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, 2010

[ ] 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 4th 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 issued and outstanding of each of the registrant’s classes of common equity, as of April 13, 2011: 119,683,294 Common Shares, $0.001 par value.

DOCUMENTS INCORPORATED BY REFERENCE: None.

KODIAK ENERGY, INC.

Form 10-K

For the Fiscal Year Ended December 31, 2010

TABLE OF CONTENTS

PART I

ITEM 1.	BUSINESS	3

ITEM 1A.	RISK FACTORS	11

ITEM 1B.	UNRESOLVED STAFF COMMENTS	18

ITEM 2.	PROPERTIES	18

ITEM 3.	LEGAL PROCEEDINGS	28

ITEM 4.	[RESERVED]	28

PART II

ITEM 5.	MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	29

ITEM 6.	SELECTED FINANCIAL DATA	30

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	30

ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	46

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	47

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	48

ITEM 9A.	CONTROLS AND PROCEDURES	48

ITEM 9B.	OTHER INFORMATION	49

PART III

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	51

ITEM 11.	EXECUTIVE COMPENSATION	54

ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	56

ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS, AND DIRECTOR INDEPENDENCE	57

ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	58

PART IV

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	59

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 engaged in the development and exploration for natural resources. During the year ended December 31, 2009, the Company transitioned from a development stage enterprise to an operating company. 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, 2010, 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.

On January 25, 2010, the Kodiak finalized a share purchase agreement between the OreMore Resources (“Oremore”) and the Company whereby the Company sold to OreMore a total of 8,461,549 shares of the common shares of CEI held by Kodiak. The share purchase agreement called for the OreMore to issue a total of 1.5 shares of common stock for each share of CEI tendered by Kodiak, resulting in the OreMore issuing a total of 12,692,324 shares of common stock to Kodiak. As further consideration for the acquisition of the CEI common shares, the OreMore forgave all current indebtedness owed to OreMore by Kodiak and guaranteed by Cougar Energy, Inc which was in the amount of $1,296,889 USD. An additional condition to the agreement was that a total of 12,000,000 restricted common shares of the Company were cancelled and Kodiak would nominate two board members to the Board of OreMore until the next AGM of OreMore. Subsequent to that event, OreMore changed it’s name to Cougar Oil and Gas Canada, Inc and a 3 for 1 share split was completed. At time of filing, Kodiak owns 59.74% of the outstanding shares of Cougar Oil and Gas Canada, Inc and files Cougar financials on a consolidated basis.

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, 2010 consolidated financial statements.

The accompanying consolidated financial statements in this annual report on Form 10-K include the accounts of the Company, 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”), an inactive Delaware company; and one majority- owned subsidiary, Cougar Oil and Gas Canada Inc. In British Columbia, Canada, the Company operates under the assumed name of Kodiak Bear Energy, Inc. All significant inter-company transactions have been eliminated in consolidation.

OIL AND GAS PRODUCTION

As of December 31, 2010, the Company had production on a consolidated basis from its Cougar holdings. The Company had no production from its other holdings in New Mexico.

During 2010 the Cougar had net daily crude oil production ranging from a low of approximately 80 barrels per day to a high of approximately 225 barrels per day. The Companies monthly crude oil production has ranged from 3,170 barrels to 5,874 barrels. Management believes the current group of producing wells is capable of daily production exceeding 250 barrels per day but this production potential has been curtailed as a result of ongoing maintenance and repair issues over the reporting period. As these maintenance and repair issues are resolved it is anticipated production will increase accordingly. It is also anticipated production will increase as a result of the ongoing development drilling operations. We averaged $30.00/bbl Cdn for the year for operating costs including maintenance costs. We believe that through ongoing maintenance and upgrades, we will reduce those costs to the $25 Cdn range and perhaps as low as $17 Cdn which we have experienced for short periods of time. We continue to receive $50 plus as a net back after royalties and are net positive for operations at year end.

Refer to the Companies reserves report for additional information regarding NPV and forecast production.

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 $30/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 First Nations JV 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 2011:

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 or debt reduction

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

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, 2010, we held approximately 46,970 gross acres under oil and gas leases. 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, 2010, approximately 12% of our oil and gas leases were held by production and will be held indefinitely

In the Trout Area, Alberta as of December 31, 2010, we held oil and gas leases on approximately 15,580 gross acres, of which approximately 65% are held indefinitely and 35% are due to expire in 2015 and are not currently held by production.

In the Alexander Area, Alberta as of December 31, 2010, 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 Lucy, British Columbia as of December 31, 2010, 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 Sofia and Speardraw Areas, northeast New Mexico as of December 31, 2010, we hold CO2 and oil and gas leases on approximately 29,712 gross acres, of which approximately 29,712 gross acres (100%) are not currently held by production. Expiries range from 2011 Q2 to 2013 Q2.

In the Hill County Area, northwest Montana as of December 31, 2010, 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 2011 Q2.

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, 2010, 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 Alexander 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.

Development Stage	Includes all companies engaged in the preparation of an established commercially producible oil or gas accumulations (reserves) for its extraction, which are not in the production stage.
Exploration Stage	All companies engaged in the search for oil or gas accumulations (reserves), which are not in either the development or production stage.
Feasibility Study	A detailed report assessing the feasibility, economics and engineering of placing an oil or gas mineralization into commercial production.
Development and Production status	Each of the reserves categories (proved, probable and possible) may be divided into developed and undeveloped categories.
Proven reserves	Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
Probable reserves	Reserves for which quantity and grade and/or quality are computed from information similar to Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
Possible reserves	Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.
Developed Reserves	Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

Developed Producing Reserves	Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
Developed Non-Producing Reserves	Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.
Undeveloped Reserves	Undeveloped Reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned.
Prospect	An area prospective for economic mineralization’s based on geological, geophysical, geochemical and other criteria
Equisetum Field.	This is a strike area where a gas or oilfield has been established and the Energy Resources Conservation Board (ERCB) of the Province of Alberta had issued a spacing unit or other approval. The Equisetum Field is located in the general area of West of the 5th Meridian, Township 88, and 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 5th Meridian, Townships 89 to 92, and 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.).

