas that are comparable to many of the major developments currently under way in the area. With an investment in a fracture program on the 2 existing wells, a development into a producing property may be possible that may show the large recoverable reserves seen in the area.

New Mexico, United States

With pipeline quality CO2 found in the 3 wells drilled to date, and large land base straddling the existing CO2 pipeline, the project is an opportunity as economics change in the enhanced oil recovery projects, to build a commercial CO2 development.

Little Chicago, Northwest Territories

With our high quality seismic over the prospect, experience working in the area, and understanding of the area geology, we have a strategic advantage and the opportunity to continue identifying prospects based on that information. As economic factors change and/or the Mackenzie Valley Pipeline construction is committed to, we anticipate re-entering the area.

BUSINESS STRATEGIES

Financial Flexibility

The Company has used and expects to use a variety of sources of funding to finance its acquisitions and capital development and exploration programs for 2010.

Internally generated cash flow from operations – will be key going forward.

Debt financing – both revolving line of credit and specific debt instruments for specific projects – normally lower risk projects or smaller acquisitions. Also vendor take backs – in certain circumstances when it benefits both the vendor and the purchaser – a type of debt structure may be set up with the vendor.

Equity issues when terms and conditions are appropriate – for higher risk projects or larger acquisitions.

This ability to adjust projects and timelines, due to large land bases and multiple projects and work within different financing models, has allowed the Company to survive the recent recession and actually show growth in difficult times.

DESCRIPTION OF OUR EXPLORATION AND PRODUCTION PROPERTIES AND PROJECTS

OIL AND GAS DATA

Reserves Categories

Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. Although probable and possible reserve locations are found by “stepping out” from proved reserve locations, estimates of probable and possible reserves are, by their nature, more speculative than estimates of proved reserves and, accordingly, are subject to substantially greater risk of being actually realized by us.

Estimated Reserves

The following table presents our estimated net proved, probable and possible oil and gas reserves relating to our oil and natural gas properties as of December 31, 2009, based on our reserve reports as of such date. The data was prepared by the independent petroleum engineering firm GLJ Petroleum Consultants Ltd. (GLJ). Reserves at December 31, 2009 were determined using the unweighted arithmetic average of the first day of the month price for each month from January through December 2009, which we refer to as the 12-month average price as of December 31, 2009, of $58.21 per barrel of oil.

OIL AND GAS RESERVES SUMMARY December 31, 2009 (Mbbl)
	Light and Medium Oil		Heavy Oil		Natural Gas		Natural Gas Liquids		Total Oil Equivalent
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
PROVED – Developed Producing	214	187	-	-	-	-	-	-	214	187
PROVED – Developed Non Producing	87	76	-	-	-	-	-	-	87	76
PROVED – Undeveloped	-	-	-	-	-	-	-	-	-	-
TOTAL PROVED	301	263	-	-	-	-	-	-	301	263
PROBABLE	174	142	37	36	-	-	-	-	211	179
TOTAL PROVED Plus PROBABLE	474	402	37	36	-	-	-	-	512	442
Notes: 1. Company Gross Reserves: These are working interest owner’s share of gross reserves before the deduction of royalties. Royalty interest share of reserves is included. Gross reserves were not estimated by the independent evaluator. 2. Company Net Reserves: These are the working interest owners’ share of gross reserves after the deduction of royalties. Royalty interest share of reserves is not included in this category. 3. Numbers have not considered the 84% ownership of Cougar Energy, Inc. by Kodiak as Kodiak reports financials on a consolidated basis.

NET PRESENT VALUE OF FUTURE NET REVENUE Based on Constant Prices and Costs December 31, 2009
Reserves Category	Before Income Taxes Discounted at (% Per Year) $M Cdn
	0%	5%	10%	15%	20%
PROVED – Developed producing	4,367	3,889	3,507	3,197	2,941
PROVED – Developed Non-producing	1,326	1,191	1,079	984	903
PROVED – Undeveloped	0	0	0	0	0
TOTAL PROVED	5,693	5,079	4,585	4,180	3,844
PROBABLE	4,645	4,006	3,520	3,139	2,834
TOTAL PROVED PLUS PROBABLE	10,377	9,086	8,105	7,320	6,678
Notes: 1. Numbers have not considered the 84.6% ownership of Cougar Energy, Inc by Kodiak, as Kodiak reports financial on a consolidated basis. 2. Numbers may not add exactly due to rounding. 3. Numbers are M $ CAD as reserve reports were calculated on that basis.

Proved Undeveloped Reserves

At December 31, 2009, we had no proved undeveloped reserves.

Sensitivity of Reserves to Prices and Costs

Fluctuations in the prices and costs used in the estimation of reserves can cause significant variations in the resulting reserve calculation. We believe it would be meaningful to consider different price and cost sensitivities to the reserve calculation presented above, particularly with respect to recent pronouncements from the U.S. SEC regarding constant and variable pricing regarding oil and gas reserves. The following table represents reserve amounts as of December 31, 2009 under the different pricing and cost scenarios explained below. The reserves presented under the alternative price and cost assumptions have been prepared by GLJ, independent petroleum engineers.

EFFECT OF SEC MODERNIZATION METHODOLOGY ON RESERVES Constant Pricing – December 31, 2009 Estimated Reserves – Constant Pricing NPV (discounted 10%)
	SEC Modernization Methodology (1)			Actual Price Received for Production (2)
Type	Oil	Gas	Total	Oil	Gas	Total
Proved Reserves	3,507	0	3,507	5,453	0	5,453
Developed	1,079	0	1,079	2,032	0	3,032
Undeveloped	4,585	0	4,585	7,485	0	7,485
Total Proved Reserves	3,520	0	3,520	5,167	0	5,167
Total Probable Reserves	8,105	0	8,105	12,652	0	12,652
Total Possible Reserves	3,507	0	3,507	5,453	0	5,453
Notes: 1. Amounts determined based on the recently adopted SEC final rule “Modernization of Gas and Oil Accounting”. The prices used in this calculation are the 12-month average price as of December 31, 2009 - $58.21 USD/bbl and used for calculation in the table above under “Estimated Reserves”. 2. Amounts determined based on actual average price received for oil production during the reporting period – $74.70 USD and used for calculation in the table under “Estimated Reserves”.

Reserves

Estimating oil and gas reserves is a very complex process requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. This data may change substantially over time as a result of numerous factors such as production history, additional development activity, and continual reassessment of the viability of production under various economic and political conditions.

Consequently, material upward or downward revisions to existing reserve estimates may occur from time to time; although, every reasonable efforts is made to ensure that reported results are the most accurate assessment available. We ensure that the data provided to our external independent experts, and their interpretation of that data, corresponds with our development plans and management’s assessment of each reservoir.

The significance of subjective decisions required and variances in available data make estimates generally less precise than other estimates presented in connection with financial statement disclosures.

In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 reserve information. In January 2010, FASB issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. We adopted the guidance as of December 31, 2009 in conjunction with our year-end reserve report as a change in accounting principle that is inseparable from a change in accounting estimate. Under the SEC’s final rule, prior period reserves were not restated.

For the United States, the primary impacts of the SEC’s final rule on our reserve estimates include: The use of the unweighted 12-month average of the first-day-of-the-month reference price of $58.21 USD per barrel for oil compared to average actual sale price of $74.20 USD per barrel received for the months of October, November and December 2009 when we had sales. Therefore, a price point was used for calculations of reserves and impact on long term liabilities, which was 78% of actual – thus our comments as to subjective price points and that effect on estimates.

The impact of the adoption of the SEC’s final rule on our financial statements is not practicable to estimate due to the operational and technical challenges associated with calculating a cumulative effect of adoption by preparing reserve reports under both the old and new rules.

The process for preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data provided for management reviews and review of the independent third party reserves report. The technical employee responsible for overseeing the process for preparation of the reserves estimates has a Bachelor of Science Degree in Geology and is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA), Society of Petroleum Engineers (SPE), and Canadian Society of Petroleum Geologists (CSPG). He has more than 25 years of experience in reservoir geology.

All reserve information in this report is based on estimates prepared by GLJ, independent petroleum engineers. The technical personnel responsible for preparing the reserve estimates at GLJ meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas by the Society of Petroleum Engineers. GLJ is an independent firm of petroleum engineers, geologists, geophysicists and petrophysicists; they do not own an interest in our properties and are not employed on a contingent fee basis.

Internal Controls

A significant component of our internal controls in our reserve estimation effort is our practice of using an independent third-party reserve engineering firm to prepare 100% of our year-end proved reserves and, for 2009, our probable and possible reserves. The qualifications of this firm are discussed below under “Independence and Qualifications of Reserve Preparer.” The Board of Directors of the Company has formed a Reserves Committee for the purposes of reviewing the reserves estimates and procedures prior to acceptance of the report. The Committee is composed of two independent board members and one non independent board member.

Our internal geologist is our Vice President, Exploration and reports to our Vice President, Operations, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides appropriate data to our independent third party reserve engineers to estimate our year-end reserves. Our internal geologist staff consists of one degreed geologist, with over 25 years of diversified geological experience in the Canadian oil and gas industry, including in the Western Canadian Sedimentary Basin. He is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA), Society of Petroleum Engineers (SPE), and Canadian Society of Petroleum Geologists (CSPG).

Production Volumes, Sales Prices and Production Costs

The following table sets forth information regarding our oil and natural gas properties. The oil and gas production figures reflect the net production attributable to our revenue interest and are not indicative of the total volumes produced by the wells.

SUMMARY OF NET REVENUE December 31, 2009 (Undiscounted)
Reserves Category	Revenue	Royalties	Operating Costs	Capital Development Costs	Well Abandonment and Reclamation Costs	Future Net Revenue Before Future Income Tax
Proved Reserves	26,595	3,253	11,383	619	548	10,792
Probable Reserves	18,002	2,784	6,583	700	98	7,838
Proved Plus Probable Reserves	44,063	6,036	17,965	1,319	646	18,631
Notes: 1. Numbers have not considered the approximate 84% ownership of Cougar Energy, Inc by Kodiak. 2. Numbers may not add exactly due to rounding. 3. Numbers are MM $ CAD. 4. Disclosure is required for Total Proved and Proved plus Probable reserves.

Independence and Qualifications of Reserve Preparer

We engaged GLJ Petroleum Consultants Ltd. (GLJ), third-party reserve engineers, to prepare our reserves as of December 31, 2009 in accordance with reserves definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (COGE), the Canadian Securities Administrators National Instrument 51-101 (NI 51-101) using Forecast Pricing Assumptions and, for the SEC, using Constant Pricing Assumptions. The technical person responsible for our reserve estimates at GLJ meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth by The Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA). GLJ is an independent firm of petroleum engineers, geologists, geophysicists and petro physicists; they do not own any interest in our properties and are not employed on a contingent fee basis.

MAINTENANCE AND PRODUCTION

General

As the operator of wells in which we have an interest, we design and manage the development of these wells and supervise operation and maintenance activities on a day-to-day basis. We employ production and reservoir engineers, geologists and other specialists.

Field operations conducted by our contractors include duties whose primary responsibility is to operate the wells. Other contracted field personnel are experienced and involved in the activities of well servicing, the development and completion of new wells and the construction of supporting infrastructure for new and existing wells (such as electric service , salt water disposal facilities, and gas feeder lines). We utilize third-party contractors on an “as needed” basis to supplement our field personnel and related equipment.

Oil and Gas Leases and Development Rights

As of December 31, 2009, we had approximately 130 leases covering approximately 285,949 gross acres. The typical oil and gas lease provides for the payment of royalties to the mineral owner for all oil or gas produced from any well drilled on the lease premises. This amount typically ranges from 12% to 30% resulting in a 70% to 88% net revenue interest to us.

Because the acquisition of oil and gas leases is a very competitive process, and involves certain geological and business risks to identify productive areas, prospective leases are sometimes held by other oil and gas operators. In order to gain the right to drill these leases, we may purchase leases from other oil and gas operators. In some cases, the assignor of such leases will reserve an overriding royalty interest, ranging from 5% to 15%, which further reduces the net revenue interest available to us to between 55% and 73%.

As of December 31, 2009, approximately 4% of our oil and gas leases were held by production, which means that for as long as our wells continue to produce oil or gas, we will continue to own those respective leases.

In the Trout Area, Alberta as of December 31, 2009, we held oil and gas leases on approximately 7,680 gross acres, of which approximately 320 gross acres (4%) are not currently held by production. The approximate 320 acres had an expiry date in Q4 2009 and an application has been submitted to the regulatory agency to extend the expiry of these leases.

In the Alexander Area, Alberta as of December 31, 2009, we held oil and gas leases on approximately 160 gross acres, of which 0 gross acres (0%) are not currently held by production. There are no expiry issues for this lease.

In the Crossfield Area, Alberta as of December 31, 2009, we held oil and gas leases on approximately 160 gross acres, of which 0 gross acres (0%) are not currently held by production. There are no expiry issues for this lease.

In the Granlea Area, Alberta as of December 31, 2009, we held oil and gas leases on approximately 1,265 gross acres, of which approximately 1,265 gross acres (100%) are not currently held by production. The Granlea oil and gas leases will expire in Q3 2010.

In Lucy, British Columbia as of December 31, 2009, we held oil and gas leases on approximately 1,975 gross acres, of which approximately 1,975 gross acres (100%) are not currently held by production. The Lucy mineral lease was extended as part of an approved Experimental Scheme application to the regulatory agency. The Lucy lease is currently extended indefinitely.

In the Little Chicago Area, N.W.T. as of December 31, 2009, we held oil and gas leases on approximately 199,000 gross acres, of which approximately 199,000 gross acres (100%) are not currently held by production. The Little Chicago oil and gas leases will expire in Q3 2010.

In the Sofia and Speardraw Areas, northeast New Mexico as of December 31, 2009, we held CO2 and oil and gas leases on approximately 76,805 gross acres, of which approximately 76,805 gross acres (100%) are not currently held by production. There are no lease expiries in 2010.

In the Hill County Area, northwest Montana as of December 31, 2009, we held oil and gas leases on approximately 879 gross acres, of which approximately 879 gross acres (100%) are not currently held by production. The Montana leases will expire in Q3 2010.

In the Bison Lake area, northern Alberta as of December 31, 2009, we hold oil and gas leases and development rights, by virtue of farm-out agreements or similar mechanisms, on approximately 17,712 gross acres that are still within their original lease or agreement term and are not earned or are not held by production. The farm-in agreement specifies that we are entitled to earn 100% of whatever leases we can extend as a result of drilling and completion operations. The farm-in leases expire in Q3 2010.

Oil Marketing Contracts

The Company currently has an oil marketing contract with an established Canadian marketing company. The contract is a monthly evergreen contract for oil purchased at the 40 degree price for light sweet crude oil at Edmonton, Alberta. The contract can be terminated with 30 days notice.

Exploration and Production

Our operations are subject to various types of regulation at federal, state, provincial, territorial and local levels. These types of regulations may include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most provinces, states, territories and some municipalities in which we operate also regulate one or more of the following:

the location of wells;

the method of drilling and casing wells;

the surface use and restoration of properties upon which wells are drilled;

the plugging and abandoning of wells; and

notice to surface owners and other third parties.

Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

See additional discussion in Item 1A. Risk Factors.

Employees and Consultants

As of December 31, 2009, the Company has a total of 8 executive and administrative personnel located at our headquarters in Calgary, Alberta, Canada. The Company has a total of 3 field contractors located in the Trout Area properties, north central Alberta, and 1 field contractor located in the Crossfield property, central Alberta Canada. Professional consultants are utilized on an as needed basis. Our employees and consultants are covered by employment and consulting agreements. Management considers its relations with our employees to be satisfactory.

Where to Find Additional Information

Additional information about us can be found on our website at www.kodiakpetroleum.com. Information on our website is not part of this document. The Company also provides free of charge on our website our filings with the SEC, including our annual reports, quarterly reports and current reports, along with any amendments thereto, as soon as reasonably practicable after we have electronically filed such material with, or furnished it to, the SEC.

You may also find information related to our corporate governance, board committees and Company code of ethics on our website. Among the information you can find there is the following:

Code of Conduct

Mandate of the Board of Directors

Audit Committee Charter

Corporate Disclosure & Insider Trading Policy

Whistleblower Policy

Health, Safety and Environment Policy

Compensation Committee Mandate.

GLOSSARY OF SELECTED TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report on Form 10-K. Some of the definitions below have been abbreviated from the applicable definition contained in Rule 4-10(a) of Regulation S-X.

Equisetum Field. This is a strike area where a gas or oilfield has been established and a spacing unit or other approval had been issued by the Energy Resources Conservation Board (ERCB) of the Province of Alberta. The Equisetum Field is located in the general area of West of the 5 th Meridian, Township 88, Ranges 5 to 6.

Kidney Field. This is a strike area where a gas or oilfield has been established and a spacing unit or other approval had been issued by the ERCB of the Province of Alberta. The Kidney Field is located in the general area of West of the 5 th Meridian, Townships 89 to 92, Ranges 3 to 7.

Muskwa Shale. The Muskwa formation occurs in northern Alberta, northeastern British Columbia and in the southern part of the Northwest Territories. Gas is produced from the Muskwa formation shales in the Horn River Basin in the Greater Sierra oil field in northeastern British Columbia. Horizontal drilling and fracturing techniques are used to extract the gas from the low permeability shales. The formation typically has a thickness of 34 meters (110 ft.).

ITEM 1A. RISK FACTORS

BUSINESS RISKS

Going Concern Uncertainty

There is uncertainty that the Company will continue as a going concern, which presumes the realization of assets and discharge of liabilities in the normal course of business for the foreseeable future. The Company has not generated positive cash flow since inception and has incurred operating losses and will need additional working capital for its future planned activities. Continuation of the Company as a going concern is dependent upon obtaining sufficient working capital to finance ongoing operations. The Company’s strategy to address this uncertainty includes additional equity and debt financing; however, there are no assurances that any such financings can be obtained on favorable terms, if at all. These financial statements do not reflect the adjustments or reclassification of assets and liabilities that would be necessary if the Company were unable to continue its operations.

Financial Markets Instability and Uncertainty

The 2008/09 worldwide financial and credit crisis has severely restricted the availability of capital and credit to fund the continuation and expansion of junior oil and gas operations worldwide. The shortage of capital and credit, combined with recent substantial losses in worldwide equity markets, led to an extended worldwide economic recession and a very slow recovery. This limited access to capital still exists today except on extremely dilutive or oppressive terms for exploration and development. The slowdown in economic activity caused by this recession has immediately reduced worldwide demand for energy, resulting in substantially lower oil and natural gas and other commodity prices. Oil has recovered somewhat, however, natural gas continues to be depressed due to an excess of supply. The prolonged reduction in oil and natural gas prices has depressed the levels of exploration, development and production activity. That is impacting negatively on our Company’s ability to raise capital to finance our ongoing capital projects. The Company may be required to consider divestiture of some properties or working interests to raise funds. Until the financial market conditions improve, we will face significant challenges in meeting our ongoing financial obligations. This continuing global financial crisis may have impacts on our business and financial condition that we cannot currently predict. Global market and economic conditions, including those related to the credit markets, could have a material adverse effect on our business, financial condition and results of operations. A general slowdown in economic activity could adversely affect our business by impacting our ability to access additional exploration and development capital in the interim.

The Oil and Gas Industry Is Highly Competitive

The oil and gas industry is highly competitive. We compete with oil and natural gas companies and other individual producers and operators, many of which have longer operating histories and substantially greater financial and other resources than we do. We compete with companies in other industries supplying energy, fuel and other needs to consumers. Many of these companies not only explore for and produce crude oil and natural gas, but also carry on refining operations and market petroleum and other products on a worldwide basis. Our larger competitors, by reason of their size and relative financial strength, can more easily access capital markets than we can and may enjoy a competitive advantage in the recruitment of qualified personnel. They may be able to absorb the burden of any changes in laws and regulation in the jurisdictions in which we do business and handle longer periods of reduced prices of gas and oil more easily than we can. Our competitors may be able to pay more for productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties in the future will depend upon our ability to conduct efficient operations, evaluate and select suitable properties, implement advanced technologies and consummate transactions in a highly competitive environment.

Trends and Uncertainties

We are subject to the following trends and uncertainties:

Adverse weather conditions that may affect our ability to conduct our exploration activities;

General economic conditions, including supply and demand for petroleum based products in Canada, the United States, and remaining parts of the world;

Political instability in the Middle East and other major oil and gas producing regions;

Domestic and foreign tax policy;

Price of oil and gas foreign imports;

Cost of exploring for, producing, and delivering oil and gas;

Overall supply and demand for oil and gas;

Availability of alternative fuel sources;

Discovery rate of new oil and gas reserves; and

Pace adopted by foreign governments for the exploration, development and production of their national reserves.

Government and Environmental Regulation

Our business is governed by numerous laws and regulations at various levels of government. These laws and regulations govern the operation and maintenance of our facilities, the discharge of materials into the environment and other environmental protection issues. The laws and regulations may, among other potential consequences, require that we acquire permits before commencing drilling, restrict the substances that can be released into the environment with drilling and production activities, limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas, require that reclamation measures be taken to prevent pollution from former operations, require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells and remediation of contaminated soil and groundwater, and require remedial measures to be taken with respect to property designated as a contaminated site.

Under these laws and regulations, we could be liable for personal injury, clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. We maintain limited insurance coverage for sudden and accidental environmental damages as well as environmental damage that occurs over time. However, we do not believe that insurance coverage for the full potential liability of environmental damages is available at a reasonable cost. Accordingly, we could be liable, or could be required to cease production on properties, if environmental damage occurs.

The costs of complying with environmental laws and regulations in the future may harm our business. Furthermore, future changes in environmental laws and regulations could occur that may result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, any of which could have a material adverse effect on our financial condition or results of operations.

Since the 2008/09 market decline, we are unable to forecast when the long term CO2 contracts delivered into the Permian Basis of S.W. Texas will recover to make our project in northeast New Mexico commercial. The following factors have negatively impacted the project:

Supply and demand of oil commodity prices, which have declined and not fully recovered and stabilized;

Unstable market has resulted for CO2 used for enhanced recovery in the Permian Basin; and

Informal nature of the current federal policies regarding carbon capture and how that will affect CO2 pricing in the long term.