For ease of reference, the following conversion factors are provided:

1 mile (mi)	= 1.609 kilometers (km)
1 yard (yd.)	= 0.9144 meter (m)
1 acre	= 0.405 hectare (ha)

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 Recently emerged from a Development Stage Company Implementing a New Business Plan

We recently emerged from 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.

Title to 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

ITEM 2. PROPERTIES

CANADA

Through Kodiak’s approximate 60% ownership of the subsidiary, Cougar Oil and Gas Canada, Inc., the Company’s Canadian 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;

First Nations Joint Venture Project, Alberta – exploration and development opportunities within the adjacent to the Trout Core Properties.;

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 Oil and Gas Canada, Inc., the Company’s majority-controlled Canadian subsidiary, completed the following transactions:

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 First Nation Joint Venture 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 installments 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 First Nation Joint Venture 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 1-3 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.

During 2010 the Cougar had net daily crude oil production ranging from a low of approximately 80 barrels per day to a high of approximately 225 barrels per day. Cougars monthly crude oil production has ranged from 3,170 barrels to 5,874 barrels. Management believes the current group of producing wells is capable of daily production exceeding 250 barrels per day but this production potential has been curtailed as a result of ongoing maintenance and repair issues over the reporting period. As these maintenance and repair issues are resolved over the next year it is anticipated production will increase accordingly. It is also anticipated production will increase as a result of the ongoing development drilling operations. We averaged $30.00/bbl Cdn for the year ended 2010 for operating costs including maintenance costs. We believe that through ongoing maintenance and upgrades, we will reduce those costs to the $25 Cdn range and perhaps as low as $17 Cdn which we have experienced for short periods of time. We continue to receive $50 plus as a net back after royalties and are net positive for operations at year end.

Refer to the Companies reserves report for additional information regarding NPV and forecast production.

The Trout field is a technically complicated field to operate as a result of two common wellbore scenarios. These scenarios include managing very high water cuts which results in excessive equipment fatigue and the extremely corrosive uphole formations which result in multiple casing failures. The Company identified these two scenarios prior to purchasing the Trout properties and believes the technical complexity of the Trout field reduces competition from entering the area resulting in additional available economic upside. Through our close attention to detail, extensive operations/maintenance experience, both down hole and at surface – we have the ability to manage costs, technical problems at a level not typically possible by majors.

GLJ Petroleum Consultants Ltd., Reserve Evaluations and Operations Update (October 1, 2009, December 31, 2009 and December 31, 2010 )

These independent engineering reports were prepared by GLJ and are based on the acquisitions of September 30, 2009 and October 1, 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.

First Nations Joint Venture 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) represented that they were 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 represented, 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 was 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.

In June of 2010 – CREEnergy defaulted on its agreements with Cougar Oil and Gas Canada, Inc and Cougar terminated any funding at that time. Cougar had met all the commitments and terms required by the agreements and that was acknowledged by CREEnergy but CREEnergy could not deliver the leases as promised. Cougar continued to find a solution with CREEnergy, but as of year-end, discussions had broken down. Once Cougar became aware of the default of CREEnergy, Cougar opened negotiations directly with the First Nation Tribal Council of Peerless Trout directly and has continued on with that process since. We have established a good working dialogue and created employment. In the seismic program we became a major employer of the community for the duration of that project. We continue to work with the Council toward formalizing a Joint Venture. Cougar is exploring recourse against CREEnergy to recover funds advanced for the agreements.

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 – This well was sold in September 2010 for $210,000 Cdn for P1 reserve value.

55% working interest in the Alexander property – 1 shut in oil well with a single well battery, 1 suspended well. Production of approximately 14 bbl/d net production upon restarting shut in oil well in June 2010.

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.

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 license. 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 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. In Q4 2010 the Mackenzie Valley Pipeline Project received partial regulatory approval, however at time of filing there has been no commitment by industry owners of the pipeline to construction.

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 no current economic production potential, the well was abandoned. The leases expired in Q3 2010.

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.

Kodiak has entered into a Farmout Agreement with a private company to develop the deeper rights of Kodiak’s approximate 30,000 gross acres of oil and gas rights in NE New Mexico. Kodiak retains the rights to the CO2 and Helium. The transaction anticipates additional seismic work and/or drilling of a number of wells on the Farmout acreage or before June 1, 2011. The Farmee will earn 100% of pre-selected, semi-contiguous 6-section blocks for each 2000’ well drilled until their continuous option or right to earn ceases. Farmor will retain a convertible overriding royalty of 7.5% on Helium and 5% on balance of rights (no deductions) on the test well blocks and a 25% potential working interest in an Area of Mutual Interest opportunity. There is a provision for a drop fee in the event of default on the part of the Farmee.

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 majority of the acreage to expire As of December 31, 2010, 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 balance of the Montana leases will expire in 2011 Q2.