We Are a Development Stage Company Implementing a New Business Plan

We are a development stage company with only a limited operating history upon which to base an evaluation of our current business and future prospects, and we have just begun to implement our business plan for the development stage prospects.

The Successful Implementation of Our Business Plan is Subject to Risks Inherent in the Oil and Gas Business

Our oil and gas operations are subject to the economic risks typically associated with exploration, development and production activities, including the necessity of significant expenditures to locate and acquire properties and to drill exploratory wells. In addition, the cost and timing of drilling, completing and operating wells is often uncertain. In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause our exploration, development and production activities to be unsuccessful. This could result in a total loss of our investment in a particular property. If exploration efforts are unsuccessful in establishing proved reserves and exploration activities cease, the amounts accumulated as unproved costs will be charged against earnings as impairments.

We Expect Our Operating Expenses to Increase in the Future and May Need to Raise Additional Funds

As our operations grow and develop, so will operating expenses. We have a history of net losses and may incur additional losses and operating expenses over the next 12 months as we continue to develop our business plan. In addition, we may experience a material decrease in liquidity due to unforeseen expenses or other events beyond our control. As a result, we may need to raise additional funds, and such funds may not be available on favorable terms, if at all. If we cannot raise funds on acceptable terms, we may not be able to execute on our business plan, take advantage of future opportunities or respond to competitive pressures or unanticipated requirements. This may seriously harm our business, financial condition and results of operations.

Operational Risks

Other Regulation of the Oil and Gas Industry

The oil and gas industry is extensively regulated by numerous federal, state, provincial, territorial and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies – federal, state, provincial, and territorial – are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply.

Legislation continues to be introduced and revised. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility, security laws or regulations, but such expenditures could be substantial.

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

Operating Hazards and Insurance

The oil and natural gas business involves a variety of operating hazards and risks that could result in substantial losses to us from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation, and penalties and suspension of operations.

In addition, we may be liable for environmental damages caused by previous owners of property we purchase and lease. As a result, we may incur substantial liabilities to third parties or governmental entities, the payment of which could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties.

In accordance with customary industry practices, we maintain insurance against some, but not all, potential losses. We carry business interruption insurance and protection against loss of revenues. Any insurance we obtain may not be adequate to cover any losses or liabilities. We cannot predict the continued availability of insurance or the availability of insurance at premium levels that justify its purchase. We may elect to self-insure if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations.

We are not currently participating in any non-operated wells and accordingly are not exposed to the risks associated with non-operated participation in oil and natural gas operations.

Oil and Natural Gas Properties

We believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry and specific to the jurisdiction that the properties reside.

Although title to these properties is subject to encumbrances, in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry; we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or will materially interfere with our use in the operation of our business. In some cases, lands over which leases have been obtained may be subject to prior liens that have not been subordinated to the leases. In addition, we believe we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects.

Pipeline Rights-of-Way

Substantially all of our gathering systems and pipelines are constructed within rights-of-way granted by property owners named in the appropriate land records. All of our facilities are located on property owned in fee or on property obtained via long-term leases or surface easements.

Our property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not interfered, and we do not expect that they will materially interfere, with the conduct of our business. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. In some cases, not all of the owners named in the appropriate land records have joined in the right-of-way grants, but in substantially all such cases signatures of the owners of majority interests have been obtained. Substantially all permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets, and provincial or state highways, where necessary.

Certain of our rights to lay and maintain pipelines are derived from recorded oil and gas leases for wells that are currently in production, however, the leases are subject to termination if the wells cease to produce. In most cases, the right to maintain existing pipelines continues in perpetuity, even if the well associated with the lease ceases to be productive. In addition, because some of these leases affect wells at the end of lines, these rights-of-way will not be used for any other purpose once the related wells cease to produce.

Seasonal Nature of Business

Seasonal weather conditions, road bans and lease stipulations can limit our development activities and other operations and, as a result, we seek to perform a significant percentage of our development during the summer, fall and winter months. These seasonal anomalies can pose challenges for meeting our well development objectives and increase competition for equipment, supplies and personnel during the summer, fall and winter months, which could lead to shortages and increase costs or delay our operations.

In addition, freezing weather, winter storms, and flooding in the spring and summer may impact operations, which could adversely affect our production volumes and revenues and increase our lease operating costs due to the time spent by field employees to bring the wells back on-line.

Environmental, Health and Safety Matters and Regulation

General

Our operations are subject to stringent and complex federal, provincial and local laws and regulations governing environmental protection as well as the discharge of materials into the environment, the generation, storage, transportation, handling and disposal of wastes, the safety of employees and governing the protection of human health and safety. These laws and regulations may, among other things:

require the acquisition of various permits before exploration or development commences;

limit or curtail some or all of the operations of facilities deemed in non-compliance with permits or other legal requirements;

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling, production, gathering, treating and transportation activities;

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, areas inhabited by endangered or threatened species, and other protected areas; and

require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits, plug abandoned wells, and restore, remediate or mitigate impacted environmental media.

These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, federal, provincial and territorial agencies frequently revise environmental laws and regulations, and the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. The oil and gas industry, in particular, recently has come under greater scrutiny by environmental regulators and non-governmental organizations. Any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for or restrictions, or other regulatory burdens on operations of the oil and gas industry, could have a significant impact on our operating costs.

Waste Management

Waste management is governed by various regulatory agencies enforcing specific federal, provincial, territorial, and state regulations and statutes. These regulatory agencies regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous solid wastes. The Company is strictly compliant and will maintain compliance with all applicable waste management regulations and requirements regarding drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, production and transportation of oil and gas.

Comprehensive Environmental Response, Compensation, and Liability

We currently own, lease or operate numerous properties that have been used for oil and gas exploration, production, and transportation. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. Under such laws, we could be required to remove previously disposed substances and wastes, including wastes disposed of or released by us or prior owners or operators in accordance with the then current laws or otherwise, remediate contaminated property, perform plugging or pit closure operations to prevent future contamination, or take other environmental response actions.

Water Discharges and Water Quality

Water discharge and water quality is governed by various regulatory agencies enforcing specific federal, provincial, territorial, and state regulations and statutes. These regulatory agencies impose restrictions and strict controls with respect to the discharge of pollutants in waste water and storm water, including spills and leaks of oil and other substances, into waters of the province. The Company is strictly compliant and will maintain compliance with all applicable regulations and requirements regarding water discharges and water quality. Spill prevention, control and countermeasure requirements of the regulatory agencies may require appropriate containment berms and similar structures to help prevent any type of fluid discharge in the event of a petroleum hydrocarbon tank spill, rupture or leak.

Our operations also produce waste waters that are disposed via underground injection wells. These activities require a permit and are subject to applicable regulatory agency requirements. Currently, our operations comply with all applicable requirements and have a sufficient number of operating injection wells. However, a change in the regulations or the inability to obtain new injection well permits in the future may affect our ability to dispose of the produced waters and ultimately affect the results of operations.

Air Emissions

Air emissions are governed by various regulatory agencies enforcing specific federal, provincial, territorial and state and regulations and statutes. These regulatory agencies regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Such laws and regulations may require the Company to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain or strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions.

Our Ability to Produce Sufficient Quantities of Oil and Gas from Our Properties May Be Adversely Affected by a Number of Factors Outside Our Control

The business of developing and exploring for and producing oil and gas involves a substantial risk of investment loss. Drilling oil wells involves the risk that the wells may be unproductive or that, although productive, that the wells may not produce oil or gas in economic quantities. Other hazards, such as unusual or unexpected geological formations, pressures, fires, blowouts, loss of circulation of drilling fluids or other conditions may substantially delay or prevent completion of any well. Adverse weather conditions can also hinder drilling operations. A productive well may become uneconomic due to pressure depletion, water encroachment, mechanical difficulties, etc,, which impair or prevent the production of oil and/or gas from the well.

There can be no assurance that oil and gas will be produced from the properties in which we have interests. In addition, the marketability of any oil and gas that we acquire or discover may be influenced by numerous factors beyond our control. These factors include the proximity and capacity of oil and gas pipelines and processing equipment, market fluctuations of prices, taxes, royalties, land tenure, allowable production and environmental protection. We cannot predict how these factors may affect our business.

In addition, the success of our business is dependent upon the efforts of various third parties that we do not control. We rely upon various companies to assist us in identifying desirable oil and gas prospects to acquire and to provide us with technical assistance and services. We also rely upon the services of geologists, geophysicists, chemists, engineers and other scientists to explore and analyze oil prospects to determine a method in which the oil prospects may be developed in a cost-effective manner. In addition, we rely upon the owners and operators of oil drilling equipment to drill and develop our prospects to production. Although we have developed relationships with a number of third-party service providers, we cannot assure that we will be able to continue to rely on such persons. If any of these relationships with third-party service providers are terminated or are unavailable on commercially acceptable terms, we may not be able to execute our business plan.

Market Fluctuations in the Prices of Oil and Gas Could Adversely Affect Our Business

Prices for oil and natural gas tend to fluctuate significantly in response to factors beyond our control. These factors include, but are not limited to actions of the Organization of Petroleum Exporting Countries and its maintenance of production constraints, the U.S. economic environment, weather conditions, the availability of alternate fuel sources, transportation interruption, the impact of drilling levels on crude oil and natural gas supply, and the environmental and access issues that could limit future drilling activities for the industry.

Changes in commodity prices may significantly affect our capital resources, liquidity and expected operating results. Price changes directly affect revenues and can indirectly impact expected production by changing the amount of funds available to reinvest in exploration and development activities. Reductions in oil and gas prices not only reduce revenues and profits, but could also reduce the quantities of reserves that are commercially recoverable. Significant declines in prices could result in charges to earnings due to impairment.

Changes in commodity prices may also significantly affect our ability to estimate the value of producing properties for acquisition and divestiture and often cause disruption in the market for oil producing properties, as buyers and sellers have difficulty agreeing on the value of the properties. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation of projects. We expect that commodity prices will continue to fluctuate significantly in the future.

Risks of Penny Stock Investing

The Company's common stock is considered to be a "penny stock" because it meets one or more of the definitions in the Exchange Act Rule 3a51-1, a Rule made effective on July 15, 1992. These include but are not limited to the following:(i) the stock trades at a price less than five dollars ($5.00) per share; (ii) it is NOT traded on a "recognized" national exchange; (iii) it is NOT quoted on the NASD's automated quotation system (NASDAQ), or even if so, has a price less than five dollars ($5.00) per share; OR (iv) is issued by a company with net tangible assets less than $2,000,000, if in business more than three years continuously, or $5,000,000, if in business less than a continuous three years, or with average revenues of less than $6,000,000 for the past three years. The principal result or effect of being designated a "penny stock" is that securities broker-dealers cannot recommend the stock but must trade in it on an unsolicited basis.

Risks Related to Broker-Dealer Requirements Involving Penny Stocks / Risks Affecting Trading and Liquidity

Section 15(g) of the Securities Exchange Act of 1934, as amended, and Rule 15g-2 promulgated there under by the Commission require broker-dealers dealing in penny stocks to provide potential investors with a document disclosing the risks of penny stocks and to obtain a manually signed and dated written receipt of the document before effecting any transaction in a penny stock for the investor's account. These rules may have the effect of reducing the level of trading activity in the secondary market, if and when one develops.

Potential investors in the Company's common stock are urged to obtain and read such disclosure carefully before purchasing any shares that are deemed to be "penny stock." Moreover, Commission Rule 15g-9 requires broker-dealers in penny stocks to approve the account of any investor for transactions in such stocks before selling any penny stock to that investor. This procedure requires the broker-dealer to (i) obtain from the investor information concerning his or her financial situation, investment experience and investment objectives; (ii) reasonably determine, based on that information, that transactions in penny stocks are suitable for the investor and that the investor has sufficient knowledge and experience as to be reasonably capable of evaluating the risks of penny stock transactions; (iii) provide the investor with a written statement setting forth the basis on which the broker-dealer made the determination in (ii) above; and (iv) receive a signed and dated copy of such statement from the investor, confirming that it accurately reflects the investor's financial situation, investment experience and investment objectives. Pursuant to the Penny Stock Reform Act of 1990, broker-dealers are further obligated to provide customers with monthly account statements. Compliance with the foregoing requirements may make it more difficult for investors in the Company's stock to resell their shares to third parties or to otherwise dispose of them in the market or otherwise.

Our Controls and Procedures Have Not Been Effective and We Have Restated Our Financial Statements

In the fiscal years 2007 and 2008, management has identified issues concerning the effectiveness of our controls and procedures. As a result, it has been determined that they have not been effective. One of the results has been the need to restate the unaudited and audited financial statements for certain periods in 2005 through 2008. The financial statements as originally filed for those periods should not be relied upon.

The Company will take measures to remediate the failures in effectiveness of the controls and procedures. Currently, the Company has plans for certain actions, but they will take time to implement because of their cost. There can be no assurance when remediation will be complete, if at all. Therefore, future reports may have statements indicating that the Company’s controls and procedures are not effective. Additionally, future financial statements may have to be restated if as a result of the ineffectiveness of controls and procedures such future financial statements are inaccurate.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

ITEM 2. PROPERTIES

CANADA

Through Kodiak’s private subsidiary, Cougar Energy, Inc., the Company’s focus is in the definitive projects of:

Cougar Trout Properties, Alberta (Core Area) – farm-in and acquired lands in the Trout, Kidney and Equisetum fields;

CREEnergy Project, Alberta – exploration and development opportunities within the CREEnergy Agreement;

Lucy, British Columbia – Horn River Basin Muskwa shale gas project; and

Other Alberta properties.

Cougar Trout Properties, Alberta (Core Area)

During the third quarter of 2009, Cougar Energy, Inc., the Company’s majority-controlled Canadian subsidiary, completed the following transactions:

Farm-in (completed June 9, 2009) . Completed a farm-in agreement with an unrelated private oil and gas company and acquisitions of producing and non-producing properties from two unrelated private oil and gas companies.

100% working interest in 28 sections of land in the area of the CREEnergy Project, northwest of Red Earth Creek, Alberta – pay 100% to earn 100% with a 3% gross overriding royalty (GOR) upon earning to the vendor.

The mineral rights within the farm-in agreement are currently held under several Alberta Crown 4-year initial term P&NG licenses expiring in September 2010. The rights can be grouped and validated with a drilling program and subsequently continued under a 5 year intermediate term license.

Close to infrastructure consisting of existing pipelines, with capacity, and all weather roads. The target formations should contain sweet natural gas. The existing regional natural gas infrastructure would reduce production and processing charges.

Acquisitions . On September 30, 2009 and October 1, 2009, acquired from an unrelated private company certain wells, facilities and producing operations in and adjacent to the CREEnergy project in Alberta, Canada. The acquisition included 11 producing wells, 21 suspended wells and associated production, water disposal, production facilities and pipelines in the Trout field. Gross production at the time of the acquisition was approximately 170 barrels of oil per day (boe/d). Cougar actively worked during the fourth quarter of 2009 to maximize production and revenue and assessed other opportunities in the area to supplement this initial asset base. The Company negotiated commercial terms for properties that had the greatest upside through normal maintenance and enhanced recovery programs, in addition to the potential for additional drilling. These negotiations culminated at the end of September and beginning of October 2009 with Cougar successfully acquiring the Trout Core Area properties from two private oil and gas companies. These acquisitions represented the Company’s first significant producing resource properties. The Cougar team had high graded many of the properties within these acquisitions and determined potential to increase existing production in the first round of development. Operations commenced on these properties during the winter of 2009/10, consisting of maintenance and work over programs. At the end of 2009, the Company reactivated 4 wells that were previously suspended and completed substantial geological evaluation on the properties. Kodiak negotiated a bridge loan, on behalf of Cougar, for this acquisition. The acquisitions closed September 30, 2009 and October 1, 2009.

Private Company Production and Property Acquisition (completed September 30, 2009)

Approximately 7,100 gross acres of mineral rights with an average 85% working interest (all continued through production and no expiries).

Approximately 125 barrels per day (bbl/d) net production (170 bbl/d gross) and an estimated 85 bbl/d at date of acquisition.

11 pumping wellbores – 8 at time of acquisition – 3 workovers pending partner approval of AFEs.

1 observation wellbore and 21 suspended wellbores.

8 single well batteries, 3 water disposal wellbores with associated facilities, 2 multi well batteries with existing fluid handling capacity in excess of 2,500bbl/day (oil, gas and water handling and treating capability).

Approximately 38.7 km of pipelines (oil and produced water).

Approximately 13 km2 of 3D seismic over the properties and approximately 84 km of 2D seismic over the properties and adjacent lands.

Based on the June 30, 2009 independent look ahead engineering report provided by an independent and private company, the estimated Proved and Probable oil reserves were approximately CAD$7,250,000 (Net Present Value 10% discount).

The agreed purchase price for this acquisition was CAD$6,000,000 with an initial payment of CAD$1,000,000 at closing. The balance of CAD$5,000,000 is payable under a debt instrument consisting of monthly instalments commencing January 1, 2010 and continuing until March 1, 2014. The purchase price was negotiated at $52.50 USD per barrel (/bbl) when oil was selling at plus $75.00/bbl USD. The cash portion of the acquisition cost and subsequent guarantees were provided by Kodiak.

The majority of this acquisition is outside the boundary of the CREEnergy Project lands. At the time of the property acquisition, the surface facilities had a replacement value of CAD$6,500,000 with a depreciated value of CAD$1,000,000. The overall project has an estimated CAD$50,000,000 in sunk costs, including wells, facilities, pipelines, roads and power lines. The substantial infrastructure results in lower overall operating costs, lower development costs and accelerating the operations schedule. Kodiak was able to borrow sufficient funds for the acquisition on behalf of Cougar by way of a bridge loan. Cougar then closed the acquisitions September 30, 2009. This was a critical mass property acquisition as there is substantial infrastructure, resulting in lower overall operating costs, lower development costs and giving our schedule an enormous leap forward to achieve our goals.

Without this kind of infrastructure, the initial production would have lower netbacks due to higher trucking costs and regular non-producing periods due to weather. In lieu of this acquisition, a large amount of capital would have to be spent to bring facilities to this baseline, which we now have. At current costs, the infrastructure replacement value would be substantially in excess of CAD$6,000,000. This capital will now be able to be spent on the drill bit and development work – allowing for a more aggressive growth plan.

Private Company Production and Property Acquisition (completed October 1, 2009)

Approximately 2.560 gross acres of land within and adjacent to the CREEnergy Project area lands.

65% working interest in 6 wells – 2 producing wells and 4 suspended wells located in the Kidney and Equisetum fields and within or adjacent to the CREEnergy Project lands.

Approximately 12 bbl/d net production (20 bbl/d gross) of light oil at time of acquisition.

Based on the April 1, 2009 engineering report provided by an independent and private company, the estimated Proved and Probable oil reserves were approximately CAD$459,000 (Net Present Value – 10%).

The Company, through is private subsidiary Cougar, negotiated a purchase agreement with the private company consisting of cash for the P1 reserves and Cougar shares for the P2 reserves.

Acquired Production and Properties Additional Discussion

The existing infrastructure and initial production on the acquired properties enables the Company to realize higher netbacks and focus on deploying capital to the drill bit and development work. Additional details include:

The existing area field personnel agreed to transfer to Cougar with their many years of hands-on field expertise thereby greatly reducing the risk of downtime due to lack of qualified field personnel.

The existing pipeline systems provides direct access to sales of oil products, which results in the access to sales being in the Company’s control and not third party pipeline operator dependent.

There are 2 batteries for the handling and treating of oil and the disposal of the produced water. The batteries are capable of handling an estimated 2,500 bbl/d with nominal refit costs.

Many of the wells are piped into the batteries to reduce the need for trucking, which is important for the higher water cut wells. These pipelines can be expanded to further lower operating costs.

There are 37 wells, which 13 were producing as of December 31, 2009. The 20 suspended wells are workover or recompletion candidates.

The produced water can be used for future water floods, which regularly have been shown to add substantial incremental production in the area.

As of December 31, 2009, the average production is 125 bbl/d net of light sweet crude oil at an average operating cost of CAD$20.00 to CAD$25.00/bbl.

GLJ Petroleum Consultants Ltd., Reserve Evaluations and Operations Update (October 1, 2009 and December 31, 2009)

These independent engineering reports were prepared by GLJ and are based on the acquisitions of September 30, 2009 and October1, 2009. The reports update the look forward reports that were prepared as part of the negotiations for property acquisitions. Due to the 3rd quarter financial statement cut off at September 30, 2009, only parts of the October 1, 2009 report were included in the 3rd quarter financial statements due to U.S. GAAP rules.

The October 1, 2009 report provided the initial analysis of the consolidated properties in the Trout Field and other Alberta properties acquired at Alexander and Crossfield. The December 31, 2009 report gave the analysis with the initial work programs implemented and plans for the balance of the winter work season.

Thus, we continue to demonstrate our ability to increase reserve value with limited capital infusion and our expectations of the opportunities these properties presented were supported by the reports and the results of the field work.

CREEnergy Project, Alberta

History

Kodiak has a well developed relationship and track record with Aboriginal communities in northern Canada. This comes from a strong commitment by Kodiak management and personnel for open and honest communications and negotiations with the Aboriginal community leaders – a demonstrated respect for their culture, land and residents. Kodiak's reputation has also been recognized through negotiations with regulatory agencies, resulting in several of those agreements being used as templates with other companies and projects. Our reputation has become known outside the far north of Canada.

CREEnergy Oil and Gas Inc. (CREEnergy) is the authorized agent for multiple First Nations communities. Some of these new First Nations communities are in various stages of ratification from the Federal Government of Canada to satisfy outstanding Treaty Land Entitlement (TLE) claims. Within these new First Nations are approximately 15 townships or 540 sections of mineral rights for development in Alberta.

In order to advance economic sustainability for First Nations communities that CREEnergy represents, CREEnergy searched for an oil and gas partner to develop certain oil and gas projects. Kodiak was one of the industry companies shortlisted in the search. Through discussions, meetings and negotiations since May 2008, CREEnergy selected Kodiak as their joint venture partner to develop those resource projects. The joint venture agreement between CREEnergy and Kodiak is the result of the negotiations.

To develop and strengthen the relationship with CREEnergy, Kodiak formed a subsidiary company, Cougar Energy, Inc., to focus on this relationship. As a result, Cougar became the operating entity for Kodiak in Western Canada.

Joint Venture Information and Summary

In December 2008, a strategic alliance and joint venture agreement was established between CREEnergy Oil and Gas Inc. (CREEnergy) and Kodiak Energy, Inc. (Kodiak). The Agreement was built on the foundation of respect for the First Nations communities, their Heritage, their Lands and the Environment. CREEnergy has agreed to work with Kodiak to develop oil and gas reserves within their lands for the benefit of both CREEnergy and Kodiak.

Joint Venture Agreement

Key priorities were established from the discussions between CREEnergy and Kodiak:

Use the royalties from the oil and gas production and work programs to develop a revenue stream. The long term purpose of the revenue is to support education, employment and development opportunities for the First Nations communities that Cougar is working with.

Open communication at all stages of the oil and gas developments.

Staged and managed growth, with regard to the interests of the communities during each step.

Identify and source other development opportunities, using a similar model, either as a value add or on a joint venture basis.

Lucy, Northern British Columbia

Cougar Energy, Inc is the operator and 80% working interest owner of a 1,920 acre lease located in Northeastern British Columbia. The Company believes the lease is situated on the southeast edge of the Horn River Basin and the Muskwa Shale gas prospect. Industry continues to show increased interest in this shale gas play with several comparisons of the Muskwa Shale gas potential as an analogue of the Barnett Shale gas potential.

The Company has been involved in two previous drilling operations on the lease. In the fourth quarter of 2006, Kodiak farmed in as a non-operated partner, paying 10% to earn 7.5%, on a drilling operation in the Lucy (Gunnell) area. This first drilling operation, designed to target a Middle Devonian reef prospect, had several operational problems and was unsuccessful.

After performing an internal review of seismic and drilling data, it was determined that there was a seismic anomaly on the southern half of the lease. This anomaly was identified on several different seismic lines and a decision was made to drill a well on that part of the lease to evaluate both the anomaly as the primary target and the Muskwa Shale, seen in the first well but not evaluated by the operator at that time.

In the third quarter of 2007, the Company served its partners with an independent operations notice which resulted in the Company increasing its working interest in the lease to 80%.

In the first quarter of 2008, a second drilling operation was completed and a vertical well was cased. It was determined that the Middle Devonian seismic anomaly was not a reef buildup and the wellbore was cased due to encountering significant gas shows in the previously identified Muskwa Shale with a formation thickness of approximately sixty meters.

The Company submitted an application to the British Columbia Oil & Gas Commission (“OGC”) for an experimental scheme to test the Muskwa Shale gas potential. On August 12, 2008, Kodiak received the final approval of the Lucy experimental scheme application. The Company has prepared a multi-phase work program designed to test the deliverability of the Muskwa Shale gas formation using vertical and horizontal drilling and completion techniques. Kodiak’s proposed work program would allow for early production into a pipeline in order to monitor long-term deliverability rates and pressures of horizontal and vertical test wells on the periphery of the Horn River Basin.

These results would be some of the first commercial production results for a Horn River Basin shale gas project and would provide information that would help define the effective exploration area of the Basin and assist in the validation of adjoining properties in a divestiture process, should that occur.

Kodiak engaged an industry-recognized shale gas assessment laboratory to prepare and analyze the drill cuttings from the 2008 well in order to evaluate the Muskwa Shale interval for gas potential. The shale gas assessment is conducted by performing various tests on the rock cuttings that were obtained while drilling the well in order to determine the type, quality and amount of both adsorbed and free gas.

The most important conclusion from the drill cutting analysis is that the information received continues to support the evaluation of Kodiak’s Muskwa (Evie) Shale gas prospect. The laboratory data is consistent with other public industry and government data on the Muskwa Shale. It should also be noted that the numbers obtained on the laboratory analysis of drill cuttings may be conservative due to the nature of sampling drill cuttings on a drilling rig. Another significant point is that all three wells on the Kodiak lease, drilled deep enough to penetrate the Muskwa Shale, had elevated gas detector readings while penetrating the shales.

The prospect is still in the early stages of delineation and no assurance can be given that its exploitation will be successful. Further appraisal work is required before these estimates can be finalized and commerciality assessed.

The severe turn down in gas prices over the past year has made natural gas projects difficult to show returns on investment – especially high capital cost projects such as those in the Horn River Basin – despite the very large reserves and recovery rates attributed to the Muskwa shales. The current $3 to $5 gas prices limit the return for this project in the short term and the availability to obtain development financing.

The current intention is to perform the following work commitments for the license (as new information and financing becomes available, the plans may be revised). In lieu of obtaining our own financing, we are actively enlisting JV partners to move the project forward by way of divesting part of our interest.

Perforate the Muskwa intervals, perform a vertical shale gas fracture treatment, test and evaluate pressures and production and, if economic, equip and tie in well to an existing pipeline approximately 1 Km from the wellhead; and

Drill and case a 1,000 meter horizontal leg from an existing cased vertical well on the lease, perform a horizontal staged fracture treatment, test and evaluate pressures and production and, if economic, equip and tie in well to pipeline.

In April 2009, Kodiak, through its subsidiary, Cougar, entered into a standard farm-out and participation agreement with one of its partners. The partner would provide 90% of the funding for the first phase of the “Lucy” Horn River work program. Upon completion of the funding, the partner will have earned an additional 30% working interest in the wells and property. Cougar will maintain operator status and majority ownership of the project with the management of Kodiak/Cougar overseeing the execution of the work program. Upon fulfillment of the funding provisions of the farm-out and participation agreement, Cougar’s working interest in the “Lucy” Horn River Basin project would be 50%.

Our partner did not complete its financing commitment and this farm-out and participation agreement expired on August 15, 2009. After due diligence was completed in October, 2009, the partner transferred its interest in its Alexander and Crossfield, Alberta wells to the Company as a penalty for non-completion (see below).

Cougar Central Alberta Producing Properties, Alberta

Private Company Production and Property Acquisition (completed October 1, 2009)

2 producing oil properties in the Crossfield and Alexander fields in Central Alberta.

100% working interest in the Crossfield property – 1 producing well with single well battery with approximately 5 barrels per day (bbl/d) net production – production continues to be stable with no capital commitment required.

55% working interest in the Alexander property – 1 shut in oil well with a single well battery, 1 suspended well. Expected production of approximately 10 bbl/d net production upon restarting shut in oil well after spring break up.

In August, 2009, it was determined that Cougar’s working interest partner in the Lucy, B.C. project was unable to complete the financing as required in the farm-out agreement and as a result, in October after due diligence and environmental reviews, Cougar has accepted the transfer of the partner’s Alexander and Crossfield, Alberta properties as a penalty payment. The properties received are valued at approximately $500,000 CAD (NPV 10% escalated pricing). Cougar has assumed asset retirement obligations in connection with the properties estimated at $50,000 CAD. The properties have an estimated potential average production of 15 boe/d.

Production from the Company’s new proved reserves commenced on October 1, 2009 and recognition of the associated revenue and cash flow began on that date.

Little Chicago, Northwest Territories

The Company is the operator and largest working interest owner of the 201,160 acre Exploration Licence 413 (“EL 413”) in the Mackenzie River Valley centered along the planned Mackenzie Valley Pipeline.

In 2006, the Company signed an exploration farm-in agreement with the two 50% working interest owners of EL 413. The Company reprocessed 50 km of existing seismic data in Q4 of 2006 and during the 2006-07 winter work season, the Company shot and acquired 84 km of high resolution proprietary 2D seismic and gravity survey data on the farm-out lands, thus earning a 12.5% working interest in the property. In September, 2007, the Company acquired Thunder River Energy, Inc.’s (“Thunder”) remaining 43.75% in the property giving the Company a 56.25% interest in EL 413. A letter of intent signed earlier in 2008 with the Company’s remaining partner in the project, which would have allowed Kodiak to acquire the balance of the working interest in EL 413 and become a 100% working interest owner, recently expired.

A 2007/08 43 km 2D high resolution proprietary seismic program and gravity survey was completed on the property and the results were processed and interpreted and used to support the Company’s planned drilling program. This project was completed on budget and schedule. The seismic and gravity data from the two projects show substantial structural closure and formation character and support the planning for a future multiple well drilling program. That data was included in an updated Chapman Prospective Resource report published in May, 2008.

The decision to acquire additional seismic and gravity data in the winter of 2007/08 was made to improve the potential to drill both the Devonian Bear Rock and the Basal Cambrian Sand targets from a common drilling site. This would substantially lower drilling costs on a per well basis and reduce the overall project risk.

Kodiak has analyzed the 2007/08 seismic data and the various reservoir indicators/lands and identified 11 drill locations. These drill locations have been selected to evaluate three primary target formations on EL 413 including the Devonian Bear Rock Oil Prospect, the Basal Cambrian Sand /Top Precambrian Oil and Gas Prospect and the Canol Oil Prospect. These locations have been further high graded into a two phase drilling program consisting of two wells with a planned total depth of 2400 meters each targeting both the Basal Cambrian/Precambrian and the Bear Rock prospects and a multi-well shallow drilling program with a planned total depth of 400m each targeting the Canol prospect. A scouting trip was completed in the third quarter of 2008 that allowed the Company to review potential access routes, well sites and camp locations.

The Devonian Bear Rock Prospect (“Bear Rock”) is the first described target and is located at a shallow depth of approximately 700 meters (2,300 ft.). This reservoir was previously identified and preliminarily evaluated in the initial Chapman Report prepared in 2005. The expected product from the reservoir is light and medium oil, with no consideration to solution gas.

The combined seismic obtained during 2007 and 2008 acknowledged a series of pools distributed throughout the project. The Chapman Report identified fifteen Bear Rock leads located along the seismic lines with five of them being selected as well defined high grade Bear Rock leads. This is an increase of 5 additional leads from the initial 2007 work program. Indicators of these potentially prolific reservoirs are present along several seismic lines that may imply these Bear Rock occurrences to be present throughout EL 413.

The additional 2008 seismic further defined a hydrocarbon trap in the Basal Cambrian Sand sitting on the top of the Precambrian. This interval, found at a depth of approximately 2,300 meters (7,545 feet), has never been regionally penetrated and tested; however, it has been proven as a productive reservoir in the Colville Hills area approximately 125 kilometers (77 miles) east of EL 413. With this additional data, the Chapman Report identified five drilling locations that will allow the Basal Cambrian Sand and the top of the Precambrian to be drilled and tested.

Physical evidence of hydrocarbons is present with a natural surface oil seep on the northern edge of the license area on the banks of the Mackenzie River. This natural occurrence is suggestive of a shallow oil pool, possibly in the Canol formation, and warrants further investigation. While reviewing core samples and well logs from previous regional drilling activity, Kodiak was able to map out the Canol/Imperial formation and determine that it is the likely source of the natural surface seeps. This prospect will be found on the Northwest quarter of EL 413 and is at a very shallow depth of approximately 350 meters (1,148 feet). The Company has identified 5 drilling locations which will be evaluated during a planned future project drilling program.

Kodiak is preparing for the previously mentioned drilling program and has commenced work on the necessary permits and applications. The Company is working with the Sahtu and the Gwich’in, which are the beneficiaries of the land claims containing the EL 413 licence. The Company does not believe there will be any difficulty finishing the Access and Benefits Agreement prior to submitting the final applications to the regulators for approval. The Company is currently in discussions with other industry partners to share in the costs of the drilling programs, thus reducing risk and capital commitments. Financing plans will be finalized when overall partnerships are established. Kodiak intends on retaining operatorship.

In addition, Kodiak had made application with regulators to extend the EL 413 license and has received written notification from Indian and Northern Affairs Canada that a one year extension is available. The one year license extension, which is subject to certain terms and conditions, was provided just prior to expiry and provides for one additional year.

Upon review of the overall status of all projects in the area, current commodity prices being much below levels required to justify development on this and other projects, continued delay of the Mackenzie Valley Pipeline Project, the risk that any discovered gas reserves would be indefinitely stranded without such development, the Company continues to seek partnership in the development; however, the deteriorating economic factors make this difficult. We will still retain the confidential proprietary seismic data for future assessment of the "Little Chicago Prospect" and the Company will determine the best way to monetize that asset through either divestiture and/or possibly renominating the prospect when conditions are more appropriate.

Province/Granlea, Southeast Alberta

The Company purchased a 50% working interest in two sections (1280 acres gross - 640 net) of P&NG rights at a provincial land sale on September 22, 2005. In 2005, a 2D seismic program was completed on the property and in 2006, a well was drilled and completed; surface facilities were installed and a pipeline tie-in was completed. Production commenced in September, 2006. The well produced for a short period until excess water rates occurred and in October, 2006 the well was shut in. After the well bore was evaluated as having n o current economic production potential, the well was abandoned. An internal geological review of the prospect will be done to determine if any further drilling is warranted.

UNITED STATES

New Mexico

Through its acquisition of Thunder, the Company acquired a 100% interest in 55,000 acres of property located in northeast New Mexico. Additional land acquisitions have increased the Company’s land position to approximately 79 ,000 acres. These lands have potential for natural gas and CO2 and oil and helium resources at shallow depths. In 2008, the Company purchased 19,000 stations of gravity data and 37 miles of trade seismic data, completed a 35 mile 2D high resolution proprietary seismic program and a three well drilling program.

The three wells were drilled with air to reduce formation damage and they were cased to the base of the Yeso formation. Based on gas detector results, drill cutting samples and open hole logs, all wells showed three potential shallow porous sandstone formations capable of CO2 production with up to 200 feet of identified net pay thickness. The Yeso, Glorieta and Santa Rosa formations were perforated and flow tested to determine deliverability and pressure. There were multiple gas samples analyzed at specialized independent laboratories from two separate extended flow tests that identified CO2 concentration quality from 98.4% to 99.5%. Two of the wells were stimulated with a nitrified acid squeeze and were able to sustain an extended flow rate of approximately 375mcf/d. The shallow sands have been mapped using offset well control and the newly acquired seismic data and the Company has determined there is a very high likelihood of encountering the target formations throughout the leased project area; provided, however, that no assurance can be given that this will be the case.

The 35 mile 2D high resolution seismic program was completed on schedule and on budget and after reviewing the seismic data, the Company was able to effectively map out a probable long term development area which would result in CO2 production from the previously identified formations. The seismic is currently being evaluated to identify possible conventional oil and gas prospects on the leased project area.

A preliminary project feasibility study was commissioned to identify capital development costs and timelines as well as projected operating costs in order to provide information to support a large scale long-term plan of development. This information will enable the definitions for pipeline access planning and negotiation, transportation agreements, sales contracts for the CO2, additional land acquisition terms and conditions, facility engineering and construction and ultimately the parameters for financing the project development.

Several companies have expressed interest in participating in the New Mexico properties at several levels of involvement. Discussions are still ongoing with several firms regarding potential opportunities for the project, including integration of the CO2 production into Permian Basin enhanced oil recovery projects and the Company has also entered into farm-out negotiations with several companies interested in exploring deeper oil and natural gas prospects on the properties.

Due to lower commodity prices for Permian Basin oil (the primary market for CO2) and CO2 contract prices (deliverable into the Denver City Hub), aggressive development is not financeable at this time. Aside from ongoing maintenance of leases and wells, the Company is focusing its efforts on updating engineering models, and business opportunities so that when prices recover and investment markets improve, we will have the opportunity to move this project forward. The leases are 10 year leases and no expiries are imminent.

Montana

During 2006, the Company, under a joint venture farm-out agreement, participated in a seismic acquisition program, and a two well drilling program to earn a 50% non-operating working interest in the wells and well spacing. This joint venture project provides the Company with the right to participate on a 50% basis going forward on this prospect in the Hill County area of Montana. The operator of the project had 60,000 contiguous undeveloped acres of P&NG rights in the area, as well as some excess capacity in facilities and pipelines. Two wells were drilled in the third quarter of 2006; one is cased for subsequent evaluation of the multiple zones found and one was abandoned. In order to facilitate the efficient exploration of this prospect area, the Company acquired from the original operator a 100% working interest of 12,000 acres of P&NG rights while retaining the right to participate and initiate operations on the remaining approximate 48,000 acres of prospect leases. After an internal geological review of this prospect, and in light of current commodity prices, the Company, in the fourth quarter of 2008, wrote off its costs relative to this project and subsequently, in 2009, the Company has allowed the acreage to expire.

OIL AND GAS PROPERTIES

The Company currently has one core producing property in Canada of developed acreage and four properties in Canada and two in the United States comprising of undeveloped land holdings on which it is carrying out exploration activities.

PRODUCING AND NON-PRODUCING WELLS as at December 31, 2009
	Oil Wells		Natural Gas Wells		Service Wells		Total
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Canada Producing	15.0	10.83	0	0	0	0	15.0	10.83
Canada Non-producing	36.0	28.35	3.0	1.375	4.0	3.36	43.0	33.085
U. S. Producing	0	0	0	0	0	0	0	0
U.S. Non-producing	0	0	5.0	4.0	0	0	5.0	4.0
Total Producing	15.0	10.83	0	0	0	0	15.0	10.83
Total Non-producing	36.0	28.35	8.0	5.375	4.0	3.36	48.0	37.085

Land Acreage

Following is a summary of the Company’s land holdings in gross and net hectares:

LAND HOLDINGS WITH ATTRIBUTED RESERVES as at December 31, 2009
	Developed Properties (Acres)		Developed Properties (Hectares)
	Gross	Net		Gross	Net
Canada	8,000	5,764		3,237	2,333
U.S.	0	0		0	0
Total	8,000	5,764		3,237	2,333

LAND HOLDINGS WITHOUT ATTRIBUTED RESERVES as at December 31, 2009
	Undeveloped Properties (Acres)		Undeveloped Properties (Hectares)
	Gross	Net		Gross	Net
Canada	202,016	111,842		81,753	45,261
U.S.	62,441	62,441		25,269	25,269
Total	264,457	176,453		107,022	71,408

A developed property is considered to mean those acres/hectares spaced or assignable to productive wells, a gross acre/hectare is an acre/hectare in which a working interest is owned, and a net acre/hectare is the result that is obtained when fractional ownership working interest is multiplied by gross acres/hectare. The number of net acres/hectares is the sum of the factional working interests owned in gross acres/hectares expressed as whole numbers and fractions thereof.

An undeveloped property is considered to be those lease acres/hectares on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas and does not include undrilled acreage held by production under the terms of a lease. As is customary in the oil and gas industry, we can generally retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by paying delay rentals during the remaining primary term of such a lease. The oil and natural gas leases in which we have an interest are for varying primary terms, and if production continues from our developed lease acreage beyond the primary term, we are entitled to hold the lease for as long as oil or natural gas is produced.

OFFICE PROPERTY

During December, 2009, Kodiak Energy, Inc. relocated its offices to 833 4th Avenue S.W., Suite 1122, Calgary, AB, T2P 3T5. We lease offices on a 3 year term, expiring in February of 2013. The current lease is approximately $14,000 CAD per month.

ITEM 3. LEGAL PROCEEDINGS

From time to time, the Company may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm our business. The Company is currently not aware of any such legal proceedings that the Company believes will have, individually or in the aggregate, a material adverse affect on our business, financial condition or operating results.

ITEM 4. [RESERVED]

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

MARKET INFORMATION

The Company's common shares are currently quoted on the Over the Counter Bulletin Board under the symbol KDKN. On December 24, 2007, the Company's common shares commenced trading on the Toronto Venture Stock Exchange in Canada under the symbol KDK. On November 4, 2009, The Company voluntarily requested the TSX Venture Exchange ("TSX-V") in Canada to delist its common shares from trading on the TSX-V. See "PART II, Item 9B. Other Information" in this Form 10-K for further information on the delisting. Trading ranges of the Company’s common shares by quarter for fiscal 2009 and 2008 were as follows:

	Over the Counter						Toronto
	Bulletin Board						Venture Exchange
	(U. S. Dollars)						(Canadian Dollars)
	High			Low			High			Low

Year ended December 31, 2009
First Quarter		$	0.64			0.32		$	0.70			0.37
Second Quarter		$	0.41			0.12		$	0.52			0.17
Third Quarter		$	0.77			0.25		$	0.88			0.21
Fourth Quarter		$	0.72			0.23		$	0.75			0.30


Year ended December 31, 2008
First Quarter		$	2.51		$	1.36		$	2.56		$	1.40
Second Quarter		$	3.08		$	1.46		$	3.10		$	1.50
Third Quarter		$	2.40		$	0.75		$	2.29		$	0.81
Fourth Quarter		$	0.95		$	0.41		$	0.97		$	0.51

The Company has not paid cash dividends since inception. The Company intends to retain all of its earnings, if any, for use in its business and does not anticipate paying any cash dividends in the foreseeable future. The payment of any future dividends will be at the discretion of the Board of Directors and will depend upon a number of factors, including future earnings, the success of the Company's business activities, capital requirements, the general financial condition and future prospects of the Company, general business conditions and such other factors as the Board of Directors may deem relevant.

As at December 31, 2009 there were 110,407,186 shares of common stock issued and outstanding and there were approximately 12,124 holders of record of our common stock.

EQUITY COMPENSATION PLAN INFORMATION

The following table sets out information with respect to compensation plans under which equity securities of our Company were authorized for issuance as of December 31, 2009.

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options Warrants and Rights (#)	Weighted-Average Exercise Price of Outstanding Options Warrants and Rights ($)	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (#)
Equity compensation plans approved by security holders	8,490,000	1.41	1,940,000
Equity compensation plans not approved by security holders	--	--	--
Total	8,490,000	1.41	1,940,000

ITEM 6. SELECTED FINANCIAL DATA

None.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION

FORWARD LOOKING STATEMENTS

From time to time, we or our representatives have made or may make forward-looking statements, orally or in writing. Such forward-looking statements may be included in, but not limited to, press releases, oral statements made with the approval of an authorized executive officer or in various filings made by us with the Securities and Exchange Commission. Words or phrases "will likely result", "are expected to", "will continue", "is anticipated", "estimate", "project or projected", or similar expressions are intended to identify "forward-looking statements". Such statements are qualified in their entirety by reference to and are accompanied by the above discussion of certain important factors that could cause actual results to differ materially from such forward-looking statements.