OFFICE PROPERTY

During December, 2009, Kodiak Energy, Inc. relocated its offices to 833 4th Avenue S.W., Suite 1120, Calgary, AB, T2P 3T5. Through Cougar Oil and Gas Canada, 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 on the OTC:BB by quarter for fiscal 2010 and 2009 were as follows:

	Over the Counter
	Bulletin Board
	(U. S. Dollars)
	High			Low

Year ended December 31, 2010
First Quarter		$	0.45			0.25
Second Quarter		$	0.30			0.14
Third Quarter		$	0.19			0.09
Fourth Quarter		$	0.28			0.09


Year ended December 31, 2009
First Quarter		$	0.64		$	0.32
Second Quarter		$	0.41		$	0.12
Third Quarter		$	0.77		$	0.25
Fourth Quarter		$	0.72		$	0.23

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, 2010 there were 119,683,294 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, 2010:

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		6,535,000		1.02		2,595,000
Equity compensation plans not approved by security holders		--		--		--
Total		6,535,000		1.02		2,595,000

ITEM 6. SELECTED FINANCIAL DATA

Not required

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 majority owned subsidiary, Cougar Oil and Gas Canada, Inc., the Company’s focus is:

PLANS FOR GROWTH

Trout Operations Growth Plans – The Company has prepared a multifaceted development program that is designed to carry the Company forward with the overall goals of increasing production. The plan is to efficiently execute field programs that combine the optimization of existing wells and infrastructure with additional infill drilling and supplemented with land acquisitions and 3D seismic supported exploration drilling. This combination of field operations represents a balanced portfolio of risk versus reward, which can be easily adjusted depending on cash flow, commodity prices and financing.

Field Optimization – Following the acquisition of the properties in the Trout area all of the existing wellbores and production practices were reviewed to identify inefficient practices. Approximately thirty field optimization projects were identified during the field review. The projects were primarily focused around field management and deliverability of existing assets.

The Company has finished implementing approximately half of the optimization projects originally identified during the field review, which resulted in a production increase in excess of 250%. The projects implemented in the field have included repair and replacement of surface and down hole production equipment, implementation of chemical enhancement programs and debottlenecking of pipeline and infrastructure facilities. The Company plans to continue to execute the remaining field optimization programs over the next 12 months.

During the last couple of months Cougar has been working on several well reactivations in the Trout production field.

The 10-21 reactivation involved deepening the existing well by approximately 15 meters to penetrate a previously unproduced Keg River oil formation. Last week the Corporation successfully installed a packer in the wellbore to shutoff an uphole water source which will allow for the Keg River to be efficiently produced. The well also had a temporary hydraulic pumpjack installed on it and this has been replaced with a conventional pumpjack which will allow a substantially larger production rate.

The 13-25 reactivation involved repairing a wellbore and pumpjack that had been shut in for over three years. The downhole work was successfully repaired with no problems but the pumpjack repair took longer due to time required to get the gear box repaired. A maintenance crew recently finished all of the repair work and the well is currently on production.

The 11-22 reactivation involved a series of downhole repairs and installation of surface equipment. The downhole work included replacing a badly corroded production liner and stimulating the productive Keg River zone with an acid wash. The surface equipment will be moved from another site once the snow has melted and the lease has dried up. It is anticipated the 11-22 reactivation will be finished in Q2.

The reactivated wells also benefit from a 5% royalty holiday for the first twelve months of production. The royalty incentive was put in place by the provincial government and provides for very attractive economics and a quicker project payout.

Infill Drilling – The majority of the wells on the Trout properties were drilled almost twenty years ago when oil prices were much lower and infrastructure was much less developed. Infill drilling is an important optimization technique in which new vertical, directional and horizontal wells are added to an existing pool to maximize the total oil recovery.

The Company recently acquired 12 Km2 of 3D seismic over a core area of the existing property which complements the 3D seismic acquired in the original acquisition. The Company has finished evaluating these two 3D seismic surveys over their Trout and Peerless properties and has identified an additional 4-5 infill drilling locations to increase the overall drainage of the oil reserves. These infill locations have an expected find and development (F&D) cost of $5-7 per barrel. The Company plans include the first 2-infill wells in Q1, 2011. See subsequent event notes.

The Company has evaluated the overall seismic mapping for the area and has planned an extensive 3D program to be initiated in Q1, 2011. The size of this 3D program coupled with the drill results will support additional drilling programs described below. See subsequent event notes

In December of 2010, the company initiated licensing of 2 wells for an infill drilling program for Q1 2011. The horizontal well was initiated in late February of 2011.

The drilling, completion and workover operations in the Trout field have finished and the equipment has been demobilized back to the Red Earth area in anticipation of spring road bans. The planned second new drill has been deferred until the Corporation’s Q3 drilling program. There was not enough time to drill the second well before the spring weather resulted in road bans being implemented in Alberta. If the drilling rig was not moved off before road bans the Corporation would have been responsible for a very large stand-by charge every day the drilling rig and equipment was stranded by the road bans so the decision was made by management to demobilize the drilling equipment after the first well was finished.

Cougar finished drilling the horizontal Keg River oil well on March 20, 2011. The horizontal leg was successfully drilled in the top two (2) meters of a ten (10) meter thick Keg River zone and has approximately 400 meters of horizontal productive formation. Upon entering the Keg River formation there was an immediate loss of circulation and increase of wellbore gas indicating a substantial reservoir was encountered. Using electro-magnetic directional tools the Corporation was able to successfully steer the horizontal wellpath to the required endpoint.

Once the drilling rig moved off the horizontal location the service rig and production equipment were moved on and rigged up. The Keg River in the Trout field has excellent inflow capability due to the substantial porosity and permeability and as such does not require the costly and time consuming stimulation work required by most of the current tight oil plays. The completion operations for Cougar’s horizontal well consisted of landing the tubing string and swabbing in multiple spots along the toe to the heel of the horizontal wellbore to confirm and induce formation inflow. Throughout the swabbing test the fluid level was maintained in the casing indicating a strong inflow of formation fluids. The final production equipment including the bottom hole pump and rods was run and the well has been put on production. It is anticipated it will take several weeks to recover all of the lost drilling fluids and begin producing the Keg River reservoir fluids.

The new wells benefit from a 5% royalty holiday for the first twelve months of production. The royalty incentive was put in place by the provincial government and provides for very attractive economics and a quicker project payout.

Cougar has completed the initial review of the processed 3D seismic data that was acquired in January. The seismic data confirms the multi-well vertical and horizontal development potential of the existing Keg River and Granite Wash oil pools but the 3D seismic also identified several new undeveloped oil reservoirs. The development drilling locations are key to increasing production and cash flow and the new undeveloped reservoirs can add significant reserves for the company to pursue. The Corporation is finalizing the locations for the next drilling program and expects to begin the permitting process by the end of April once the next phase seismic review has been completed.