Management is currently unaware of any trends or conditions other than those mentioned elsewhere in this management's discussion and analysis that could have a material adverse effect on the Company's consolidated financial position, future results of operations, or liquidity. However, investors should also be aware of factors that could have a negative impact on the Company's prospects and the consistency of progress in the areas of revenue generation, liquidity, and generation of capital resources. These include: (i) variations in revenue, (ii) possible inability to attract investors for its equity securities or otherwise raise adequate funds from any source should the Company seek to do so, (iii) increased governmental regulation, (iv) increased competition, (v) unfavorable outcomes to litigation involving the Company or to which the Company may become a party in the future and, (vi) a very competitive and rapidly changing operating environment. The risks identified here are not all inclusive. New risk factors emerge from time to time and it is not possible for management to predict all of such risk factors, nor can it assess the impact of all such risk factors on the Company's 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. Accordingly, forward-looking statements should not be relied upon as a prediction of actual results.

The financial information set forth in the following discussion should be read in conjunction with the consolidated financial statements of Kodiak Energy, Inc. included elsewhere herein.

PLAN OF OPERATION

Canada

Through Kodiak’s private subsidiary, Cougar Energy, Inc., the Company’s focus is in the definitive projects of:

Cougar Trout Properties, Alberta (Core Area) – farm-in and acquired lands in the Trout, Kidney and Equisetum fields;

CREEnergy Project, Alberta – mineral leases, exploration and development opportunities within the CREEnergy Agreement and several current and proposed Northern Alberta Treaty Land Entitlement Claims;

Lucy, British Columbia – Horn River Basin Muskwa shale gas project; and

Other Alberta properties.

The Company expects to finance its future capital expenditure programs and acquisitions with combinations of revenue from current operations, debt instruments, farm-outs, equity financings and divestitures, depending upon what vehicle is appropriate to the capital program/acquisition and the overall market economy. A 6 to 12 month payback will be used to benchmark all such capital programs for financing purposes. A brief description of the Company’s properties and activities is described below. For a more detail description of the properties to better understand the planned operations – refer to Item 2. Properties.

Cougar Trout Properties, Alberta (Core Area)

The following is a summary of the various properties plan of developments:

Farmin (June 2009) . A 100% working interest in 28 sections of land in the area of the CREEnergy Project, northwest of Red Earth Creek, Alberta – pay 100% to earn 100% with a 3% gross overriding royalty (GOR) upon earning to the vendor.

A drilling program has been prepared for one initial well and two subsequent wells. Contingent upon financing, this program will be evaluated and funds allocated to the best net back between this gas project and the other oil developments. A minimum 18 month payback criteria will be used prior to assigning capital to this project.

Private Company Production and Property Acquisitions (2009) . The existing infrastructure and initial production on the acquired properties enables the Company to realize higher netbacks and focus on deploying capital to the drill bit and development work. Additional details include:

The existing pipeline systems provides direct access to sales of oil products, which results in the access to sales being in the Company’s control and not third party pipeline operator dependent.

There are 2 batteries for the handling and treating of oil and the disposal of the produced water. The batteries are capable of handling an estimated 2,500 bbl/d with nominal refit costs.

Many of the wells are piped into the batteries to reduce the need for trucking, which is important for the higher water cut wells. These pipelines can be expanded to further lower operating costs.

There are 37 wells, which 13 were producing as of December 31, 2009. The 20 suspended wells are workover or recompletion candidates.

The produced water can be used for future water floods, which regularly have been shown to add substantial incremental production in the area.

As of December 31, 2009, the average production is 125 bbl/d net of light sweet crude oil at an average operating cost of CAD$20.00 to CAD$25.00/bbl.

Subsequent Maintenance and Development Programs

Prior to the production and property acquisitions, the Company conducted a detailed review of the properties in public domain petroleum records over last 5 to 7 years and with a comparison to other operators in the area. The Company’s operations and geological teams have determined a strong potential to increase production through normal maintenance activities. These activities include utilizing existing technologies that have proven success in similar maintenance programs in the area. Some of these normal maintenance activities include and are not limited to:

Acid wash of perforations

Setting of bridge plugs to seal off water

Cleanouts

Re perforating

Drill out plugs and open up previously unproduced zones

Repairs to wells with separated rods

Plug off water sources with no resulting loss of production – ongoing

Pump and well site equipment optimization – ongoing

Waterflood programs – future

Horizontal drilling – future

Use of low damage drilling fluids – future

Continued Development of the Trout Area Through Systematic Operational Controls

As we develop our maintenance program through the Trout Area lands in north central Alberta, we will continue to utilize our economical model to drive efficiency and minimize costs. We will focus our maintenance program on industry best practices and continued technological enhancements to maximize our return on assets and capital deployed.

Consolidate the Trout Area

To further enhance our economies of scale, we intend to be aware of other acquisition opportunities in the area. Consistent with our strategy to improve our financial flexibility, we intend to make acquisitions utilizing either equity and/ or debt instruments.

Develop Trout Area Assets

We intend to prudently develop this acreage position by redeploying cash flow generated from area operations. We are currently evaluating a series of developmental drilling locations in addition to several step out drilling locations with the goal of adding incremental reserves and cash flow. As we are focused on locations in areas with existing infrastructure, we expect our development plan to have a near-term material impact on our proved reserves and production. We believe investing in this area is the most expedient way for us to improve our financial flexibility and return on capital.

CREEnergy Project

Current Status

Cougar continues to actively work with CREEnergy as they assist their First Nations communities to achieve the goal of independence though the Treaty Land Entitlement (TLE) claim with the Federal Government of Canada and the Province of Alberta. Although delayed several times due to regulatory processes, this process is nearing completion.

We endeavor to engage with CREEnergy on a weekly basis through conference calls, status email and other written communication, monthly in person status meetings, and a continual dialogue to foster open communication.

At this time Cougar Energy is under negotiations to vend part of their mineral leases located within the TLE claim to CREEnergy for fair market value, to provide direct ownership and participation to the communities in the Oil and Gas mineral rights and associated operations.

This proposed transaction will continue to provide positive growth for the relationship going forward and will provide cash flow opportunities for CREEnergy and thus the communities.

Due to delays in the land claim process, and in order to move Cougar Energy forward in the interim, Cougar looked to other opportunities in the Red Earth area. .

Lucy, Northern British Columbia

Depending upon commodity prices – the severe turn down in gas prices over the past year have made natural gas projects difficult to show returns on investment – especially high capital cost project such as the Horn River Basin – despite the very large reserves and recovery rates attributed to the Muskqua shales. The current $4-$5 gas prices limit the return this project in the short term and thus the financing availability.

The current intention is to perform the previously planned work programs for the license (as new information and financing becomes available, the plans may be revised). In lieu of obtaining our own financing, we are actively enlisting JV partners to move the project forward by way of divesting part of our interest.

Cougar Central Alberta Producing Properties

Private Company Production and Property Acquisition (completed October 1, 2009)

2 producing oil properties in the Crossfield and Alexander fields in Central Alberta.

In Summary

The Company plans to aggressively develop and explore its newly acquired Cougar assets. A maintenance and development program is planned for the winter work season which is expected to result in production increased to approximately 250 barrels of oil per day (net). Addition maintenance programs will be initiated in post break up through into the following winter. Drilling programs will be planned for the fourth quarter of 2010 where the seismic data supports the effort and expense and further drilling will be based on the results of the initial wells.

Little Chicago – Northwest Territories

The Company is the operator and largest working interest owner of the 201,160 acre Exploration License 413 (“EL 413”) in the Mackenzie River Valley centered along the planned Mackenzie Valley Pipeline.

Province/Granlea – Southeast Alberta

No budget is assigned to this prospect.

UNITED STATES

New Mexico

FINANCIAL INFORMATION

Financial Condition and Changes in Financial Condition:

The Company’s total assets have decreased to $31,657,559 as at December 31, 2009 from $37,171,397 as at December 31, 2008, and from $38,190,768 at the end of 2007. This 2009 decrease is the net difference between the increase in the value of the Company’s Canadian assets due to a increase in the value of the Canadian dollar from the end of 2008 to December 31, 2009 and its 2008 capital expenditures and acquisitions. As well as write-downs of its unproved properties of approximately $17,463,508. Had this currency revaluation loss not occurred, total assets would have increased by approximately $4 million resulting from increased capital expenditure programs undertaken by the Company, as well as the acquisition described under “Property Acquisition” and the financings described under “Liquidity and Capital Resources”. Total assets consist of cash and other current assets of $557,355 (December 31, 2008 - $245,562).

For the first time, the Company had included in oil and gas properties evaluated and unevaluated properties. Evaluated properties net of accumulated depreciation, depletion and amortization was $4,657,406 (December 31, 2008 - $Nil). Unevaluated properties decreased to $26,081,783 from $36,559,367 on December 31, 2008. The major difference is the transfer assets from unevaluated to evaluated and the write-down of assets of $17,463,508. Included in this total write-down for the year was $1,653,263 for a year end ceiling test.

The Corporation reports its reserves in the United States based on a “constant pricing and cost assumptions” model to meet US GAAP requirements and the values shown in that portion of the GLJ report and the resultant differences are due to those base assumptions.

In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 reserve information. In January 2010, the FASB issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. We adopted the guidance as of December 31, 2009 in conjunction with our year-end reserve report as filed in the US, as a change in accounting principle that is inseparable from a change in accounting estimate. Under the SEC’s final rule, prior period reserves were not restated.

For the United States, the primary impacts of the SEC’s final rule on our reserve estimates include: The use of the unweighted 12-month average of the first-day-of-the-month reference price of $58.21 USD per barrel for oil compared to average consolidated revenue of $74.20 USD per barrel received for the months of October, November and December 2009, when we had sales. Thus, a price point was used for calculations of reserves and impact on long term liabilities, which was 78% of actual – thus our comments as to subjective price points and that effect on estimates.

Other assets of $296,153 remained as of December 31, 2009 (December 31, 2008 - $290,903).

Our total current liabilities were $4,451,528 (December 31, 2008 - $1,140,273) and consisted of accounts payable and accrued liabilities relating to capital activities and general and administrative costs incurred. Also included in current liabilities were Notes payable of $1,364,036 (December 31, 2008 – $Nil) and Current portion of long term debt of $538,831 (December 31, 2008 – $Nil).

We had long term liabilities of $3,400,489 (December 31, 2008 - $39,262). This increase was due to the acquisition made in the third quarter of 2009. See Cougar Core Trout properties in Section 2. Asset retirement obligations of $1,285,614 (December 31, 2008 - $199,574) were recorded at year end. The increase is a result of the third quarter acquisition and the company’s transfer of assets from unevaluated to evaluated.

Shareholders’ equity amounted to $22,261,801 (December 31, 2008 - $35,792,288), net of an accumulated deficit of $28,283,170 (2008 - $8,710,088) and comprehensive loss of $416,905 (December 31, 2008 - $4,903,762). Non controlling interest was $258,127 (December 31, 2008 – $Nil).

Overall Operating Results (All dollar values are expressed in United States dollars unless otherwise stated)

In 2009, the Company had income during the period of $607,469 (2008 - $1,065; 2007 - $225) and operating costs of $418,218 (2008 - $9,646; 2007 - $ 20,543) relating to start up of production from its Trout, Alberta project in the fourth quarter of 2009. The Company has now moved from an exploratory stage to a production company.

Net Loss for the year ended December 31, 2009 totaled $19,573,082 (2008 - $2,074,649; 2007 - $2,571,662). These losses include general and administrative expenses of $2,219,441 (2008 - $2,206,015; 2007 - $2,470,230). which includes stock-based compensation expense amounting to $774,199 (2008 - $674,226; 2007 - $643,934); interest expense of $106,612 (2008 - $1,417; 2007 - $94,083); depletion depreciation and accretion including ceiling test impairment write-downs of $ 18,317,295 (2008 - $923,097; 2007 - $218,841) and deferred income tax recoveries of $NIL - (2008 – $978,835; 2007 - $147,000).

General and administrative expenses include the cost of consulting personnel and others who provided investor relations services, public company costs for SEC reporting compliance, accounting, audit and legal fees and other general and administrative office expenses. General and administrative expense also includes stock-based compensation relating to the cost of stock options granted to directors, officers and other personnel of $774,199 in 2009 (2008 - $674,226; 2007 - $643,934). General and administrative costs have been increasing, as the scope of the company’s activities have increased, and we believe substantial amounts will continue to be spent on such costs in the near term as we progress with the evaluation of our oil and gas prospects. A significant increase in our shareholder base from 7,000 to approximately 12,000 shareholders during the past year has also contributed to our increased general and administrative costs.

Interest expense for the year ended December 31, 2009 was $106,612 (2008 - $1,417; 2007 - $94,083).

Depletion, depreciation and accretion including ceiling test impairment write-downs includes the cost of depletion and depreciation relating to production from producing properties in 2009, ceiling test impairment write-downs and the cost of depreciation relating to office furniture and equipment. Costs attributable to certain Canadian cost center properties were determined to be unsupportable and, as a result, ceiling test write-downs of $18,168,878 for 2009 (2008 - $370,980; 2007 - $174,380) relating to the Company’s Canadian cost center were recorded and included in this expense. Costs attributable to certain United States cost center properties were determined to be unsupportable and, as a result, ceiling test write-downs of $498,867 for 2008 (2008 - $498,867; 2007 - $Nil) relating to the Company’s United States cost center were recorded and included in this expense. The remaining capitalized costs relating to Canadian and United States unproven properties have been excluded from the depletable cost pools for ceiling test purposes.

Quarterly Information

In the fourth quarter of 2009, Kodiak began economic production on its evaluated proven assets. The following table show selected quarterly information for this production. As this was the first quarter of production, there are no comparisons for prior quarters or years.

Kodiak Energy Inc.
Consolidated Production Volume Schedule
Total Production boe
Production By Product	Q4 2009	Q3 2009	Q2 2009	Q1 2009	YTD 2009
Light Oil (bbls)	10,323.8	-	-	-		10,323.8
Natural Gas (mcf)	-	-	-	-		-
Total (boe/d) (6:1)	10,323.8	-	-	-		10,323.8

Production By Area (boe)	Q4 2009	Q3 2009	Q2 2009	Q1 2009	YTD 2009
Trout	10,319.4	-	-	-		10,319.4
Crossfield	4.4					4.4
Total (boe/d) (6:1)	10,323.8	-	-	-		10,323.8

boe/d
Production By Product	Q4 2009	Q3 2009	Q2 2009	Q1 2009	YTD 2009
Light Oil (bbls/d)	112.2	-	-	-		28.3
Natural Gas (mcf/d)	-	-	-	-		-
Total (boe/d) (6:1)	112.2	-	-	-		28.3

Production By Area (boe/d)	Q4 2009	Q3 2009	Q2 2009	Q1 2009	YTD 2009
Trout	112.2	-	-	-		28.3

Total (boe/d) (6:1)	112.2	-	-	-		28.3

Kodiak Energy Inc.
Consolidated Price Realized Schedule

Kodiak Realized Prices	Q4 2009	Q3 2009	Q2 2009	Q1 2009	YTD 2009
Light Oil (bbls/d)	68.24	-	-	-		68.24
Natural Gas (mcf/d)	-	-	-	-		-
$/boe (6:1)	68.24	-	-	-		68.24

Capital Expenditures

Capital Expenditures incurred by the Company during the years ended December 31, 2009, 2008, and 2007 are set out below.

	2009		2008		2007
Land acquisition and carrying costs	$	8,044,239	$	5,536,736	$	18,907,518
Geological and geophysical		1,523,613		4,827,123		6,390,003
Intangible drilling and completion		545,475		3,892,511		998,556
Tangible completion and facilities		882,267		140,151		23,002
Long Lived Assets		1,049,321		-		-
Other fixed assets		9,851		33,470		58,850
Total Capital Costs Incurred	$	12,054,766	$	14,429,991	$	26,377,929

Property and Equipment

Property and equipment is recorded at cost. Depreciation of assets is provided by use of a declining balance method over the estimated useful lives of the related assets. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred.

Liquidity and Capital Resources

Since inception to December 31, 2008, the Company’s operations have been financed from the sale of securities and loans from shareholders. Working capital deficiency increased from $894,711 as at December 31, 2007 to a working capital deficiency of $3,894,173 at December 31, 2009. Of the total deficiency, $1,364,036 (December 31, 2008 – $Nil) is a current note payable and $538,831 (December 31, 2008 – $Nil) is the current portion of long term debt. Subsequent to year end, the note payable has been converted to equity in a controlled subsidiary of Kodiak and payment has been made on the current and long term portion of both current and long term debt. As at December 31, 2009, the Company was not in breach or default of any covenants or terms of any credit or lending agreements.

During 2009, the Company raised $1,278,349 in private placement financing proceeds in Cougar Energy, Inc. These financings enabled Cougar Energy to finance ongoing capital expenditures and general and administrative expenses.

During 2009, the Company received $1,350,000 CAD by way of a bridge loan at an interest rate of 12% per annum and issuance of 383,188 restricted common shares of Kodiak based on the 10 day weighted average at market close price on September 25, 2009, less 10% discount to market. Proceeds were advanced to its subsidiary, Cougar Energy, to fund the down payment for the acquisition of September 30, 2009. This loan was assumed by a non related third party in December of 2009 and subsequent to year end converted to equity.

The Company is in the process of raising additional financing in its Cougar Energy, Inc. subsidiary that will provide financing to carry out its business plan through 2010. See Subsequent Event Note 21 to the consolidated financial statements. Such additional financing will be required for the company’s 2009 planned activities. In the event that additional capital is raised at some time in the future, existing shareholders will experience dilution of their interest in the Company, or the Company’s interest in the subsidiary.

Kodiak Energy Inc.
Consolidated Revenue Schedule

Revenues ($)	Q4 2009	Q3 2009	Q2 2009	Q1 2009	YTD 2009
Light Oil	704,515	-	-	-		704,515
Natural Gas	-	-	-	-		-
Subtotal	704,515	-	-	-		704,515
Royalty Revenue	-	-	-	-		-
Petroleum and Natural Gas Revenue	704,515	-	-	-		704,515
$/boe (6:1)	68.24	-	-	-		68.24

Kodiak Energy Inc.
Consolidated Royalties Schedule


Royalties ($)	Q4 2009		Q3 2009	Q2 2009	Q1 2009	YTD 2009
Light Oil	109,814		-	-	-		109,814
Natural Gas	-		-	-	-		-
Total Royalties	109,814		-	-	-		109,814
As a % of Oil and Gas Revenue	15.59	%	-	-	-		15.59	%
Petroleum and Natural Gas Revenue	109,814		-	-	-		109,814
$/boe (6:1)	10.64		-	-	-		10.64

Kodiak Energy Inc.
Consolidated Operating Expenses Schedule


Operating Expenses ($)	Q4 2009	Q3 2009	Q2 2009	Q1 2009	YTD 2009

Operating Expenses	411,879	4,167	1,002	1,170.0		418,218
$/boe (6:1)	39.90	-	-	-		40.51

Kodiak Energy Inc.
Consolidated Netback Calculation Schedule


Operating Netback ($/boe)	Q4 2009	Q3 2009	Q2 2009	Q1 2009	YTD 2009
Petroleum & Natural gas Revenue	68.24	-	-	-		68.24
Royalties	10.64	-	-	-		10.64
Operating Costs	39.90	-	-	-		40.51
Operating Netback	17.71	-	-	-		17.09

Kodiak Energy Inc.

Consolidated G&A Schedule

G&A Expenses ($)

Q4 2009

Q3 2009

Q2 2009

Q1 2009

YTD 2009

G&A Expenses

710,679

658,872

356,428

493,462

2,219,441

$/boe(6:1)

68.84

N/A

214.98

Kodiak Energy Inc.
Consolidated Interest Income Schedule


Interest & Other Income ($)	Q4 2009	Q3 2009	Q2 2009	Q1 2009		YTD 2009

Interest and Other Income	11,800	45	725	198.0			12,768
Gain/Loss on Disposal of Assets	479,433			(2,164.0	)		477,269
Total Other Income	491,233	45	725	(1,966	)		490,037
$/boe (6:1)	47.58	-	-	-			47.47

Kodiak Energy Inc.
Consolidated Interest Expense Schedule


Interest Expense ($)	Q4 2009	Q3 2009	Q2 2009	Q1 2009	YTD 2009		Q4 2008	Q3 2008	Q2 2008	Q1 2008	YTD 2008

Interest Expense	106,309	-	92	211		106,612	160	-	1,257	-		1,417
$/boe(6:1)	10.30	-	-	-		10.33	0	0	0	0		0

Consolidated DD&A Schedule


DD&A Expense ($)	Q4 2009	Q3 2009	Q2 2009	Q1 2009	YTD 2009		Q4 2008	Q3 2008	Q2 2008	Q1 2008	YTD 2008
Depletion & Depreciation	243,404	5,409	5,173	4,600		258,586	7,266	8,064	6,840	8,763		30,933
Accretion	22,949	3,461	3,362	3,188		32,960	4,266	4,650	4,808	4,865		18,589
Asset Writedowns	1,645,462	211,156	16,169,130	-		18,025,748	869,847	3,728				873,575
Total DD&A	1,911,815	220,026	16,177,665	7,788		18,317,294	881,379	16,442	11,648	13,628		923,097

DD&A Expense $/boe (6:1)	Q4 2009	Q3 2009	Q2 2009	Q1 2009	YTD 2009		Q4 2008	Q3 2008	Q2 2008	Q1 2008	YTD 2008
Depletion & Depreciation	23.58	-	-	-		25.05	-	-	-	-		-
Accretion	2.22	-	-	-		3.19	-	-	-	-		-
Asset Writedowns	159.39	-	-	-		1,746.04	-	-	-	-		-
Total DD&A $/boe (6:1)	185.19	-	-	-		1,774.28	-	-	-	-		-

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risk from changes petroleum and natural gas and related hydrocarbon prices, foreign currency exchange rates and interest rates.

PETROLEUM AND NATURAL GAS AND RELATED HYDROCARBON PRICES

The Company’s oil and gas business makes it vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By definition, proved reserves are based on current oil and gas prices. Declines in oil and gas prices reduce the estimated quantity of proved reserves and increase annual amortization expense (which is based on proved reserves). Declines in oil and gas prices can reduce the value of our oil and gas properties and increase impairment expense, as occurred in 2009.

We expect oil and gas price volatility to continue. We do not currently utilize hedging contracts to protect against commodity price risk. As our oil and gas production grows, we may manage our exposure to oil and natural gas price declines by entering into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future oil and natural gas production.

OPERATING COST RISK

During 2008 and 2009, we have generally experienced fluctuations in operating costs (including costs of drilling and completing wells) which impact our cash flow from operating activities and profitability. We expect our drilling activity in 2010 to be focused on drilling oil wells. Several other companies seek to drill similar wells in the general area in 2010 whereby drilling and operating costs may rise in response to demand for limited rigs and services in the area.

Fluctuations in drilling costs and production costs, as well as fluctuations in oil and gas prices can have a significant impact on our profitability and may be deciding factors on how many wells we will drill in a given project or even if severe shut in production to control overall costs.

FOREIGN CURRENCY EXCHANGE RATES

The Company, operating in both the United States and Canada, faces exposure to adverse movements in foreign currency exchange rates. These exposures may change over time as business practices evolve and could materially impact the Company’s financial results in the future. To the extent revenues and expenditures denominated in other currencies vary from their U. S. dollar equivalents, the Company is exposed to exchange rate risk. The Company can also be exposed to the extent revenues in one currency do not equal expenditures in the same currency. The Company is not currently using exchange rate derivatives to manage exchange rate risks.

INTEREST RATES

The Company’s interest income and interest expense, in part, is sensitive to the general level of interest rates in North America. The Company is not currently using interest rate derivatives to manage interest rate risks.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

OPINION ON THE AUDIT OF THE FINANCIAL STATEMENTS

To the Board of Directors and the Stockholders of

Kodiak Energy, Inc.

We have audited the accompanying consolidated balance sheets of Kodiak Energy, Inc. (The “Company and subsidiaries”) as of December 31, 2009 and 2008 and the consolidated statements of operations, stockholder’s equity and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluation of the overall financial statement presentation. We believe that our audits provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company and subsidiaries as of December 31, 2009 and 2008 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, the Company’s ability to continue as a going concern is dependent on obtaining sufficient working capital to fund future operations. Management’s plan in regard to these matters is also described in Note 1. These financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 3 to the consolidated financial statement, the Company and subsidiaries have changed their reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements as fo December 31, 2009.

/s/ MEYERS NORRIS PENNY LLP

Chartered Accountants

Calgary, Canada

March 19, 2009

KODIAK ENERGY, INC.
Consolidated Balance Sheets
(Going Concern Uncertainty - Note 1)

Years ended December 31,	2009			2008

Assets
Current Assets:
Cash and Short Term Deposits	$	2,058		$	75,175
Accounts Receivable (Note 5)		403,907			64,325
Prepaid Expenses and Deposits		151,390			106,062
		557,355			245,562

Other Assets (Note 6)		296,153			290,903

Oil and natural gas properties, Full cost accounting (Note 7)
Evaluated properties		6,823,400			-
Less accumulated depreciation, depletion and amortization		2,165,994			-
		4,657,406			-

Unevaluated properties excluded from depletion		26,081,783			36,559,367


Furniture and Fixtures, net		64,862			75,565
		30,804,051			36,634,932

Total Assets	$	31,657,559		$	37,171,397

Liabilities and Stockholders' Equity
Current Liabilities:
Accounts Payable (Note 8)	$	2,267,139		$	984,590
Accrued Liabilities		281,522			122,842
Note Payable to Related Party (Note 18)		-			32,841
Note Payable (Note 9)		1,364,036			-
Current portion of long term debt (Note 10)		538,831			-
		4,451,528			1,140,273

Long-term Liabilities (Note 10)		3,400,489			39,262

Asset Retirement Obligations (Note 11)		1,285,614			199,574


Total Liabilities		9,137,631			1,379,109

Share Capital: Authorized 300,000,000 Common Shares Par Value $.001; 10,000,000 (2008 -10,000,000) Common Shares Issued and Outstanding 110,407,186 (2008 -110,023,998) Common Shares		110,407			110,024
Additional Paid in Capital		50,851,469			49,296,114
Other Comprehensive Loss		(416,905	)		(4,903,762	)
Deficit		(28,283,170	)		(8,710,088	)
		22,261,801			35,792,288
Non controlling interest (Note 14)		258,127			-
Total Liabilities and Equity	$	31,657,559		$	37,171,397
Commitments and Contingencies (Note 16)
Subsequent Events (Note 21)
(See accompanying notes to the consolidated financial statements)

KODIAK ENERGY INC. Consolidated Statements of Shareholders Equity (Deficiency) For the Periods ended December 31, 2007, 2008 and 2009 (Going Concern Uncertainty - Note 1)
	Number of Common Shares		Amount		Additional Paid in Capital (Restated-Note 2)		Deficit Accumulated (Restated - Note 2)			Accumulated other Comprehensive Loss(Restated - Note 2)			Shares Issuable (Restated - note 2)			Non- controlling interest			Total Shareholders' Equity (Deficit) (Restated - Note 2)
Balance at December 31, 2006		89,946,468		89,946		5,212,777		(4,063,776	)		(20,214	)		538,328			-			1,757,061
Net Loss		-		-		-		(2,571,663	)		-			-						(2,571,663	)
Foreign currency translation		-		-		-		-			(321,987	)		-			-			(321,987	)
Total comprehensive Loss		-		-		-		(2,571,663	)		(321,987	)		-			-			(2,893,650	)
Issuance of common stock		16,746,030		16,746		35,660,846		-			-			(538,328	)		-			35,139,264
Stock-based Compensation		-		-		643,934		-			-						-			643,934
Balance at December 31, 2007		106,692,498		106,692		41,517,557		(6,635,439	)		(342,201	)		-			-			34,646,609
Net Loss		-		-		-		(2,074,649	)		-			-			-			(2,074,649	)
Foreign currency translation		-		-		-		-			(4,561,561	)		-			-			(4,561,561	)
Total comprehensive Loss		-		-		-		(2,074,649	)		(4,561,561	)		-			-			(6,636,210	)
Issuance of common stock		3,331,500		3,332		7,104,331		-			-			-			-			7,107,663
Stock-based Compensation		-		-		674,226		-			-			-			-			674,226
Balance at December 31, 2008		110,023,998		110,024		49,296,114		(8,710,088	)		(4,903,762	)		-			-			35,792,288
Net Loss		-		-		-		(19,573,082	)		-			-			(403,746	)		(19,976,828	)
Foreign currency translation		-		-		-		-			4,486,857			-			-			4,486,857
Issuance of common stock		383,188		383		154,207		-			-			-			-			154,590
Stock-based Compensation		-		-		774,199		-			-			-			-			774,199
Increase in paid in capital as a result of change in non-controlling interest proportionate ownership percantage		-		-		626,949		-			-			-			661,873			1,288,822
Balance at December 31, 2009		110,407,186		110,407		50,851,469		(28,283,170	)		(416,905	)		-			258,127			22,519,928
(See accompanying notes to the consolidated financial statements)


KODIAK ENERGY INC.
Consolidated Statements of Operations
(Going Concern Uncertainty - Note 1)

Years ended December 31,	2009			2008			2007

REVENUE
Oil Sales, net of royalties	$	594,701		$	-		$	-
Other		12,768			1,065			225
		607,469			1,065			225
EXPENSES
Operating		418,218			9,646			20,543
General and Administrative		2,219,441			2,206,015			2,470,230
Depletion, Depreciation and Accretion
including Ceiling Test Impairment		18,317,295			923,097			218,841
Interest Expense		106,612			1,417			94,083
		21,061,566			3,140,175			2,803,697

Loss Before Other Expenses		20,454,097			3,139,110			2,803,472

Gain on non-monetary transfer of properties		(477,269	)		-			-
Loss on sale of assets		-			4,145
Interest Income		-			(89,771	)		(84,809	)
		(477,269	)		(85,626	)		(84,809	)

Loss before income taxes		19,976,828			3,053,484			2,718,663
Recovery of deferred income taxes (Note 12)		-			(978,835	)		(147,000	)
Net Loss		19,976,828			2,074,649			2,571,663
Net Loss attributed to Non Controlling Interest (Note 14)		(403,746	)		-			-
Net Loss attributed to Kodiak	$	19,573,082		$	2,074,649		$	2,571,663

Basic and diluted loss per share (Note 15)	$	(0.18	)	$	(0.02	)	$	(0.03	)

(See accompanying notes to the consolidated financial statements)


KODIAK ENERGY, INC.
Consolidated Statements of Cash Flows
(Going Concern Uncertainty - Note 1)

Years ended December 31,	2009			2008			2007
							(Restated - Note 2)
Operating Activities:
Net Loss		(19,573,082	)	$	(2,074,649	)	$	(2,571,663	)

Adjustments to reconcile net loss to net cash used in operating activities:

Depletion, Depreciation and Accretion including Ceiling Test Impairments and Write-downs		18,317,295			923,097			218,841
Stock-Based Compensation		774,199			674,226			643,934
Recovery of Deferred Income Taxes		-			(978,835	)		(147,000	)
Bad Debts Written off		-			-			11,908
Gain on non-monetary transfer of properties		(477,269	)		-			-
Non-Controlling interest		(403,746	)		-			-
Non-Cash Working Capital Changes (Note 20)		397,569			772,037			(660,101	)
Net Cash Used In Operating Activities		(965,034	)		(684,124	)		(2,504,081	)

Investment Activities:
Additions to Capital Assets		(5,563,737	)		(6,427,666	)		(7,508,553	)
Decrease (Increase) in Other Assets		-			68,450			(309,493	)
Net Cash Used In Investment Activities		(5,563,737	)		(6,359,216	)		(7,818,046	)

Financing Activities:
Shares Issued and Issuable		552,692			2,768,087			16,500,995
Shares Issued by subsidary for cash		1,046,925			-			-
Proceeds from note payable		369,179			-			3,300,000
Repayment of note payable		-			-			(732,500	)
(Decrease) Increase in Long Term Liabilities		-			(71,693	)		110,955
Cash Provided By Financing Activities		1,968,796			2,696,394			19,179,450

Foreign Currency Translation		4,486,857			(4,561,561	)		321,987
Net Cash (Decrease) Increase		(73,118	)		(8,908,507	)		8,535,336
Cash beginning of year		75,175			8,983,682			448,346
Cash end of year	$	2,057		$	75,175		$	8,983,682

Cash is comprised of:
Balances with banks	$	2,057		$	75,175		$	1,238,796
Short term deposits	$	-		$	-		$	7,744,886
	$	2,057		$	75,175		$	8,983,682

(See accompanying notes to the consolidated financial statements)

KODIAK ENERGY, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Years Ended December 31, 2009 and 2008

Stated in US dollars

1. ORGANIZATION, BASIS OF PRESENTATION AND GOING CONCERN UNCERTAINTY

The accompanying consolidated financial statements include the accounts of Kodiak Energy Inc. and subsidiaries (collectively “Kodiak”, the “Company”, “we”, “us” or “our”) as at December 31, 2009 and December 31, 2008 , and are presented in accordance with accounting principles generally accepted in the United States of America (“U. S. GAAP”).

The Company was incorporated under the laws of the state of Delaware on December 15, 1999 under the name “Island Critical Care, Corp.” with authorized common stock of 50,000,000 shares with a par value of $0.001. On December 30, 2004 the name was changed to “Kodiak Energy, Inc.” During 2008, the Company increased its authorized capital to include 10,000,000 preferred shares.

With the commencement of production in the fourth quarter, the Company is no longer an exploration stage company.

Going Concern Uncertainty

These consolidated financial statements have been prepared assuming the Company will continue as a going concern, which presumes the realization of assets and discharge of liabilities in the normal course of business for the foreseeable future. The Company has not generated positive cash flow since inception and has incurred operating losses and will need additional working capital for its future planned activities. The success of these programs is yet to be determined. These conditions raise doubt about the Company’s ability to continue as a going concern. Continuation of the Company as a going concern is dependent upon obtaining sufficient working capital to finance ongoing operations. The Company’s strategy to address this uncertainty includes additional equity and debt financing; however, there are no assurances that any such financings can be obtained on favorable terms, if at all. These financial statements do not reflect the adjustments or reclassification of assets and liabilities that would be necessary if the Company were unable to continue its operations.

2. RESTATEMENT

In March, 2009, we determined that it was necessary to restate our financial statements as at December 31, 2007. The purpose of the restatement is to correct an error in measurement and an error in the application of US GAAP in the course of recording the following 2007 transactions:

Issue of common shares of the Company in consideration for the acquisition of properties.

On September 28, 2007, the Company issued to Thunder River Energy, Inc. (“Thunder”) 7,000,000 common shares of the Company as partial consideration for the acquisition of properties. The shares issued were recorded at a negotiated price per share of US$2.00 or $14,000,000. In the course of a review by the Securities and Exchange Commission (“SEC”) of the Company’s Form 10-Q for the Fiscal Quarter Ended September 30, 2007 and Form 10-K for the Fiscal Year Ended December 31, 2007, the SEC questioned the measurement date and the $2.00 per share value at which the transaction was recorded. Following an exchange of correspondence and discussions between the Company and the SEC during 2008 and 2009 regarding this issue, the Company has determined that the acquisition should have been recorded at a value per share of $2.50 or $17,500,000, which represents the fair value of exactly comparable common shares issued at the same $2.50 price per share as a private placement financing for 2,756,000 common shares which closed on September 28, 2007, the same date that the Thunder transaction closed. Management believes that the $2.50 Kodiak share price to be the most reliable measurement for the fair value of the shares issued and that September 28, 2008 to be the appropriate measurement date because that was the date when the parties’ closing conditions were satisfied and Thunder’s (the counterparty’s) performance was complete. The result of the restatement adjustment was an increase of $3,500,000 in the recorded acquisition cost and related issuance of common shares.

Issue of flow-through common shares of the Company at a premium.

On September 28, 2007, October 3, 2007 and October 30, 2007, the Company issued on a Canadian flow-through share basis 2,251,670 common shares of the Company at US$3.00 per share or $6,755,010, which amount represented a premium of $.50 per share or $1,125,835 when compared to other non-flow through shares issued at the same time at $2.50 per share. At the time of the transactions, the issues of the flow through common shares were recorded as credits to par value of common shares and additional paid in capital. Following discussions with the Company’s tax consultant, the Company has determined that the $1,125,835 premium on flow-through common shares issued should have, in accordance with US GAAP, been recorded as a liability at the time the shares were issued rather than as additional paid in capital. A $147,000 portion of the premium liability discharged during the period October 1, 2007 to December 31, 2007, when flow-through eligible expenditures amounting to $879,922 were incurred by the Company, was recognized as a reduction of deferred tax expense.

Effects of the restatement by line item follow:

Consolidated Balance Sheets

	December
	31, 2007						December
	As Previously			Impact			31, 2007
	Reported			of Changes			Restated

Cash and Short Term Deposits	$	8,983,682			-		$	8,983,682
Accounts Receivable		1,214,253			-			1,214,253
Prepaid Expenses and Deposits		90,475			-			90,475
Total current assets		10,288,410			-			10,288,410

Other Assets		359,353			-			359,353

Unproved Oil and Gas Properties		23,967,351			3,500,000			27,467,351
Furniture and Fixtures		75,654			-			75,654
Total Property, Plant and Equipment		24,043,005			3,500,000			27,543,005

Total Assets	$	34,690,768			3,500,000			38,190,768

Accounts Payable	$	1,547,273			-			1,547,273
Accrued Liabilities		755,282			-			755,282
Premium on Flow-through Shares Issued		-			978,835			978,835
Total current liabilities		2,302,555			978,835			3,281,390

Long Term Liabilities		110,955			-			110,955

Asset Retirement Obligations		151,814			-			151,814

Deferred Income Taxes		57,000			(57,000	)		-

Share Capital		106,692			-			106,692
Additional Paid in Capital		39,143,392			2,374,165			41,517,557
Other Comprehensive Loss		(342,201	)		-			(342,201	)
Deficit Accumulated during the Exploration Stage		(6,839,439	)		204,000			(6,635,439	)
Total Shareholders’ Equity		32,068,444			2,578,165			34,646,609

Total Liabilities and Shareholders’ Equity	$	34,690,768			3,500,000			38,190,768

Consolidated Statement of Shareholders' Equity Period April 7, 2004 (Date of Inception) to December 31, 2007

	Par Value		Additional Paid in Capital		Deficit Accumulated during the Development Stage				Accumulated Other Comprehensive Loss			Total Shareholders' Equity
Balance December 31, 2007 as Previously Reported		106,692		39,143,392		$	(6,839,439	)	$	(342,201	)		$	32,068,444

Impact of Changes		-		2,374,165			204,000			-				2,578,165

Balance December 31, 2007 as Restated		106,692		41,517,560		$	(6,635,439	)	$	(342,201	)		$	34,646,609

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

These consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Kodiak Petroleum ULC, Kodiak Petroleum (Montana), Inc., Kodiak Petroleum (Utah), Inc. and its 84.62% owned subsidiary Cougar Energy, Inc. (formerly 1438821 Alberta Ltd.) (“Cougar”). In British Columbia, Canada, the Company operates under the assumed name of Kodiak Bear Energy, Inc. All intercompany balances and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.

Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of unproved properties, future taxable income and related assets/liabilities, the collectability of outstanding accounts receivable, fair values of derivatives, stock-based compensation expense, contingencies and the results of current and future litigation.

Oil and natural gas reserve estimates which are the basis for unit-of-production depletion and the ceiling test, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Subsequent drilling results, testing and production may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

The significant estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, the creditworthiness of counterparties, interest rates, the market value of the Company’s common stock and corresponding volatility and the Company’s ability to generate future taxable income. Future changes in these assumptions may affect these significant estimates materially in the near term. The Company has also evaluated subsequent events for recording and disclosures, including assumptions used in its estimates.

Joint Venture Operations

In instances where the Company’s oil and gas activities are conducted jointly with others, the Company’s accounts reflect only its proportionate interest in such activities.

Cash and Short-term Deposits

Cash consists of balances with financial institutions and investments in money market instruments, which have terms to maturity of three months or less at time of purchase.

Oil and Gas Properties

Under the full cost method of accounting for oil and gas operations all costs associated with the exploration for and development of oil and gas reserves are capitalized on a country-by-country basis. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells, production equipment and overhead charges directly related to acquisition, exploration and development activities. Proceeds from the sale of oil and gas properties are applied against capitalized costs with no gain or loss recognized, unless such a sale would alter the rate of depletion and depreciation by 25% in a particular country, in which case a gain or loss on disposal is recorded.

Capitalized costs, less accumulated amortization and related deferred income taxes, are limited to a “ceiling-test” based on the estimated future net revenues, discounted at 10% per annum, from proved oil and natural gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. If net capitalized costs exceed this limit, the excess is charged to earnings. The option to use a pricing date subsequent to the balance sheet is no longer available to the Company effective December 31, 2009 due to the adoption of the new oil and natural gas reporting requirements as described below under “Recently Adopted Accounting Pronouncements.”

Capitalized costs within each country are depleted and depreciated on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. Oil and gas reserves and production are converted into equivalent units on the basis of 6,000 cubic feet of natural gas to one barrel of oil. Depletion and depreciation is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future costs to be incurred in developing proved reserves, net of estimated salvage value.

Costs of acquiring and evaluating unproved properties and major development projects are initially excluded from the depletion and depreciation calculation until it is determined whether or not proved reserves can be assigned to such properties. Costs of unproved properties and major development projects are transferred to depletable costs based on the percentage of reserves assigned to each project over the expected total reserves when the project was initiated. These costs are assessed periodically to ascertain whether impairment has occurred.

Property and Equipment

Asset Retirement Obligations

The Company recognizes a liability for asset retirement obligations in the period in which they are incurred and in which a reasonable estimate of such costs can be made. Asset retirement obligations include those legal obligations where the Company will be required to retire tangible long-lived assets such as producing well sites. The asset retirement obligation is measured at fair value and recorded as a liability and capitalized as part of the cost of the related long-lived asset as an asset retirement cost. The asset retirement obligation accretes until the time the asset retirement obligation is expected to settle while the asset retirement costs included in oil and gas properties are amortized using the unit-of-production method.

Amortization of asset retirement costs and accretion of the asset retirement obligation are included in depletion, depreciation and accretion. Actual asset retirement costs are recorded against the obligation when incurred. Any difference between the recorded asset retirement obligations and the actual retirement costs incurred is recorded in depletion, depreciation and accretion.

Environmental

Oil and gas activities are subject to extensive federal, provincial, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites.

Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated

Income Taxes

Income taxes are determined using assets and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period that includes the enactment date. In addition, a valuation allowance is established to reduce any deferred tax asset for which it is determined that it is more likely than not that some portion of the deferred tax asset will not be realized.

Per FASB ASC 740 “Income taxes” under the liability method, it is the Company’s policy to provide for uncertain tax positions and the related interest and penalties based upon management’s assessment of whether a tax benefit is more likely than not to be sustained upon examination by tax authorities. At December 31, 2009, the Company believes it has appropriately accounted for any unrecognized tax benefits. To the extent the Company prevails in matters for which a liability for an unrecognized benefit is established or is required to pay amounts in excess of the liability, the Company’s effective tax rate in a given financial statement period may be affected. Interest and penalties associated with the Company’s tax positions are recorded as Interest Expense.