Additional Development – In addition to the production optimization and infill drilling projects, The Company has been aggressively planning out the future growth for the Company. These plans include the acquisition of existing assets in the area and the development of neglected production areas. The Company is continuously evaluating acquisition opportunities in the core area and will act on these opportunities if the project details and economics are synergistic. Development plans include the following:

(a)

The Company has identified several neglected production areas and has implemented a strategy to acquire land from public or private landowner around these areas whenever possible. Once the land has been acquired the Company will typically perform some additional seismic acquisition and review and then proceed with the drilling operations.

(b)

The Trout area has excellent well control to assist the modeling of the future drilling programs. The majority of the wells drilled in the area were cored which allows for a detailed rock evaluation in additional to the conventional well log information. There is an important blend of geological and geophysical analysis to identify the target formations and the structure required to trap the oil in place.

(c)

The Company is also evaluating other production areas in western Canada as potential acquisition targets and secondary core areas.

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 economic 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.

The First Nation Joint Ventures

First Nation ventures provide additional drilling and development opportunities with adjacent land to our Core Trout Project that may use the existing infrastructure. The Company continues to actively work on the First Nation joint ventures with a goal of responsible development of the leased oil and natural gas mineral rights. Private First Nation land represents some of the largest unleased blocks of mineral rights in the province of Alberta. Cougar has identified this type of Joint Venture as a strategically critical growth opportunity. The Company had paid an exclusivity fee to an First Nation agent, which provides the opportunity to lease specific mineral rights. The Company is also currently working with other First Nation groups to develop mutually beneficial joint venture agreements, which will allow Cougar and the First Nations to explore and develop conventional oil and natural gas prospects on both private and public lands. These joint venture projects will generally be developed using traditional exploration and development techniques, which include leasing blocks of mineral rights and using seismic and drilling to develop the prospects. Further information regarding these joint ventures will be provided when available.

Current Status

In June of 2010 – CREEnergy defaulted on its agreements with Cougar Oil and Gas Canada, Inc. and Cougar terminated any funding at that time. Cougar had met all the commitments and terms required by the agreements and that was acknowledged by CREEnergy but CREEnergy could not deliver the leases as promised. Cougar continued to work to find a solution with CREEnergy, but as of yearend, discussions had broken down. Once Cougar became aware of the default of CREEnergy, Cougar opened negotiations directly with the Peerless Trout First Nation directly and has continued on with that process since. We have established a good working dialogue and created employment. In the 2011 Q1 Trout 3D seismic program Cougar became a major employer of local Peerless Trout Lake First Nation contractors and labourers for the duration of that project. We continue to work with the Chief and Council toward formalizing a Joint Venture. Cougar is exploring recourse against CREEnergy to recover funds advanced for the agreements.

Northern Alberta – First Nations Joint Ventures:

•

Approximately 75,000 gross acres for access and development inside the land claim

•

Approximately 90,000 gross acres for development outside the land claim in identified 2 mile perimeter currently tendered as Joint Venture – Cougar 85% and operator

–

Light crude and natural gas prospects

Project Status:

•

Negotiations underway to develop and finalize Joint Venture agreements with communities to develop oil and natural gas prospects within the Peerless Lake and Trout Lake land claim.

•

In Parallel - Develop Joint Venture agreement to acquire, explore, develop and operate adjacent lands to the benefit of both Cougar and the Peerless Trout First Nation – Native Joint Ventures have priority with province over other industry and thus reduced competition for a Cougar/Peerless Trout First Nation JV.

Operating Plan – 2011/2012:

•

Explore and develop lands already identified by 2D and 3D seismic acquired - targeting Keg River light oil prospects

•

Acquire additional seismic and perform drilling programs

•

Execute similar maintenance programs on existing wells as Trout properties

•

Acquire additional lands adjacent to the land claim in a Joint Venture structure (anticipated model is 85/15 shared ownership).

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 two existing wells, a development into a producing property may be possible that may show the large recoverable reserves seen in the area.

The current intention is to perform the previously planned vertical and horizontal work programs for the license. In lieu of obtaining our own financing, we are actively enlisting joint venture partners to move the project forward by way of divesting part of our interest. Monthly the Company reviews the opportunity and balances the risk versus reward, which can be adjusted depending on cash flow, commodity prices and financing. When the stability of natural gas prices over a period of time that then translates into a netback on the Lucy prospect we will look to assign capital dollars to the project. Until then there is no expiry on the lease.

Manning Heavy Oil Project

See subsequent event notes

On March 17, 2011 Cougar has entered into a two phase farm-in agreement with TAMM Oil and Gas Corporation (TAMM) which will ultimately result in Cougar earning a 50% working interest in approximately 47 sections or 30,000 acres of heavy oil prospective lands in the Manning area. This is in the same area as the heavy oil farm-in agreement previously announced by the Corporation on February 14, 2011. TAMM originally acquired these lands in 2008 and has a previously prepared independent third party estimate of 3.14 billion barrels of original oil in place

for the prospect.

The Farm-in agreement has two earning phases which will allow Cougar to become the operator and earn a 50% working interest in the prospect. The first phase of the farm-in is a work commitment to earn a 30% working interest of the TAMM prospect. The work commitment will consist of Cougar spending $2.5 million over the next 12 months on a work program consisting of seismic and drilling evaluation, and independent third party geological and project feasibility studies. Cougar will also become the operator of the project area once the first phase is completed.

The second phase of the farm-in will allow Cougar to earn an additional 20% working interest of the TAMM prospect and includes a work commitment to spend an additional $6.5 million over a 24 month period following the first phase. The work program will consist of drilling, coring, feasibility studies and updates to reserve/resource estimates.