Flow-through Shares

From time to time the Company finances a portion of its Canadian exploration programs with flow-through common shares issued pursuant to certain provisions of the Income Tax Act (Canada) (the “Act”). Under the Act, where the proceeds are used for eligible expenditures, the related income tax deductions may be renounced to subscribers. Accordingly, the tax credits associated with the renunciation of such expenditures are recorded as an increase to deferred income tax liabilities. Any premium received from subscribers on the sale of such flow-through common shares is recorded initially as a current liability and then discharged and recognized as a reduction of deferred income taxes when the flow-through eligible expenditures relating to the flow-through premium are incurred by the Company.

Financial Instruments

The Company’s financial instruments consist of cash, accounts receivables, accounts payables, accrued liabilities, notes payable and long-term debt. The carrying amount of cash, accounts receivables, accounts payable, accrued liabilities, and notes payable approximates fair value because of the short-term nature of these items. The carrying amounts of long-term debt approximate the fair values as these borrowings have been discounted at market rates.

Concentration of Credit Risk

Substantially all of the Company’s accounts receivable result from oil and natural gas sales, joint interest billings to third parties in the oil and natural gas industry or drilling and completion advances to third-party operators for development costs of in-progress wells. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not require collateral from its customers. The Company generally has the right to offset revenue against related billings to joint interest owners

Stock-Based Compensation

The Company records compensation expense for share based payments using the fair value method in accordance with FASB ASC 718 “Compensation- Stock Compensation”. The fair value of share-based compensation to employees will be determined using an option pricing model at the time of grant. Fair value for common shares issued for goods or services rendered by non-employees are measured based on the fair value of the goods or services received. Stock-based compensation expense is included in general and administrative expense with a corresponding increase to Additional Paid in Capital. Upon the exercise of the stock options, consideration paid together with the previously recognized Additional Paid in Capital is recorded as an increase in share capital.

Foreign Currency Translation

The functional currency for the Company’s foreign operations is the Canadian dollar. The translation from the applicable foreign currencies to U.S. dollars is performed for asset and liability accounts using current exchange rates in effect at the balance sheet date, while income, expenses and cash flows are translated at the average exchange rates for the period. The resulting translation adjustments are recorded as a component of other comprehensive loss. Gains or losses resulting from foreign currency transactions are included in other income/expenses.

Revenue Recognition

Revenues from the sale of petroleum and natural gas are recorded when title passes from the Company to its petroleum and/or natural gas purchaser and collectability is reasonably assured.

Loss Per Common Share

Basic loss per common share is computed by dividing net loss by the weighted average number of common shares outstanding for the period. Diluted loss per common share is computed after giving effect to all dilutive potential common shares that were outstanding during the period. Dilutive potential common shares consist of incremental shares issuable upon exercise of stock options and warrants, contingent stock, conversion of debentures and preferred stock outstanding. The dilutive effect of potential common shares is not considered in the EPS calculations for these periods if the impact would have been anti-dilutive.

Non-controlling Interests

We adopted the accounting standard for non-controlling interests in the consolidated financial statements as of January 1, 2009. This standard establishes accounting and reporting standards for ownership interests in subsidiaries held by parties other than the parent, the amount of consolidated net income attributable to the parent and to the non-controlling interest, changes in a parent’s ownership interest and the valuation of retained non-controlling equity investments when a subsidiary is deconsolidated. This standard also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interest of the parent and the interests of the non-controlling owner.

Accounting for Changes in Ownership Interests in Subsidiaries

The Company’s ownership interest in a consolidated subsidiary may change if it sells a portion of its interest, or if the subsidiary issues or re-purchases its own shares. If the transaction does not result in a change in control over the subsidiary and it is not deemed to be a sale of real estate, the transaction is accounted for as an equity transaction. If the transaction results in a change in control it would result in the deconsolidation of a subsidiary with a gain or loss recognized in the statement of operations. During 2009 the Company’s ownership interest in Cougar Energy Inc. changed in three separate transactions which were accounted for as equity transactions. See Note 14 Non-Controlling Interest for a description of the transactions and the impact to the financial statements.

Accounting for Sales of Stock by a Subsidiary

The Corporation issued common shares in various transactions, which resulted in a dilution of the Corporation's percentage ownership in the Subsidiary. The Corporation accounted for the sale of the Subsidiary common shares in accordance with guidance related to equity transactions. The guidance allows for the election of an accounting policy of recording such increase or decreases in a parent's investment either in income or in equity. The Corporation adopted a policy of recording such gains or losses directly to additional paid in capital.

4. RECENT ACCOUNTING PRONOUNCEMENTS

In December 2007, the Financial Accounting Standards Board (the "FASB") issued FASB Accounting Standards Codification (ASC) 805, "Business Combinations", formerly Statement No. 141R, "Business Combinations" ("SFAS No. 141R"). Under ASC 805, a company is required to recognize the assets acquired, liabilities assumed, contractual contingencies, and any contingent consideration measured at their fair value at the acquisition date. It further requires that research and development assets acquired in a business combination that have no alternative future use are to be measured at their acquisition-date fair value and then immediately charged to expense, and that acquisition-related costs are to be recognized separately from the acquisition and expensed as incurred. Among other changes, this statement also requires that "negative goodwill" be recognized in earnings as a gain attributable to the acquisition, and any deferred tax benefits resultant in a business combination be recognized in income from continuing operations in the period of the combination. ASC 805 is effective for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning after December 15, 2008. On January 1, 2009, the Company adopted ASC 805 and applies its provisions prospectively to business combinations that occur after adoption. The adoption did not have any immediate effect on the financial statements and related disclosures.

In September 2008, the EITF reached a consensus for exposure on Issue No. 08-6, “Equity Method Investment Accounting Considerations”. This issue addresses the accounting for equity method investments as a result of the accounting changes prescribed by SFAS 141(R) and SFAS 160. The issue includes clarification on the following: (a) transaction costs should be included in the initial carrying value of the equity method investment, (b) an impairment assessment of an underlying indefinite-life intangible asset of an equity method investment need only be performed as part of any other-than-temporary impairment evaluation of the equity method investment as a whole and does not need to be performed annually, (c) the equity method investee’s issuance of shares should be accounted for as the sale of a proportionate share of the investment, which may result in a gain or loss in income, and (d) a gain or loss should not be recognized when changing the method of accounting for an investment from the equity method to the cost method. For the Company, this issue was effective January 1, 2009. The impact of this issue did not have a material effect on our consolidated financial statements.

In June 2009, the Financial Accounting Standards Board (“FASB”) issued an accounting standard ASC 855 -

"Subsequent events" for subsequent events which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. This standard is effective for interim or annual periods ending after June 15, 2009.

In June 2009, the FASB issued an accounting standard that codifies and modifies the hierarchy of generally accepted accounting principles. This standard is the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (“SEC”) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. This standard superseded all then-existing non-SEC accounting and reporting standards. All other non grandfathered non-SEC accounting literature not included in this standard is now non authoritative. This standard is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of this standard did not have an impact on our consolidated financial position, results of operations or cash flows.

Effective July 1, 2009, the Company adopted FASB ASU No. 2009-05, Fair Value Measurements and Disclosures (Topic 820) (“ASU 2009-05”). ASU 2009-05 provided amendments to ASC 820-10, “Fair Value Measurements and Disclosures – Overall, for the fair value measurement of liabilities”. ASU 2009-05 provides clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using certain techniques. ASU 2009-05 also clarifies that when estimating the fair value of a liability, a reporting entity is not required to include a separate input or adjustment to other inputs relating to the existence of a restriction that prevents the transfer of a liability. ASU 2009-05 also clarifies that both a quoted price in an active market for the identical liability at the measurement date and the quoted price for the identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are Level 1 fair value measurements. Adoption of ASU 2009-05 did not have a material impact on the Company’s consolidated results of operations or financial condition.

On December 31, 2008 the SEC issued the final rule, "Modernization of Oil and Gas Reporting" (the "Final Reporting Rule"). The Final Reporting Rule adopts revisions to the SEC's oil and gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also designed to modernize the oil and gas disclosure requirements to align them with current practices and changes in technology. Revised requirements in the Final Reporting Rule include, but are not limited to:

• Oil and gas reserves must be reported using the un-weighted arithmetic average of the first day of the month price for each month within a 12 month period, rather than year-end prices;

• Companies will be allowed to report, on an optional basis, probable and possible reserves;

• Non-traditional reserves, such as oil and gas extracted from coal and shales, will be included in the definition of "oil and gas producing activities;"

• Companies will be permitted to use new technologies to determine proved reserves, as long as those technologies have been demonstrated empirically to lead to reliable conclusions with respect to reserve volumes;

• Companies will be required to disclose, in narrative form, additional details on their proved undeveloped reserves ("PUDs"), including the total quantity of PUDs at year end, and any material changes to PUDs that occurred during the year, investments and progress made to convert PUDs to developed oil and gas reserves and an explanation of the reasons why material concentrations of PUDs in individual fields or countries have remained undeveloped for five years or more after disclosure as PUDs; and Companies will be required to report the qualifications and measures taken to assure the independence and objectivity of any business entity or employee primarily responsible for preparing or auditing reserves estimate.

We have complied with the disclosure requirements in our annual report on Form 10-K for the year ended December 31, 2009.

Application of the new reserves rules resulted in the use of lower prices at December 31, 2009 for crude oil than would have been used under the previous rules.

The following new accounting standards have been issued, but have not yet been adopted by the Company:

Effective April 1, 2009, FASB ASC 820-10-65, Fair Value Measurements and Disclosures – Overall – Transition and Open Effective Date Information (“ASC 820-10-65”). ASC 820-10-65 provides additional guidance for estimating fair value in accordance with ASC 820-10 when the volume and level of activity for an asset or liability have significantly decreased. ASC 820-10-65 also includes guidance on identifying circumstances that indicate a transaction is not orderly.

Effective April 1, 2009, FASB ASC 825-10-65, Financial Instruments – Overall – Transition and Open Effective Date Information (“ASC 825-10-65”). ASC 825-10-65 amends ASC 825-10 to require disclosures about fair value of financial instruments in interim financial statements as well as in annual financial statements and also amends ASC 270-10 to require those disclosures in all interim financial statements.

Effective April 1, 2009, FASB ASC 855-10, Subsequent Events – Overall (“ASC 855-10”). ASC 855-10 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued.

Effective July 1, 2009, FASB 107-1 (ASU No. 825) which amends FASB 107, Disclosures about Fair Value of Financial Instruments (SFAS 107) to require entities to disclose, among other things, the methods and significant assumptions used to estimate the fair value of financial instruments in both interim and annual financial statements. This FSP also amends APB Opinion No. 28, Interim Financial Reporting (Opinion 28) to require those disclosures in summarized financial information at interim reporting periods.

In October 2009, the FASB issued ASU 2009-13, Multiple-Deliverable Revenue Arrangements, (amendments to FASB ASC Topic 605, Revenue Recognition ) (“ASU 2009-13”) and ASU 2009-14, Certain Arrangements That Include Software Elements , (amendments to FASB ASC Topic 985, Software ) (“ASU 2009-14”). ASU 2009-13 requires entities to allocate revenue in an arrangement using estimated selling prices of the delivered goods and services based on a selling price hierarchy. The amendments eliminate the residual method of revenue allocation and require revenue to be allocated using the relative selling price method. ASU 2009-14 removes tangible products from the scope of software revenue guidance and provides guidance on determining whether software deliverables in an arrangement that includes a tangible product are covered by the scope of the software revenue guidance. ASU 2009-13 and ASU 2009-14 should be applied on a prospective basis for revenue arrangements entered into or materially modified in fiscal years beginning on or after June 15, 2010, with early adoption permitted. The Company does not expect adoption of ASU 2009-13 or ASU 2009-14 to have a material impact on the Company’s consolidated results of operations or financial condition.

5. ACCOUNTS RECEIVABLE

Accounts receivable consist of the following:

	2009		2008
Non-operating Partner joint venture accounts	$	309,667	$	1,193
Government of Canada Goods and Services Tax Claims		14,547		16,733
Other		79,693		46,399
	$	403,907	$	64,325

6. OTHER ASSETS

Other assets represent long term deposits required by governmental regulatory authorities for environmental obligations relating to well abandonment and site restoration activities.

	2009		2008
Alberta Energy and Utility Board Drilling Deposit	$	43,738	$	73,507
Department of Energy Reclaimation Deposit		476		-
British Columbia Oil and Gas Commission Deposit		251,939		217,396
	$	296,153	$	290,903

7. CAPITAL ASSETS

	Cost		Accumulated Depreciation and Depletion		Net book Value December 31, 2009
Oil and Gas Properties:
Developed
Canada	$	6,823,400	$	2,165,994	$	4,657,406

Undeveloped
Canada		32,441,500		17,634,527		14,806,973
United States		11,773,677		498,867		11,274,810
		44,215,177		18,133,394		26,081,783

Furniture and Fixtures		168,166		103,304		64,862
Total	$	51,206,743	$	20,402,692	$	30,804,051

	Cost		Accumulated Depreciation and Depletion		Net book Value December 31, 2008
Oil and gas Properties:
Undeveloped
Canada	$	27,244,206	$	1,935,428	$	25,308,778
United States		11,749,456		498,867		11,250,589
		38,993,662		2,434,295		36,559,367

Furniture and Fixtures		148,025		72,460		75,565
Total	$	39,141,687	$	2,506,755	$	36,634,932

During the year ended December 31, 2009, the Company capitalized $182,202 (2008 - $292,824) of general and administrative personnel costs attributable to acquisition, exploration and development activities. Future capital costs included in the depletion calculation for December 31, 2009 was $619,000 (2008-Nil)

Capital addition for the years ended December 31, 2009 and 2008 were as follows:

	2009		2008
Land acquisition and carrying costs	$	8,044,239	$	5,536,736
Geological and geophysical		1,523,613		4,827,123
Intangible drilling and completion		545,475		3,892,511
Tangible completion and facilities		882,267		140,151
Long Lived Assets		1,049,321		-
Other fixed assets		9,851		33,470
Total Capital Costs Incurred	$	12,054,766	$	14,429,991

Unproved Properties

Included in oil and gas properties are the following costs related to Canadian and United States unproved properties, valued at cost, that have been excluded from costs subject to depletion:


	2009		2008
Canada
Land acquisition and retention	$	1,503,314	$	15,039,607
Geological and geophysical costs		10,867,335		9,330,180
Exploratory drilling		2,220,826		619,409
Tangible Equipment and Facilities		215,501		244,450
Other		0		75,132
	$	14,806,976	$	25,308,778


United States
Land acquisition and retention	$	8,168,134	$	8,158,899
Geological and geophysical costs		937,924		941,836
Exploratory drilling		1,993,244		1,974,346
Tangible Equipment and Facilities		95,699		95,699
Other		79,809		79,809
	$	11,274,810	$	11,250,589

In Canada, a stimulation and horizontal drilling program is planned for our British Columbia property during the next year. In the United States, an initial seismic and drilling program has been conducted on our New Mexico property with additional drilling to follow. These planned activities, when completed, will enable the Company to evaluate the economic viability of these properties.

The costs associated with the unproved properties are subject to a test for impairment which is separate from the test applied to proved resource properties.

Property Acquisition

On September 30, 2009, Cougar acquired from an unrelated private company certain wells, facilities and producing operations in and adjacent to the CREEnergy Project in Alberta, Canada. The purchase price of the acquisition was $5,604,000 of which $934,000 was paid in cash and the remainder in the form of non-interest bearing debt. At December 31, 2009, the non-interest bearing balance of $4,471,990 was payable in accordance with the terms set out in Note 10.

On October 1, 2009 Cougar acquired wells, facilities and production from a private company with operations in the Trout area of Alberta, Canada. The purchase price of the acquisition was $291,650, $107,241 in cash payable over 18 months with the balance to be paid by the issuance of 155,000 common shares of Cougar.

On October 1, 2009, Cougar received as a default payment in a farmout agreement, two oil and natural gas leases. The transaction was accounted for as a non-monetary transaction in relation to the receipt of assets for no cash consideration. As a result, a gain of $477,269 was recorded in the financial statements.

During the year, Cougar entered into an agreement with CREEnergy Oil and Gas Inc. The agreement provides for an "exclusivity contract" with CREEnergy for oil and gas properties for up to 15 townships or 345,000 gross acres of mineral rights in north central Alberta, Canada. The initial leases, as outlined in the agreement, are for mineral rights on a total of 46,000 gross acres for a lease term of 10 years. As the project moves forward, additional leases will be identified and added to the joint venture. The cash payment of $951,474 was funded with a private equity issue in Cougar.

Full Cost Accounting Ceiling Test on Canadian Proved Oil and Gas Properties

At December 31, 2009, a ceiling test was performed on the Company's properties subject to depletion. Costs of unproved properties aggregating $6,277,616 and future abandonment costs of $306,375 have been excluded from this test. This test disclosed that the carrying costs of the Company's depletable Canadian properties exceeded their net present value by $1,570,607 and consequently a non cash ceiling test write-down of that amount has been recorded.

Reserves

In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 2009 reserve information. In January 2010, the FASB issued its authoritative guidance on extractive activities for oil and gas to align its requirements with the SEC’s final rule. We adopted the guidance as of December 31, 2009 in conjunction with our year-end reserve report as a change in accounting principle that is inseparable from a change in accounting estimate. Under the SEC’s final rule, prior period reserves were not restated.

For the United States, the primary impact of the SEC’s final rule on our reserve estimates include the use of the unweighted 12 month average of the first-day-of-the-month reference price of $58.21 USD per barrel.

8. ACCOUNTS PAYABLE

Included in accounts payable at December 31, 2009 is $517,026 (2008 – Nil) which related to funds advanced to the Company by outside investors pursuant to an agreement to convert the balance of the advances to working interests in certain properties subject to regulatory and other approvals.

9. NOTE PAYABLE

During the year, the Company entered into a loan agreement with Ionic Capital Corp. ("Ionic"), under the terms of which Ionic loaned $1,292,675 to the Company to enable it to close the CREEnergy property acquisition described in Note 7. The indebtedness bears interest at the rate of 12% per annum payable monthly in arrears and is repayable at any time up to but no later than June 30, 2010. As additional financing consideration for the loan, the Company agreed to issue common shares based on a 10% discount to the 10 day weighted average closing trading price on September 25, 2009 that equated to 12% of the principal amount of the financing. The 383,188 common shares of the Company that were issued to satisfy that obligation were recorded at a value of $187,762 based on the closing market price of the Company’s common shares on September 30, 2009. Share issue costs associated with this transaction were $33,172. In December of 2009 the debt was assumed by Zentrum Energie AG (“Zentrum”) under the existing terms and conditions. The indebtedness above is governed by several operational covenants. As at December 31, 2009 the Company was in compliance with all covenants. On January 25, 2010, the debt converted to equity (Note 21).

During the year, Zentrum advanced an additional $71,361 to the Company. The note bears interest at 1% per annum and the principle less prepayments and accrued interest is due on or before November 17, 2010.

10. LONG TERM LIABILITIES

The Company has the following long-term liabilities:

	2009			2008
Amount due to vendor of CREEnergy properties	$	4,471,930
Amount of Discount to be accreted in the future (at 7.5% annually - .0625% per month)		(650,425	)		-
Present value of amount due		3,821,505			-
Amount due to vendor of Trout area properties		72,312
Total indebtedness from the purchase of properties		3,893,817

Less current portion		538,831			-
Long-term portion		3,354,986			-

Funds advanced by partners for their share of a drilling deposit required to be lodged by the Company with the British Columbia Oil and Gas Commission (See Note 6) as security for future well abandonment and site restoration activities		45,502			39,262
Total		3,400,488			39,262

The total amount due to the vendor of the Trout Core properties is payable in accordance with the following schedule:

Due in 2010 in 11 monthly installments	$	732,635
Due in 2011 in 12 monthly installments		970,504
Due in 2012 in 12 monthly installments		1,141,769
Due in 2013 in 12 monthly installments		1,313,035
Due in 2014 in 2 monthly installments		313,987
	$	4,471,930

The Company has the right to prepay the vendor loan in full, without penalty, semi-annually commencing March 31, 2010 at a proportionate discount to the original purchase price. The indebtedness is secured by a debenture covering a fixed and floating charge over Cougar's interest in the acquired properties .

During the year, non cash interest of $73,983 was recorded as interest expense in relation to the discount on the Trout Core indebtedness.

11. ASSET RETIREMENT OBLIGATIONS

Changes in the carrying amounts of the asset retirement obligations associated with the Company’s oil and natural gas properties are as follows:

Asset retirement obligations, December 31, 2007		151,814
Obligations incurred		62,642
Accretion		14,044
Retirements		(28,926	)
Asset retirement obligations, December 31, 2008		199,574
Obligations incurred		1,022,582
Accretion		32,960
Retirements		(2,276	)
Foreign Exchange Gain (Loss)		32,774
Asset retirement obligations, December 31, 2009	$	1,285,614

At December 31, 2009, the estimated total undiscounted amount required to settle the asset retirement obligations was $3,033,143 (2008 - $302,273). These obligations will be settled at the end of the useful lives of the underlying assets, which currently extends up to 8 years into the future. This amount has been discounted using a credit adjusted risk-free interest rate of 7.5% and a rate of inflation of 2.5%.

12. INCOME TAXES

As at December 31, 2009, the Company's deferred tax asset is attributable to its net operating loss carry forward of approximately $3,357,000 (2008 - $2,802,000; 2007 - $2,000,000), which will expire if not utilized in the years 2024, 2025, 2026, 2027, 2028 and 2029. As reflected below, this benefit has been fully offset by a valuation allowance based on management's determination that it is not more likely than not that some or all of this benefit will be realized.

For the years ended December 31, 2009, 2008, and 2007, a reconciliation of income tax benefit at the U.S. federal statutory rate to income tax benefit at the Company's effective tax rates is as follows.

	2009			2008			2007 (Restated)

Income tax benefit at statutory rate	$	7,563,000		$	1,156,000		$	944,000
Permanent Differences		-			(4,000	)		2,000
State tax benefit, net of federal tax		-			-			48,000
Foreign taxes, net of federal benefit		-			(2,224,000	)		(323,000	)
Revision to tax account estimates		-			(177,000	)		-
Previously unrecognized tax asset		-			-			308,000
Other		(2,000	)		(2,000	)		-
Change in valuation allowance		(7,268,000	)		1,251,000			(979,000	)
Deferred tax asset before the following		-			-			-
Deferred tax credit arising from flow-through share premiums		-			978,835			147,000
Deferred Tax Recovery		-			978,835			147,000

Deferred tax assets (liabilities) at December 31, 2009 and 2008 are comprised of the following:

	2009			2008
Deferred tax assets
Capital assets	$	1,428,000		$	-
Net operating loss carryover		7,286,000			2,802,000
Asset retirement obligations		-			-
Other		-			75,000
Total deferred tax asset		8,714,000			2,877,000

Deferred Tax liabilities
Capital assets		-			345,000
Net deferred tax asset before valuation allowance		8,714,000			2,532,000
Less valuation allowance		(8,714,000	)		(2,532,000	)
Net deferred tax asset	$	-		$	-

The valuation allowance of $8,714,000 (2008 - $2,532,000) includes $1,806,000 (2008 - $1,690,000) relating to year end currency revaluation adjustments that have not been charged to expense but are included in comprehensive loss in shareholders’ equity.

Accounting for uncertainty for Income Tax

Effective January 1, 2009, we adopted the interpretation for accounting for uncertainty in income taxes which was an interpretation of the accounting standard accounting for income taxes. This interpretation created a single model to address accounting for uncertainty in tax positions. This interpretation clarifies the accounting for income taxes, by prescribing a minimum recognition threshold a tax position is required to meet before being recognized in the financial statements.

We or one of our subsidiaries files income tax returns in the U.S. federal jurisdiction, and various states and foreign jurisdictions. With few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years prior to 2006. To date, the Internal Revenue Service (“IRS”) has not performed an examination of our U.S. income tax returns for 2006 through 2008.

We do not have any unrecognized tax benefits or loss contingencies.

13. STOCK OPTION PLAN AND STOCK BASED COMPENSATION

The Company has a stock option plan under which it may grant options to its directors, officers, employees and consultants for up to a maximum of 10% of its issued and outstanding common shares at market price at the date of grant for up to a maximum term of five years. Options are exercisable equally over the first three years of the term of the option.

A summary of the status of our stock option plans as of December 31, 2009, 2008 and 2007 and changes during the years ending on those dates is presented below (shares in thousands):

	Weighted average Exercise				Weighted average Exercise				Weighted average Exercise
	Price		Shares		Price		Shares		Price		Shares
Outstanding at beginning of year	$	1.50		1,796,666	$	1.62		2,035,000	$	1.48		1,125,000
Options Granted		0.29		4,630,000		0.92		125,000		1.80		910,000
Options cancelled		1.61		366,666		1.99		363,334		-		-
Outstanding at end of year		0.57		6,060,000		1.50		1,796,666		1.62		2,035,000
Exersicable at end of year	$	1.45		1,303,333	$	1.52		976,670	$	1.48		375,000

Significant option groups outstanding at December 31, 2009 and related weighted average price and life information follow:

		Outstanding								Exerciseable
Range of exercise Price		Number outstanding at December 31, 2009		Weighted Average remaining Contracual life		Weighted average Exercsie Price		Aggregate intrinsic value		Number Exersiceable at December 31, 2009		Weighted average Exercise price		Aggregate Intrinsic Value
	0.28-1.28		4,855,000		4.38		0.32		-		225,000		1.02		-
	1.29-2.28		1,105,000		1.89		1.45		-		1,011,666		1.47		-
	2.29-3.28		100,000		2.92		2.58		-		66,667		2.58		-

The Black-Scholes option pricing model was developed for use in estimating the value of traded options. Option pricing models require the input of highly subjective assumptions, including the expected stock price volatility and expected life. The expected volatility is based on historical volatilities of our stock. Historical data is used to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options are expected to be outstanding. The risk-free rate for the periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant.

For options granted during	2009			2008			2007
Weighted average fair value	$	0.23		$	0.46		$	1.34
Weighted average expected life		4.94			3.00			5.00
Valuation assumptions:
Expected Volitility		100	%		75	%		75	%
Risk - free interest rate		1.89-2.68			2.96-3.05			3.65-4.57
Expected dividend yield		0			0			0
Expected annual forfeitures	Nil			Nil			Nil

A summary of options granted and outstanding under the plan is presented below.


	Nonvested Options			Weighted-Average Grant Date Fair Value
Nonvested at December 31,2008		1,660,000			1.11
Granted		125,000			0.46
Vested		(601,671	)		1.08
Forfeited		(363,333	)		1.31
Nonvested at January 1, 2009		819,996			0.96
Granted		4,630,000			0.23
Vested		(559,996	)		0.83
Forfeited		(133,333	)		1.16
Nonvested at December 31, 2009		4,756,667			0.25

Warrants

During years ended December 31, 2006, 2007, 2008 and 2009, the Company, as part of certain private placement financings, issued warrants that are exercisable in common shares of the Company. A summary of such outstanding warrants follows:

	Exercise Price ($)		Expiry Date	Equivalent Shares Outstanding		Weighted Average Years to Expiry
Issued June 30, 2006		3.50	Jun. 30/11		1,130,000		1.50
Issued June 18, 2008		3.50	Jun. 18/10		1,300,000		0.50
Balance December 31, 2009					2,430,000		1.04

During the twelve months ended December 31, 2009, warrants exercisable into 3,693,014 common shares of the Company expired unexercised.

In accordance with FASB ASC 718, the Company uses the Black-Scholes option pricing method to determine the fair value of each warrant granted and the amount is recognized as additional expense in the statement of earnings over the vesting period of the warrants. The fair value of each warrants granted has been estimated using the following average assumptions:

	2009	2008
Risk free interest rate	1.89-2.57 %	2.96-3.05%
Expected holding period	3 Years	3 Years
Share price volatility	100%	75%
Estimated annual common share dividend	-	-

Cougar Stock Option Plan

Cougar has a stock option plan under which it may grant options to its directors, officers, employees and consultants for up to a maximum of 10% of its issued and outstanding common shares at market price at the date of grant for up to a maximum term of five years. Options are exercisable equally over the first three years of the term of the option.

A summary of options granted and outstanding under the plan is as follows:

	2009				2008				2007
	Weighted average Exercise				Weighted average Exercise				Weighted average Exercise
	Price		Shares		Price		Shares		Price		Shares
Outstanding at beginning of year	$	-		-	$	-		-	$	-		-
Options Granted		0.72		850,000		-		-		-		-
Options cancelled		-		-		-		-		-		-
Outstanding at end of year		0.72		850,000		-		-		-		-
Exersicable at end of year	$	0.72		850,000	$	-		-	$	-		-

	Outstanding				Exerciseable
Range of exersise Price	Number outstanding at December 31, 2009	Weighted Average remaining Contracual life	Weighted average Exercsie Price	Aggregate intrensic value	Number Exersiceable at December 31, 2009	Weighted average Exercise price	Aggregate Intrensic Value
0.65	750,000	4.04	0.65	-	-	-	-
1.30	100,000	4.83	1.30	-	-	-	-

	Nonvested Options		Weighted-Average Grant Date Fair Value
Nonvested at January 1, 2009		-		-
Granted		850,000	$	0.72
Vested		-		-
Forfeited		-		-
Nonvested at December 31, 2009		850,000	$	072

Cougar warrants

During 2009 Cougar issued 893,000 warrants in conjunction with various private placement made during the year. The exercise price and expiry dates are disclosed in the tables below.

	Exercise Price ($)	Expiry Date	Equivalent Shares Outstanding	Weighted Average Years to Expiry
Issued Jan 12, 2009	1.30	Jan 12/11	126,923	1.03
Issued Feb 12, 2009	1.30	Feb 12/11	157,000	1.12
Issued Feb 12, 2009	2.60	Feb 12/11	145,415	1.12
Issued Feb 27,2009	2.60	Feb 27/11	38,462	1.16
Issued Mar 25, 2009	2.60	Mar 4/11	13,846	1.17
Issued Mar 25, 2009	2.60	Mar 23/11	7,692	1.22
Issued Mar 25, 2009	1.30	Mar 4/11	76,923	1.17
Issued Apr 27, 2009	2.60	Apr 27/11	1,000	1.32
Issued June 1, 2009	2.60	Jun 1/11	325,739	1.42
Balance December 31, 2009			893,000	1.22

14.	NON CONTROLLING INTEREST

Following is a summary of the interest of the non controlling shareholders of Cougar:



Net Income Attributable to the Company's transfers (to) from Non contolling interest for the year ended December 31, 2009

Net loss attributable to Kodiak	(19,573,082	)
Transfer (to) from the non-controlling interest
Increase in Kodiak's paid-in capital for sale of 556,261 Cougar common shares to a third party.	101,764
Increase in Kodiak's paid-in capital for sale of 19,046 Cougar common shares to a third party.	13,521
Increase in Kodiak's paid-in capital for sale of 962,693 Cougar common shares to a third party.	511,664
Net transfers (to) from noncontrolling interest	626,949
Net Loss attributable to the Company and transfers from (to) noncontrolling interest	(18,946,133	)

15.	LOSS PER SHARE

A reconciliation of the numerator and denominator of basic and diluted loss per share is provided as follows:


Years ended December 31,	2009		2008		2007
Numerator:
Numerator for basic and diluted loss per share.
Net loss	$	19,573,082	$	2,074,649	$	2,571,663
Denominator:
Denominator for basic and diluted loss per share
Weighted average shares outstanding		110,121,632		108,323,376		95,850,148
Basic and diluted loss per share	$	0.18	$	0.02	$	0.03

Basic loss per share is based on the weighted average number of shares outstanding during the periods. Diluted loss is per share is based on the weighted average number of shares and all dilutive potential shares outstanding during the periods. The Company had outstanding stock options and warrants as at 31 December, 2009, 2008 and 2007, as disclosed in note 13, that were antidilutive due to the net loss of those periods.

16. COMMITMENTS AND CONTINGENCIES

Lease Commitments

As of December 31, 2009 and 2008, the Company had lease commitments for vehicles, office rent and office equipment. The following lease commitments for the years shown:

	2009		2008
Amounts payable in:
2009	$	-	$	-
2010		150,816		26,099
2011		166,642		23,856
2012		162,337		3,172
2013	$	39,797	$	-

17. FINANCIAL INSTRUMENTS

The Company, as part of its operations, carries a number of financial instruments. It is management’s opinion that the Company is not exposed to significant interest, credit or currency risks arising from these financial instruments except as otherwise disclosed.

The Company’s financial instruments, including cash and short term deposits, accounts receivable, accounts payable and accrued liabilities are carried at values that approximate their fair values due to their relatively short maturity periods.

18. RELATED PARTY TRANSACTIONS

For the twelve months ended December 31, 2009, the Company paid $73,245 (2008 - $Nil) to Sicamous Oil & Gas Consultants Ltd. (“Sicamous”), a company controlled by the CEO, President and COO of the Company for consulting services rendered by him. Of this amount, $27,727 was payable as at December 31, 2009 (2008 - $ Nil). These amounts were charged to General and Administrative Expense.

For the twelve months ended December 31, 2009, the Company paid $24,107 (2008 – $113,481), to Harbour Oilfield Consulting Ltd., a company owned by the Vice-President Operations of the Company for consulting services. Of this amount, $6,910 (2008 - $ 39,394) was capitalized to Unproved Oil and Gas Properties and $17,197 (2008 - $49,041) was charged to General and Administrative Expense. Of this amount, $13,115 was payable as at December 31, 2009 (2008 – $ Nil).

For the twelve months ended December 31, 2009, the Company paid $124,353 (2008 - $171,376) to the Chief Financial Officer. Of this amount, $20,846 was payable as at December 31, 2009 (2008 - Nil). These amounts were charged to General and Administrative Expense.

These related party transactions were non arm's length transactions in the normal course of business and agreed to by the related parties and the Company based on negotiations and Board approval and accordingly had been measured at the exchange amounts.

Note payable to related party

On November 24, 2008 the Company borrowed Cdn. $40,000 from Sicamous under the terms of a demand note bearing interest at the Royal Bank of Canada prime rate plus 1% per annum. Following is a summary of transactions regarding this related party indebtedness:

Advance received, November 2008 (Cdn. $40,000)		37,915
Currency revaluation adjustment December 31, 2008		5,074
Balance December 31, 2008 (Cdn $ 40,000)		32,841
Repayment, January 2009 (Cdn. $20,000)		(15,857	)
Advance March, 2009 (Cdn. $3,000)		2,378
Repayment June, 2009 (Cdn. $23,000)		(19,362	)
Balance, December 31, 2009	$ Nil

19. SEGMENTED INFORMATION

The Company’s two geographical segments are the United States and Canada. Both segments use accounting policies that are identical to those used in the consolidated financial statements. The Company’s geographical segmented information is as follows:

	Year Ended December 31, 2009
	U. S.			Canada			Total

Revenue, net of Royalites		-			607,469			607,469
Net Loss		36,715			19,536,367			19,573,082
Capital Assets		11,274,809			19,529,242			30,804,051
Total Assets		11,282,903			20,374,656			31,657,559
Capital Expenditures		24,221			7,454,821			7,479,042

	Year Ended December 31, 2008
	U. S.			Canada			Total

Revenue, net of Royalites	$	-		$	1,065		$	1,065
Net Loss		(490,044	)		(1,584,605	)		(2,074,649	)
Capital Assets		11,250,589			25,384,344			36,634,932
Total Assets		9,861,161			24,190,538			37,171,397
Capital Expenditures		3,270,212			11,159,779			14,429,991

	Year Ended December 31, 2007
	U. S.			Canada			Total

Revenue, net of Royalites	$	-		$	225		$	225
Net Loss		(57,193	)		(2,514,470	)		(2,571,663	)
Capital Assets		8,423,346			19,119,659			27,543,005
Total Assets		8,949,538			29,241,230			38,190,768
Capital Expenditures		7,858,511			18,519,418			26,377,929

20. CHANGES IN NON-CASH WORKING CAPITAL


	2009			2008			2007
Operating Activities:
Accounts Receivable	$	(339,582	)	$	620,554		$	(650,850	)
Prepaid Expenses and Deposits		35,608			(17,251	)		(49,613	)
Accounts Payable		536,624			147,886			11,471
Accrued Liabilities		164,919			20,848			28,891

Total	$	397,569		$	772,037		$	(660,101	)

Investing Activities
The total changes in investing activities non-cash working capital accounts, which is detailed below, pertains to capital asset additions and has been included in that caption in the Statement of Cash Flow:
Accounts Receivable	$	-		$	529,374		$	122,572
Prepaid Expenses and Deposits		(5,250	)		1,664			155,976
Accounts Payable		282,139			(638,152	)		867,152
Accrued Liabilities		-			(433,288	)		232,542

Total	$	276,889		$	(540,402	)	$	1,378,242

Financing Activities
The total changes in financing activities non-cash working capital accounts, which is detailed below, pertains to shares issued and issuable and has been included in that caption in the Statement of Cash Flow:
Deposits and Prepaids		(32,841	)		-			-
Accounts Payable		430,946			(72,417	)		83,396
Accrued Liabilities		-			(220,000	)		220,000
Note Payable to Related Party		-			32,841			-
Flow-through Share Premium Liabilty		-			-			1,125,835

Total	$	398,105		$	(259,576	)	$	1,429,231

21. SUBSEQUENT EVENTS

On January 25, 2010 the Company sold its interest in Cougar to Ore-More Resources Inc (“Ore-More”) in exchange for shares. This transaction effected the cancellation of certain indebtedness of the Company, which Ore More recently acquired from Zentrum and also resulted in the disposition of the non-controlling interest in Cougar and the acquisition of the controlling interest of Ore More. Following the closing of the transaction, Ore-More changed its name to Cougar Oil and Gas Canada.

On February 26, 2010, Cougar Oil and Gas Canada closed a formal agreement (the "Agreement") with a Canadian bank for two credit facilities. The first credit facility is a revolving demand loan in the amount of Cdn$1,000,000 at a per annum rate of prime interest plus 3.5%. The second credit facility is a non-revolving acquisition/development demand loan bearing an annual per annum interest rate of prime plus 3.0%. Under the terms of the Agreement, the two credit facilities are committed for the development of existing proved non-producing /undeveloped petroleum and natural gas reserves.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15-d-15(e)) as of the end of the period covered by this report. They concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were not adequate and effective in ensuring that material information relating to the Company would be made known to them by others within those entities, particularly during the period in which this report was being prepared.

Management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and in reaching a reasonable level of assurance, management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f)). Under the supervision and with the participation of our management, including our principal executive officer (CEO) and principal financial officer (CFO), we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the financial statements will not be prevented or detected. Management identified the following material weaknesses during its assessment of our internal control over financial reporting as at December 31, 2008 and December 31, 2007.

SEGREGATION OF DUTIES AND ACCESS TO CRITICAL ACCOUNTING SYSTEMS

As at December 31, 2009, December 31, 2008 and December 31, 2007, management believes the Company’s Internal Control over Financial Reporting did not meet the definition of adequate control, based on criteria established by Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management identified a material weakness relating the segregation of duties among certain personnel who had incompatible responsibilities within all significant processes affecting financial reporting. We also had a material weakness resulting from our failure to implement controls to restrict access to financially significant systems or to monitor access to those systems, which resulted in conflicting access and/or inappropriate segregation of duties. These material weaknesses affect all significant accounts. In addition, the 2007 restatement issues discussed below demonstrated a need to engage additional personnel or outside consulting assistance to ensure the proper accounting for non-routine accounting transactions and adherence to US GAAP, to assist in income tax planning and compliance and a review of our Canadian and U. S. income tax provisions. As a result of these material weaknesses, management has concluded that internal control over financial reporting was not effective as at December 31, 2009.

REMEDIATION OF MATERIAL WEAKNESS IN INTERNAL CONTROL

During December, 2006 and the first half of 2007, the Company hired a Controller, a new CFO, a Vice-President, Operations and additional qualified personnel. The new staff and existing management have implemented new procedures and controls for many areas of the Company’s activities. During 2007, the Company initiated a review of its corporate policies and procedures with the assistance of an outside consulting firm, with a goal of having the Company become fully SOX compliant by year end 2007. Additional policies and procedures have been implemented and others strengthened. Testing of such policies and procedures was completed in late 2007 and early 2008. In addition, the Company will endeavor to engage outside consulting assistance to ensure the proper accounting for non-routine accounting transactions and adherence to US GAAP. Beginning in 2008, the Company engaged an outside consulting firm to assist in income tax planning and compliance and beginning with our fiscal year ended December 31, 2008, to review our Canadian and U.S. income tax provisions.

As at December 31, 2009, the Company continues to have a material weakness relating to the segregation of duties among certain personnel and, as of that date, management believes that without engaging additional personnel estimated to cost a minimum of approximately $150,000 per annum, we cannot remedy such material weakness. Management believes such expenditures cannot be justified at this time when the Company is still in the early stage of operations and has just acquired proved reserves, production and cash flow. When sufficient cash flow is being generated, management will review its position. Management believes its controls and procedures related to its financial and corporate information systems are appropriate for a company of its size and mandate and, due to its internal expertise, is not dependent upon the inherent risks in external third party management of such systems. Our CFO retired on December 31, 2009, has joined the Board of Directors and continues to consult to the Company in a financial capacity and alleviate some of the segregation of duties and related weaknesses. The VP of Finance assumed the role of CFO ensuring a smooth transition.

This Annual Report on Form 10-K does not include an attestation report of the Company's registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management's report on this Annual Report on Form 10-K.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There have been no changes in our internal control over financial reporting during the fourth quarter ended December 31, 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

On November 4, 2009, the Company voluntarily requested the TSX Venture Exchange ("TSX-V") in Canada to delist its common shares from trading on the TSX-V. This voluntary delisting is not pursuant to any order or communication from the TSX-V.

Kodiak's common shares are currently quoted for trading on the Over the Counter Bulletin Board (OTCBB) in the United States under the symbol KDKN. It will continue to maintain this quotation status and Canadian shareholders will be able to continue to trade through their brokers on that market.

The Company’s Board of Directors approved the voluntary delisting from the TSX-V after weighing the required expenses and multi-jurisdictional filings to maintain a dual listing of the Company's securities against the perceived shareholder benefit accrued from trading on different platforms.

The primary reasons for the voluntary delisting request were:

Since the Company’s TSX-V listing effective December 24, 2007 to market close on October 30, 2009, liquidity analysis revealed an average daily trading volume of 270,413 shares on the OTCBB and 14,022 on the TSX-V for the period – a difference in trading volume and liquidity of over 19 times.

Following the initial Canadian based financing associated with the TSX-V listing, the Company has repeatedly experienced little to no investment interest or support from the Canadian financial community consisting of investment banks, capital markets and retail brokerage firms, and private equity firms. The primary source of equity financing has been from Europe over the last 18 months, and we do not expect that to change in the foreseeable future. Our European investors have a stated preference for the OTCBB listing versus the TSX-V, of which the latter listing they do not follow.

The Company’s Board of Directors believes that voluntarily delisting from the TSX-V and focusing on U.S. and European markets is in the best interests of our shareholders. This will eliminate the substantial cross-border financing and reporting issues.

As of October 31, 2009, the Company’s transfer agent, Computershare, revealed the shareholder geographic position of all foreign based shareholders at 61.54% and Canadian based shareholders at 38.46%, of which the vast majority of the latter is founder shareholdings and only a nominal amount in the Canadian float. As a result, the OTCBB quotation system serves shareholders of the majority of Kodiak’s shares, where the Company’s stock has been trading since December 27, 2004.

The internal and external compliance costs to maintain the listing of the Company’s shares on the TSX-V are relatively significant to a company of this size, which has not resulted in an additional benefit for shareholders in view of the low trading volume on the TSX-V.

The Financial Industry Regulatory Authority (FINRA) is the largest independent regulator for securities firms in the United States and is responsible for establishing rules governing its broker/dealer members, including OTCBB subscribing members, on conduct, qualification standards, examinations, investigations, violations, and investor and member inquiries – thus, there is a previous and demonstrated, current market for Kodiak shareholders.