Cougar has also continued the preparation for the Manning area heavy oil farm-ins. The geological review has included core and log analysis and detailed geological mapping. Several drilling locations have been identified and the Corporation expects to begin the permitting process for these heavy oil prospects by the end of April.

Summary

The Company plans to develop and optimize its assets in Alberta and British Columbia. Due to the strength of the crude oil commodity prices Cougar will focus on the development of the crude oil properties over natural gas. A maintenance and development program has been prepared and will be implemented, as capital is available focusing on low risk work. The Company will also continue preparing for a planned two well drilling program and nine square mile seismic program in parallel to the maintenance programs.

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.

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. Recently the Government of Canada has approved the pipeline proposal – however the majority stakeholders in the pipeline have not committed to construction and have advised that they will not make that commitment either way until 2014.

UNITED STATES

New Mexico

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. A budget of $500,000 CAD would be required to move this project to the next stage in order to further define the reserves and the potential deliverability of those reserves in order to add definition to the engineering and economical prospect.

FINANCIAL INFORMATION

Financial Condition and Changes in Financial Condition:

The Company’s total assets have decreased to $29,515,286 as at December 31, 2010 from $31,657,559 as at December 31, 2009. This 2010 decrease is the result of write-downs of its unproved properties of approximately $4,365,315, net with additional acquisitions of oil and gas properties. Total assets consist of cash and other current assets of $750,245 (December 31, 2009 - $557,355) and other assets of $313,247 (December 31, 2009 - $296,153).

The Company has included in oil and gas properties evaluated and unevaluated properties. Evaluated properties net of accumulated depreciation, depletion and amortization was $5,772,328 (December 31, 2009 - $4,657,403). Unevaluated properties decreased to $22,622,246 from $26,081,786 on December 31, 2009. The major difference is the write-off of assets of $4,144,000 relating to expired leases.

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.

Other assets of $313,247 remained as of December 31, 2010 (December 31, 2009 - $296,153).

Our total current liabilities were $5,607,308 (December 31, 2009 - $4,451,528) 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 $Nil (December 31, 2009 – $1,364,036), Operating line of credit of $2,035,994 (December 31, 2009 - $Nil) and Current portion of long term debt of $839,060 (December 31, 2009 – $538,831).

We had long term liabilities of $2,769,965 (December 31, 2009 - $3,400,489). This decrease was primarily due payments against our long term debt. Asset retirement obligations of $1,471,808 (December 31, 2009 - $1,285,614) were recorded at year end. The increase is a result of the acquisitions and the company’s transfer of assets from unevaluated to evaluated.

Shareholders’ equity amounted to $19,666,205 (December 31, 2009 - $22,519,928), net of an accumulated deficit of $35,237,407 (2009 - $28,283,170) and comprehensive loss of $256,401 (December 31, 2009 - $416,905). Non controlling interest was $411,430 (December 31, 2009 – $258,127).

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

In 2010, the Company had revenue during the year of $3,112,225 (2009 - $607,469) and operating costs of $1,556,974 (2009 - $418,218) 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, 2010 totaled $6,954,237 (2009 - $19,573,082). These losses include general and administrative expenses of $2,856,086 (2009 - $2,219,441) which includes stock-based compensation expense amounting to $856,121 (2009 - $774,199); net loss (non cash) on settlement of debt of $522,171 (2009 - $Nil); interest expense of $346,548 (2009 - $106,612); depletion depreciation and accretion including ceiling test impairment write-downs of $ 5,536,041 (2009 - $18,317,295) and deferred income tax recoveries of $NIL - (2009 – $Nil).

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 $856,121 in 2010 (2009 - $774,199). 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, 2010 was $346,548 (2009 - $106,612).

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 $221,315 for December 31, 2010 (2009 - $18,168,878) 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 $4,144,000 for 2010 (2009 - $498,867) 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 2010, 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.

2010:

Kodiak Energy Inc.
Consolidated Production Volume Schedule
Total Production (boe)
Production By Product	Q4 2010	Q3 2010	Q2 2010	Q1 2010	YTD 2010
Light Oil (bbls)	10,840.6	13,395.8	16,820.2	11,759.1		52,815.7
Natural Gas (mcf)	-	-	-	-		-
Total (boe/d) (6:1)	10,840.6	13,395.8	16,820.2	11,759.1		52,815.7

Production By Area (boe)	Q4 2010	Q3 2010	Q2 2010	Q1 2010	YTD 2010
Trout	10,243.3	12,424.0	16,574.7	11,475.8		50,717.8
Crossfield	-	119.0	201.4	283.3		603.7
Alexander	597.3	852.8	44.1	-		1,494.2
Total (boe/d) (6:1)	10,840.6	13,395.8	16,820.2	11,759.1		52,815.7

Production per day (boe/d)
Production By Product	Q4 2010	Q3 2010	Q2 2010	Q1 2010	YTD 2010
Light Oil (bbls/d)	117.8	145.6	184.8	130.7		144.7
Natural Gas (mcf/d)	-	-	-	-		-
Total (boe/d) (6:1)	117.8	145.6	184.8	130.7		144.7

Production By Area (boe/d)	Q4 2010	Q3 2010	Q2 2010	Q1 2010	YTD 2010
Trout	111.3	135.0	182.1	127.5		139.0
Crossfield	-	1.3	2.2	3.1		1.7
Alexander	6.5	9.3	0.5	-		4.1
Total (boe/d) (6:1)	117.8	145.6	184.8	130.7		144.7

Kodiak Energy Inc.
Consolidated Price Realized Schedule

Kodiak Realized Prices	Q4 2010	Q3 2010	Q2 2010	Q1 2010	YTD 2010
Light Oil ($/bbl)	72.65	68.44	69.33	73.50		70.68
Natural Gas ($/mcf)	-	-	-	-		-
$/boe (6:1)	72.65	68.44	69.33	73.50		70.68

2009:

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	-	-	-		112.2
Natural Gas (mcf/d)	-	-	-	-		-
Total (boe/d) (6:1)	112.2	-	-	-		112.2

Production By Area (boe/d)	Q4 2009	Q3 2009	Q2 2009	Q1 2009	YTD 2009
Trout	112.2	-	-	-		112.2
Total (boe/d) (6:1)	112.2	-	-	-		112.2

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, 2010 and 2009 are set out below.

	2010		2009
Land acquisition and carrying costs	$	1,549,737	$	8,044,239
Geological and geophysical		823,314		1,523,613
Intangible drilling and completion		1,401,114		545,475
Tangible completion and facilities		390,333		882,267
Long Lived Assets		86,696		1,049,321
Other fixed assets		16,972		9,851
Total Capital Costs Incurred	$	4,268,166	$	12,054,766

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, 2010, the Company’s operations have been financed from the sale of securities and loans from shareholders. Working capital deficiency increased from $3,894,173 as at December 31, 2009 to a working capital deficiency of $4,857,063 at December 31, 2010. Of the total deficiency, $2,035,994 (December 31, 2009 – $Nil) is an operating line of credit and $839,060 (December 31, 2009 – $538,831) is the current portion of long term debt. As at December 31, 2010, 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 subsequently in 2010 converted to equity.

During the year ended December 31, 2010, the Company reached formal agreement with a Canadian bank for credit facilities. The credit facility is a revolving demand loan facility in the amount of Cdn$2,500,000 bearing an interest at prime plus 3.5% per annum. Under the terms of the Agreement, the credit facility is committed for the development of existing proved non-producing/undeveloped petroleum and natural gas reserves. As at December 31, 2010, U.S$2,035,994 of the revolving line was drawn.

The Company advanced $900,000 to Cougar Oil and Gas Canada, Inc. and received an 18 months unsecured convertible note from Cougar on January 31, 2011 in the same amount with an interest rate of prime plus 3% per annum. Kodiak will also receive a 1% gross over-riding royalty on two wells that the funds are intended to finance. The note is convertible into common shares of the Company at a price of $3.52 per share.

During February 2011, the Cougar Oil and Gas Canada, Inc received the initial draw down of 950,000 Swiss Francs ($985,388 CDN) on an unsecured note agreement with a maximum issuance of 4,700,000 Swiss Francs (approximately $5,000,000 CDN), subject to certain conditions. The note has a term of 18 months and accrues interest at the rate of Bank of Canada prime plus 3% per annum. The holder of the note, Zentrum Energie Trust SA, has the option to convert the balance of the note plus accrued interest into common shares of Cougar at the rate of $3.00 per common share along with a warrant to purchase additional common shares on a 1:1 basis for a period of 4 years at a price of $3.90 per common share.

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 2011. See Subsequent Event Note 19 to the consolidated financial statements. Such additional financing will be required for the company’s 2011 planned activities. No assurances can be given that the Company will be able to raise additional financing or, if offered terms for financing, they will be on accepted terms. 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.

Our independent registered public accountants have stated in their report dated April 13, 2011 that we have incurred operating losses since inception, and that we are dependent upon management's ability to develop profitable operations and/or obtain necessary funding from outside sources, including by the sale of our securities, or obtaining loans from financial institutions, where possible. These factors, among others, may raise substantial doubt about our ability to continue as a going concern. The report may cause difficulty in raising future financings.

2010:

Kodiak Energy Inc.
Consolidated Revenue Schedule

Revenues ($)		Q4 2010		Q3 2010		Q2 2010		Q1 2010	YTD 2010
Light Oil		787,526		916,773		1,164,160		864,339		3,732,798
Natural Gas		-		-		-		-		-
Subtotal		787,526		916,773		1,164,160		864,339		3,732,798
Royalty Revenue		2,616		407		2,065		-		5,088
Petroleum and Natural Gas Revenue		790,142		917,180		1,166,225		864,339		3,737,886
$/boe (6:1)	$	72.89	$	68.47	$	69.33	$	73.50	$	70.77

2009:

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

2010:

Kodiak Energy Inc.
Consolidated Royalties Schedule

Royalties ($)		Q4 2010			Q3 2010			Q2 2010			Q1 2010		YTD 2010
Light Oil		117,935			146,004			222,776			138,946			625,661
Natural Gas		-			-			-			-			-
Total Royalties		117,935			146,004			222,776			138,946			625,661
As a % of Oil and Gas Revenue		14.93	%		15.92	%		19.10	%		16.08	%		16.74	%
Petroleum and Natural Gas Royalties		117,935			146,004			222,776			138,946			625,661
$/boe (6:1)	$	10.88		$	10.90		$	13.24		$	11.82		$	11.85

2009:

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 Royalties	109,814		-	-	-		109,814
$/boe (6:1)	10.64		-	-	-		10.64

2010:

Kodiak Energy Inc.
Consolidated Operating Expenses Schedule

Operating Expenses ($)		Q4 2010		Q3 2010		Q2 2010		Q1 2010	YTD 2010

Operating Expenses		428,423		353,785		471,531		303,235		1,556,974
$/boe (6:1)	$	39.52	$	26.41	$	28.03	$	25.79	$	29.48

2009:

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

2010:

Kodiak Energy Inc.
Consolidated Netback Calculation Schedule

Operating Netback ($/boe)	Q4 2010	Q3 2010	Q2 2010	Q1 2010	YTD 2010
Petroleum & Natural gas Revenue	72.89	68.47	69.33	73.50		70.77
Royalties	(10.88)	(10.90)	(13.24)	(11.82)		(11.85)
Operating Costs	(39.52)	(26.41)	(28.03)	(25.79)		(29.48)
Operating Netback	22.49	31.16	28.06	35.89		29.44

2009:

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

2010:

Kodiak Energy Inc.
Consolidated G&A Schedule

G&A Expenses ($)		Q4 2010		Q3 2010		Q2 2010		Q1 2010	YTD 2010

G&A Expenses		927,353		648,013		628,201		652,520		2,856,087
$/boe(6:1)	$	85.54	$	48.37	$	37.35	$	55.49	$	54.08

2009:

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

2010:

Kodiak Energy Inc.
Consolidated Interest Income Schedule

Interest & Other Income ($)		Q4 2010			Q3 2010		Q2 2010		Q1 2010	YTD 2010

Interest and Other Income		151			311		751		41		1,254
Gain/(Loss) on settlement of debt		(595,725	)		897		72,657		-		(522,171	)
Total Other Income		(595,574	)		1,208		73,408		41		(520,917	)
$/boe (6:1)	$	(54.94	)	$	0.09	$	4.36	$	0.00	$	(9.86	)

2009:

Kodiak Energy Inc.
Consolidated Interest Income Schedule

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

Gain/Loss on Disposal of Assets	479,433	-	-	(2,164	)		477,269
Total Other Income	479,433	-	-	(2,164	)		477,269
$/boe (6:1)	46.44	-	-	-			46.23

2010:

Kodiak Energy Inc.

Consolidated Interest Expense Schedule

Interest Expense ($)		Q4 2010		Q3 2010		Q2 2010		Q1 2010		YTD 2010

Interest Expense		99,282		84,914		86,092		76,260		346,548
$/boe(6:1)	$	9.16	$	6.34	$	5.12	$	6.49	$	6.56

2009:

Kodiak Energy Inc.
Consolidated Interest Expense Schedule


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

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

Consolidated DD&A Schedule

DD&A Expense ($)	Q4 2010	Q3 2010	Q2 2010	Q1 2010	YTD 2010		Q4 2009	Q3 2009	Q2 2009	Q1 2009	YTD 2009
Depletion & Depreciation	222,429	263,240	347,942	242,276		1,075,887	243,404	5,409	5,173	4,600		258,586
Accretion	24,224	23,570	23,012	24,033		94,839	22,949	3,461	3,362	3,188		32,960
Asset Write downs	18,411	202,903	-	4,144,000		4,365,314	1,645,462	211,156	16,169,130	-		18,025,748
Total DD&A	265,064	489,713	370,954	4,410,309		5,536,040	1,911,815	220,026	16,177,665	7,788		18,317,294


DD&A Expense $/boe (6:1)	Q4 2010	Q3 2010	Q2 2010	Q1 2010		YTD 2010	Q4 2009	Q3 2009	Q2 2009	Q1 2009		YTD 2009
Depletion & Depreciation	20.52	19.65	20.69	20.60		20.37	23.58	-	-	-		25.05
Accretion	2.23	1.76	1.37	2.04		1.80	2.22	-	-	-		3.19
Asset Write downs	1.70	15.15	-	352.41		82.65	159.39	-	-	-		1,746.04
Total DD&A $/boe (6:1)	24.45	36.56	22.06	375.05		104.82	185.19	-	-	-		1,774.28

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risk from changes in 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 2009 and 2010, 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 2011 to be focused on drilling oil wells. Several other companies seek to drill similar wells in the general area in 2011 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

KODIAK ENERGY, INC

INDEX TO FINANCIAL STATEMENTS

		Page

Report of Independent Registered Public Accounting Firm		F-1

Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets as of December 31, 2010 and 2009		F-3

Consolidated Statements of Operations for the years ended December 31, 2010 and 2009		F-4

Consolidated Statement of Stockholders’ Equity for the two years ended December 31, 2010		F-5

Consolidated Statements of Cash Flows for the years ended December 31, 2010 and 2009		F-6

Notes to Consolidated Financial Statements		F-7 – F-30

RBSM LLP

CERTIFIED PUBLIC ACCOUNTANTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Kodiak Energy, Inc.

Alberta, Canada

We have audited the accompanying consolidated balance sheet of Kodiak Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2010 and the related consolidated statements of operations and comprehensive loss, stockholders’ equity, and cash flows for the year ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based upon our audit.

We have conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. 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 evaluating the overall financial statement presentation. We believe our audit provide 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 Kodiak Energy, Inc. at December 31, 2010 and the results of its operations and its cash flows for the year ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2, the Company has incurred operating losses and has a working capital deficiency. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/S/ RBSM LLP

New York, New York

April 13, 2011

F-1

MEYERS NORRIS PENNY LLP

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 the consolidated statements of operations, stockholder’s equity and cash flows for the year 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 provide 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 the results of its operations and its cash flows for the year ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 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 2. These financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 1 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 of December 31, 2009.

/s/ MEYERS NORRIS PENNY LLP

Chartered Accountants

Calgary, Canada

March 19, 2010

F-2

KODIAK ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2010 AND 2009

	2010			2009
Assets
Current Assets
Cash and short term deposits	$	18,735		$	2,058
Accounts receivable (Note 4)		585,637			403,907
Prepaid expenses and deposits		145,873			151,390
Total current assets		750,245			557,355

Other assets (Note 5)		313,247			296,153

Oil and natural gas properties, Full cost accounting (Note 3)
Developed properties		9,266,193			6,823,400
Less accumulated depreciation, depletion and amortization		(3,493,865	)		(2,165,997	)
Net		5,772,328			4,657,403
Undeveloped properties excluded from amortization		22,622,246			26,081,786
Furniture and fixtures, net		57,220			64,862
		28,451,794			30,804,051

Total assets	$	29,515,286		$	31,657,559

Liabilities and Stockholders' Equity
Current Liabilities
Accounts payable	$	2,054,919		$	2,267,139
Accrued liabilities		677,335			281,522
Operating line of credit (Note 6)		2,035,994			-
Note payable (Note 7)		-			1,364,036
Current debt		839,060			538,831
Total current liabilities		5,607,308			4,451,528