Other factors:

To maintain quotation eligibility on the OTCBB, Kodiak Energy, Inc. is required to file periodic financial information with the U.S. Securities and Exchange Commission (SEC). All of the Company’s filings are located under the “Kodiak Energy, Inc.” profile on the Electronic Data Gathering, Analysis, and Retrieval (EDGAR) system through the U.S. SEC website at http://www.sec.gov.

Kodiak intends on maintaining its “foreign reporting issuer status” with the Alberta Securities Commission.

Kodiak was Sarbanes Oxley (SOX) compliant for 2008, is a fully reporting filer, and adheres to the security laws, rules, regulations and filing requirements of the U.S. SEC.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

DIRECTORS AND EXECUTIVE OFFICERS

Name	Age	Title
William Tighe	59	Chairman of the Board, CEO, COO and President
Glenn Watt	36	Vice President Operations and Director
Leslie Owens	46	Director
Gordon Taylor	62	Director
Greg Juneau	43	Director
William Brimacombe	67	Director
David Wilson	47	Chief Financial Officer, Vice President, Finance

Mr. William Tighe has held the positions of Chief Operating Officer, President and Director of the Company since September 2005 and Chief Executive Officer of the Company since December 2007. At Kodiak's 2008 annual meeting in December, he assumed the position of Acting Chairman of the Board with position of Chairman at the Company's board of directors meeting in January 2009. Since 2005, Mr. Tighe has focused on developing the Company's business interests. His past experience includes approximately thirty years in management, operations, maintenance, and more recently major and minor projects for both Canadian and other international energy companies. These positions were in a variety of field settings from the heavy oil industry, sour gas and liquids plants in Alberta and British Columbia and the sub-arctic in Canada, to design offices, construction, construction and startup, and operation of large gas/liquids processing operations in Southeast Asia. From 2004 to 2005, Mr. Tighe worked for Suncor Energy Ltd. as a Business Services Manager, Growth Planning and Development. From 2000 until 2004, he worked for Petro China International as Operations Development and Commissioning Manager. Prior to that, Mr. Tighe had extensive experience in both Alberta and internationally in the oil and gas industry. He attended the University of Calgary where he studied general science and computer science. Mr. Tighe is a director of Tamm Oil and Gas Corp., a junior heavy oil exploration and development company based in Calgary, Alberta, Canada. He holds an Interprovincial Power Engineering Certification II Class. We believe that the extensive Canadian and international oil and gas experience, coupled with the 5 years as President and COO of the Company as a fully reporting SOX compliant issuer, makes Mr. Tighe an asset to the Board of Directors of Kodiak Energy, Inc.

Mr. David Wilson has been the Vice President, Finance of the Company since November 2009. In January 2010, he also assumed the position of Chief Financial Officer of the Company. Mr. Wilson over 20 years of professional accounting experience with various public and private oil and gas exploration companies, both domestically and internationally. He has expertise in accounting, securities and regulatory standards for publicly traded companies including U.S. GAAP and Canadian IFRS. From 2006 to 2009, he was Vice President, Finance and Chief Financial Officer for Kootenay Energy Inc. From 2001 to 2005, Mr. Wilson was Vice President, Finance and Chief Financial Officer for Monroe Energy Inc. His previous financial experience consisted of progressive finance positions within various industries, including oil and gas. Mr. Wilson is also accomplished in various financing initiatives, related negotiations, and M&A transactions. His proven executive management skills in the capacities of Vice President, Finance and Chief Financial Officer were instrumental in successfully executing various strategic transactions. Mr. Wilson obtained his Certified Management Accountant designation from the Alberta Society of Management Accountants. We believe that Mr. Wilson’s qualifications, including his knowledge of both Canadian GAAP and US GAAP, oil and gas accounting and financial principles and prior successful public company roles including CFO of those companies, makes an excellent VP of Finance and CFO for Kodiak Energy, Inc.

Mr. Glenn Watt has been a director of the Company since November 2005 and Vice President, Operations of the Company since April 2007. Prior to joining Kodiak, he worked primarily in the Western Canadian Sedimentary Basin and, from May 2003 to March 2007, was drilling and completions superintendent for a large Canadian oil and gas royalty trust. Prior to that, Mr. Watt worked for a major oil and gas company as a completions superintendent. He has additional field experience working on drilling rigs in Alberta and British Columbia. Mr. Watt has an honours diploma in Petroleum Engineering Technology from the Northern Alberta Institute of Technology and a Bachelor of Applied Petroleum Engineering Technology Degree from the Southern Alberta Institute of Technology. We believe that Mr. Watt’s formal education and extensive work experience in drilling and project management in the Western Canada Sedimentary Basin makes him a valuable and key member of management and Board of Directors of Kodiak Energy, Inc.

Mr. Leslie Owens has been as a director of the Company since December 2008. He has more than 25 years of oil and gas experience, primarily in completions and production services. Since June 2009, Mr. Owens is General Manager, Operations at Pure Energy Services Ltd., a provider of production testing services, cased holed electric wireline and slickline services, specialty logging services, pressure transient analysis, and well optimization and swabbing services. Prior, he was General Manager at Canadian Sub-Surface, Energy Services Corp., a provider of cased-hole completion, production and evaluation services until the company merged with Pure Energy Services Ltd. in June 2009. From October 2001 to April 2008, Mr. Owens was in management positions with Ultraline Services Corp., a provider of wireline services. Prior to that, from October 1999 to October 2001, he was in sales with Plains Perforating Ltd., a provider of perforating services. We believe that Mr. Owens’ previous experience was with various oil and gas service companies, in positions progressing from sales to senior management, makes him an excellent independent addition to the Board of Directors of Kodiak Energy, Inc.

Mr. Gordon Taylor has been a director of the Company since February 2009. Mr. Taylor is a Calgary-based businessman with over 16 years of financial experience in mortgages, investments, real estate acquisition, and development. He is the founder and president of Liberty Mortgage Services Ltd. and since 1996 to present has specialized in syndicated mortgages. From 1992 to present, he is also founder and president of Tach Investments Ltd., a private investment company. Prior to 1992, Mr. Taylor was with Alberta Opportunity Company for over 18 years, with 15 years as Branch Manager, financing small to medium sized businesses in the province of Alberta. We believe that Mr Taylor’s lengthy financial background makes for an independent and valuable addition to the Board of Directors.

Mr. Greg Juneau has been a director of the Company since February 2009. Mr. Juneau is a Calgary-based professional engineer with over 19 years of oil and gas experience as a project engineer and manager. His areas of expertise include engineering, procurement and construction management of surface facilities. From 2000 to present, Mr. Juneau is the president and engineering manager at Segment Engineering Ltd. He coordinates full discipline engineering, procurement, construction and management (EPCM) projects consisting of oil and gas well sites, gathering systems, transmission pipelines, pump stations, satellites, batteries, compression and gas plants within British Columbia, Alberta and Saskatchewan. Mr. Juneau graduated from the University of Alberta in 1990 with a Bachelor of Science Degree in Mechanical Engineering and is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA), and Association of Professional Engineers and Geoscientists of BC (APEG of BC). As Kodiak’s projects mature, his extensive EPCM experience will provide independent review to the Board of Directors. We believe that Mr. Juneau’s extensive and full cycle oil and gas experience makes for an excellent independent addition to the Company’s Board of Directors.

Mr. William E. Brimacombe is a Canadian Chartered Accountant and, since January 2007, had been Chief Financial Officer of the Company until his retirement in December 2009 when he joined our Board of Directors. From 2000 to 2006, he was Vice-President Finance of AltaCanada Energy Corp., a publicly traded Canadian oil and gas company. Prior thereto, Mr. Brimacombe has over thirty years financial experience working for a number of public and private oil and gas companies with operations in Canada, the United States and other countries, including experience as an independent financial consultant during the years 1988 to 2000. In 2009, he became a Life member of the Institute of Chartered Accountants of Alberta with forty years membership in that organization. We believe that Mr. Brimacombe’s qualifications, including knowledge of both Canadian GAAP and US GAAP, oil and gas accounting and financial principles and prior successful public company roles including CFO of those companies, successful SOX compliance for Kodiak during his tenure as CFO, adds additional financial oversight for the Board of Directors.

During the last 10 years, no officer or director of the Company has been involved in any legal, bankruptcy or criminal proceedings or violated any federal, state or provincial securities or commodities laws or engaged in any activity that would limit their involvement in any type of business, including securities or banking activities. There are no direct family relationships between or amongst any of the above directors or executive officers.

COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT

Section 16(a) of the Exchange Act requires the Company's directors and executive officers, and persons who own more than 10% of the outstanding shares of the Company's Common Stock, to file initial reports of beneficial ownership and reports of changes in beneficial ownership of shares of Common Stock with the Commission. Such persons are required by Commission regulations to furnish the Company with copies of all Section 16(a) forms they file.

Based solely upon a review of Forms 3 and 4 and amendments thereto furnished to the Company during the year ended December 31, 2009, and upon a review of Forms 5 and amendments thereto furnished to the Company with respect to the year ended December 31, 2009, or upon written representations received by the Company from certain reporting persons, that no Forms 5 were required for those persons for the year ended December 31, 2009.

AUDIT COMMITTEE AND FINANCIAL EXPERT

During the year end December 31, 2009, the Audit Committee met five times. The Audit Committee’s role is financial oversight. Our management is responsible for the preparation of our financial statements and our independent registered public accounting firm is responsible for auditing those financial statements. The Audit Committee is not providing any special assurance as to our financial statements or any professional certification as to the registered independent accounting firm’s work.

The Audit Committee is directly responsible for the appointment, compensation, retention and oversight of Kodiak’s independent registered accounting firm. The Audit Committee, among other things, also reviews and discusses Kodiak’s audited financial statements with management.

Our Audit Committee is comprised of three directors: Gordon Taylor, Leslie Owens and Greg Juneau, who are independent.

CODE OF ETHICS

A code of ethics relates to written standards that are reasonably designed to deter wrongdoing and to promote:

Honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships.

Full, fair, accurate, timely and understandable disclosure in reports and documents that are filed with, or submitted to the Securities and Exchange Commission and in other public communications made by the Company.

Compliance with applicable government laws, rules and regulations.

The prompt internal reporting of violations of the code to an appropriate person or persons identified in the code.

Accountability for adherence to the code.

In October, 2007, the Company adopted a formal code of business conduct. The Board of Directors evaluated the business of the Company and its personnel and has determined that its business operations are operated by a growing number of persons, some of who are also officers, directors and employees of the Company and others who are independent contractors. Although general rules of fiduciary duty and federal, state and provincial criminal, business conduct and securities laws are adequate ethical guidelines, a formal written code of business conduct would provide additional ethical standards of conduct to which the Company’s personnel should comply.

Requests for copies of our current Code of Ethics, which will be provided at no charge, should be sent in writing to Kodiak Energy, Inc., 833 4th Avenue S.W., Suite 1122, Calgary, AB T2P 3T5, Canada.

ITEM 11. EXECUTIVE COMPENSATION

COMPENSATION OF EXECUTIVE OFFICERS

The following table summarizes compensation of our Chief Executive Officer, President and Chief Operating Officer; Chief Financial Officer; Vice President, Finance; and Vice President, Operations for the fiscal year ended December 31, 2009.

SUMMARY COMPENSATION TABLE
Name and Principal Position	Year	Salary	Stock Awards	Option Awards (5)	Non-Equity Incentive Plan Compensation	Change in Pension Value and Nonqualified Deferred Compensation Earnings	All Other Compensation	Total
William S. Tighe, CEO, President and COO (1)	2009	$105,420	0	$72,464	$0	$0	$0	$185,959
William E. Brimacombe, CFO (2)	2009	$124,353	0	$67,666	$0	$0	$0	$239,042
Glenn Watt, Vice President, Operations (3)	2009	$105,708	0	$72,464	$0	$0	$0	$185,945
David Wilson, Vice President, Finance (4)	2009	$21,934	0	0	0	0	0	$21,934
(1) Mr. Tighe’s compensation was directly to him as a salaried employee for the first 3 months of 2009 and as a contractor to the Company for 9 months. (2) Mr. Brimacombe’s compensation was paid directly to him for services rendered by him as Chief Financial Officer of the Company for 2009. (3) Mr. Watt’s compensation was paid to Harbour Oilfield Consulting Ltd., a company owned by Mr. Watt for services rendered by him as Vice President, Operations of the Company, the first 4 months of 2009 and directly to him as a salaried employee for 8 months. (4) Mr. Wilson’s compensation was paid directly to him for services rendered by him as Vice President, Finance of the Company for 2009. (5) This is the estimated 2009 cost of stock options granted based on the Black-Scholes valuation method.

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
	Option Awards					Stock Awards
Name	Number of Securities Underlying Unexercised Options Exercisable	Number of Securities Underlying Unexercisable Options Unexercisable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options	Option Exercise Price	Option Expiration Date	Number of Shares or Units of Stock that have not Vested (1)	Market Value of Shares or Units of Stock that have not Vested (1)	Equity Incentive Plan Awards, Number of Unearned Shares, Units or Other Rights that have not Vested	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights that Have not Vested
William S. Tighe	200,000	0(1)	-	$1.50	10/23/11	0	0	0	0
	-	900,000	-	$0.28	06/24/14	0	0	0	0
Glenn Watt	200,000	0(1)	-	$1.50	10/23/11	0	0	0	0
	-	900,000	-	$0.28	06/24/14	0	0	0	0
William E. Brimacombe	186,666	93,334(2)	-	$1.29	01/03/12	0	0	0	0
	-	60,000	-	$0.28	06/23/14	0	0	0	0
David Wilson	-	300,000	-	$0.45	11/01/14	0	0	0	0
(1) Unexercised options vest 66,667 on Oct. 23/09. (2) Unexercised options vest 93,333 on Jan. 03/09 and 93,334 on Jan. 3/10.

COMPENSATION DISCUSSION AND ANALYSIS

Overview of Compensation Program and Philosophy

The Company has three executive officers, two of whom are the Company’s directors. The Board of Directors serves as the Company’s compensation committee, initiates and approves most compensation decisions. Annual bonuses for executives are determined by the Board of Directors.

The goal of the compensation program is to adequately reward the efforts and achievements of executive officers for the management of the Company. The Company has no pension plan and no deferred compensation arrangements. The Company has not used a compensation consultant in any capacity.

We have a formal employment contract with Mr. William Tighe and formal consulting contracts with Mr. Glenn Watt and Mr. William Brimacombe or their consulting companies. During 2009, Mr. William Tighe was to be paid Cdn $10,000 per month. During 2009, Harbour Oilfield Consulting Ltd., a company owned by Mr. Watt, was to be paid Cdn $10,000 per month. During 2009, Mr. William Brimacombe was paid Cdn. $110 per hour, and a monthly vehicle allowance of Cdn. $800. During 2009, David Wilson was to be paid $10,000 per month and a monthly vehicle allowance of Cdn. $1,200.

Compensation of Directors

The directors of the Company are not paid any cash compensation. We reimburse each of our directors for reasonable out-of-pocket expenses that they incur in connection with attending board or committee meetings.

On January 4, 2006, the Company adopted a stock-based compensation plan, under which each director of Kodiak would receive 120,000 options upon becoming a director and an additional 80,000 options in the second year and 200,000 options in the third year for each year or part of a year served as a director. On July 19, 2006 the stock option plan was approved by the shareholders of the Company. On October 23, 2006, options granted to directors were adjusted to 200,000 shares per director. The exercise price of such options is the market price per share on the date of grant.

On June 24, 2009 the Company announced that its board of directors has, pursuant to the Corporation’s incentive stock option plan, approved the granting of stock options “Options” to directors, officers and other personnel to acquire an aggregate of 4,330,000 common shares of the Corporation (“Common Shares”) at an exercise price of $0.28 per Common Share – the market closing price of the Corporation’s common shares on June 23, 2009. Of the total options granted, an aggregate of 3,300,000 Options were granted to directors and executive officers as follows and are for a five year term with vesting occurring for one third of the options at the end of each of the first three years:

No named directors or executive officers exercised any stock options during fiscal 2009.

DIRECTOR COMPENSATION TABLE

The table below summarizes the compensation paid by us to our non-employee directors during the year ended December 31, 2009.

Name	Fees Earned or Paid in Cash	Stock Awards (1)	Option Awards (2)	Non-Equity Incentive Plan Compensation	Change in Pension Value and Nonqualified Deferred Compensation Earnings	All Other Compensation	Total
Gordon Taylor	$0	N/A		N/A	N/A	$0
Leslie Owens	$0	N/A		N/A	N/A	$0
Greg Juneau	$0	N/A		N/A	N/A	$0
(1) No stock awards were made during 2008, 2007, 2006 or 2005. (2) This is the estimated 2009 cost of stock options granted October 23, 2006 based on the Black-Scholes valuation method. (3) Mr. Jones resigned as a director effective February 27, 2009, Mr. Schriber resigned as a director effective April 15, 2009 and their options have expired.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth, as of the date of this report, information relating to the beneficial ownership of our common stock by those persons known to us to beneficially own more than 5% of our capital stock, by each of our directors, proposed directors and executive officers, and by all of our directors, proposed directors and executive officers as a group. The address of each person is set out in the footnotes to the table.

Name of Beneficial Owner or Director	Number of Shares of Class	Percent of Class (1)
William Tighe (3)	12,644,000	11.45%
Glenn Watt (4)	9,012,000	8.16%
Gordon Taylor	0
Leslie Owens	320,000	*
Greg Juneau	40,000	*
William Brimacombe (4)	200,000	*
David Wilson	0
All directors and executive officers as a group (six persons)	26,821,000	24.29%
* Less than 1% (1) Based on 110,407,186 common shares outstanding as at December 31, 2009 and as at the date of this report.
(2) Including 19,000 shares held directly by Mr. Tighe and 12,625,000 shares held by Sicamous Oil and Gas Consultants Ltd. (‘Sicamous”), a company owned by Mr. Tighe, a director and CEO, COO and President of the Company and his wife Diane Tighe. The address for Mr. Tighe and Sicamous Oil and Gas Consultants Ltd. is 68 Silver Springs Drive N.W., Calgary, AB.
(3) Including 6,012,000 shares held directly by Mr. Watt, a director and Vice President-Operations of the Company and 3,000,000 shares held by 697580 Alberta Ltd., a company wholly-owned by Kathleen, Jana and Ryan Tighe and of which Mr. Watt is the sole officer and director. The address for Mr. Watt and 697580 Alberta Ltd. is 3405 15 th St. S.W., Calgary, AB, T2T 5X3.
(4) Shares held directly by William Brimacombe, previous CFO and current Director of the Company as at December 31, 2009, whose address is 68 Arbour Wood Close N.W., Calgary, AB T3G 4A8.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

DIRECTOR INDEPENDENCE

We undertook a review of the independence of our directors and, using the definitions and independence standards for directors provided in the rules of The Nasdaq Stock Market, although not required as the standard for the Company as it is traded on the Over-the-Counter Market considered whether any director has a material relationship with us that could interfere with his ability to exercise independent judgment in carrying out his responsibilities. As a result of this review, we determined that Leslie Owens, Gordon Taylor and Greg Juneau each are an "independent director" as defined under the rules of The Nasdaq Stock Market.

RELATED TRANSACTIONS

For the twelve months ended December 31, 2009, the Company paid $73,245.13 (2008 - $Nil) to Sicamous Oil & Gas Consultants Ltd. (“Sicamous”), a company controlled by William S. Tighe, CEO, President and COO, and Chairman of the Board of the Company for consulting services rendered by him. Of this amount, $19,029 was payable as at December 31, 2009 (2008 - $ Nil). These amounts were charged to General and Administrative Expense.

For the twelve months ended December 31, 2009, the Company paid $24,107 (2008 – $113,481), to Harbour Oilfield Consulting Ltd., a company owned by Glenn Watt, Vice-President Operations and Director of the Company for consulting services. Of this amount, $19,029 was payable as at December 31, 2009 (2008 – $ Nil) and of this amount, $6,910 (2008 - $ 39,394) was capitalized to Unproved Oil and Gas Properties and $17,197 (2008 - $49,041) was charged to General and Administrative Expense.

For the twelve months ended December 31, 2009, the Company paid $124,353 (2008 - $171,376) to William Brimacombe, the former Chief Financial Officer. Of this amount, $19,439 was payable as at December 31, 2009 (2008 - Nil). These amounts were charged to General and Administrative Expense.

ITEM 14. PRINCIPAL ACCOUNTANTING FEES AND SERVICES

AUDIT FEES

The Company paid audit fees to Meyers Norris Penny LLP for December 31, 2008 totaling $80,000 and estimate the 2009 fees to be $182,000. The 2009 fees include approximately $62,000 relative to Internal Controls and Financial Reporting ( 2008 - $55,000).

AUDIT-RELATED FEES

None

TAX FEES

None

ALL OTHER FEES

None

AUDIT COMMITTEE POLICIES AND PROCEDURES

In accordance with our policy, all of the above services were pre-approved by the Company's Audit Committee of the Board of Directors.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)

Exhibits

23.1	Consent of Meyers Norris Penny LLP

31.1	Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)of the Exchange Act, as enacted by Section 302 of the Sarbanes-Oxley Act of 2002.(1)

31.2	Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)of the Exchange Act, as enacted by Section 302 of the Sarbanes-Oxley Act of 2002.(1)

32.1	Certification of Chief Executive Officer, pursuant to 18 United States Code Section as enacted by Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	Certification of Chief Financial Officer, pursuant to 18 United States Code Section as enacted by Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on March 31, 2010.

	KODIAK ENERGY, INC.
	By: /s/ William Tighe Name: William Tighe Title: President and Chief Executive Officer

In accordance with the Exchange Act, this Report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated.

/s/ William Tighe

William Tighe, Chairman, Chief Executive Officer, Chief Operating Officer and President

(Principal Executive Officer

/s/ Dave Wilson

Dave Wilson, Chief Financial Officer

(Principal Financial and Accounting Officer)

/s/ Glenn Watt

Glenn Watt, Vice President Operations and Director

/s/ Gordon Taylor

Gordon Taylor, Director

/s/ Gregory Juneau

Gregory Juneau, Director

/s/ Leslie R. Owens

Leslie R. Owens, Director

/s/ William E. Brimacombe

William E. Brimacombe, Director

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