Long-term liabilities (Note 7)		2,769,965			3,400,489

Asset retirement obligations (Note 8)		1,471,808			1,285,614

Total liabilities		9,849,081			9,137,631

Commitments and contingencies (Note 13)

Stockholders' equity (Note 10)
Preferred stock, par value $0.001 per share; 10,000,000 shares authorized, -0- issued and outstanding		-			-
Common stock, par value $0.001 per share; 300,000,000 shares authorized; 119,683,294 and 110,407,186 shares issued and outstanding as of December 31, 2010 and December 31, 2009, respectively		119,683			110,407
Additional paid in capital		54,628,900			50,851,469
Accumulated comprehensive loss		(256,401	)		(416,905	)
Deficit		(35,237,407	)		(28,283,170	)
Stockholders' equity attributable to Kodiak Energy, Inc.		19,254,775			22,261,801
Non controlling interest		411,430			258,127
Total stockholders' equity		19,666,205			22,519,928

Total liabilities and stockholders' equity	$	29,515,286		$	31,657,559

The accompanying notes are an integral part of these consolidated financial statements

F-3

KODIAK ENERGY, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS

	Year ended December 31,
	2010			2009
REVENUE
Oil sales	$	3,108,147		$	594,701
Other		4,078			12,768
Total revenue		3,112,225			607,469

EXPENSES:
Operating		1,556,974			418,218
General and administrative		2,856,086			2,219,441
Depletion, depreciation and amortization		5,536,041			18,317,295
Total expenses		9,949,101			20,954,954

Net loss from operations		(6,836,876	)		(20,347,485	)

OTHER INCOME (EXPENSE)
Gain on non-monetary transfer of properties					477,269
Net loss on settlement of debt		(522,171	)		-
Interest expense		(346,548	)		(106,612	)
Interest income		1,254			-

Net loss before income taxes		(7,704,341	)		(19,976,828	)

Income taxes		-			-

Net loss		(7,704,341	)		(19,976,828	)

Non controlling interest		750,104			403,746

NET LOSS ATTRIBUTABLE TO KODIAK ENERGY, INC.	$	(6,954,237	)	$	(19,573,082	)

Loss per common share (basic and fully diluted)	$	(0.06	)	$	(0.18	)

Weighted average number of shares outstanding (basic and fully diluted)		111,424,277			110,121,632

Comprehensive loss
Net loss	$	(7,704,341	)	$	(19,976,828	)
Foreign currency translation gain (loss)		160,504			4,486,857

Comprehensive loss:		(7,543,837	)		(15,489,971	)
Comprehensive loss attributable to non controlling interest		728,230			403,746

Comprehensive loss attributable to Kodiak Energy, Inc.	$	(6,815,607	)	$	(15,086,225	)


The accompanying notes are an integral part of these consolidated financial statements

F-4

KODIAK ENERGY, INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
FROM JANUARY 1, 2009 THROUGH DECEMBER 31, 2010

									Additional		Other									Total
	Preferred shares				Common shares				Paid in		Comprehensive			Accumulated			Non-Controlling			Stockholders'
	Shares		Amount		Shares		Amount		Capital		Income (loss)			Deficit			Interest			Equity
Balance, January 1, 2009		-	$	-		110,023,998	$	110,024	$	49,296,114	$	(4,903,762	)	$	(8,710,088	)	$	-		$	35,792,288
Stock based compensation		-		-		-		-		774,199		-			-			-			774,199
Issuance of common stock		-		-		383,188		383		154,207		-			-			-			154,590
Effect of change in ownership interest in majority owned subsidiary		-		-		-		-		626,949		-			-			661,873			1,288,822
Foreign currency translation		-		-		-		-		-		4,486,857			-			-			4,486,857
Net loss		-		-		-		-		-		-			(19,573,082	)		(403,746	)		(19,976,828	)
Balance, December 31, 2009		-		-		110,407,186		110,407		50,851,469		(416,905	)		(28,283,170	)		258,127			22,519,928
Stock based compensation		-		-		-		-		856,121		-			-			-			856,121
Common stock issued of Cougar Oil and Gas of Canada to acquire outstanding debt obligation of the Company, subsequently cancelled (Note 1)		-		-		-		-		1,296,888		-			-			-			1,296,888
Effect of change in ownership interest in majority owned subsidiary		-		-		-		-		116,618		21,874			-			881,533			1,020,025
Common stock issued in exchange for debt		-		-		9,276,108		9,276		1,199,379		-			-			-			1,208,655
Fair value of warrants issued in connection with settlement of debt		-		-		-		-		308,425		-			-			-			308,425
Foreign currency translation		-		-		-		-		-		138,630			-			21,874			160,504
Net loss		-		-		-		-		-		-			(6,954,237	)		(750,104	)		(7,704,341	)
Balance, December 31, 2010		-	$	-		119,683,294	$	119,683	$	54,628,900	$	(256,401	)	$	(35,237,407	)	$	411,430		$	19,666,205

The accompanying notes are an integral part of these consolidated financial statements

F-5

KODIAK ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year ended December 31,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(6,954,237	)	$	(19,573,082	)
Adjustments to reconcile net loss to net cash used in operating activities:
Loss from non controlling interest, net of tax		(750,104	)		(403,746	)
Depreciation and depletion		5,441,201			18,317,295
Amortization and accretion		94,839			-
Stock based compensation		856,121			774,199
Gain on non-monetary transfer of assets		-			(477,269	)
Interest expense charged to notes payable		234,270			-
Net loss on settlement of debt		522,171			-
Working capital changes (Note 17)		457,380			397,569
Net cash used in operating activities		(98,359	)		(965,034	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchases of fixed assets		(2,205,697	)		(5,563,737	)
Proceeds from sale of assets		210,000			-
Net cash used in investing activities		(1,995,697	)		(5,563,737	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Shares issued or issuable		-			552,692
Shares issued by subsidiary for cash		-			1,046,925
Advances on the revolving line of credit		2,035,994			-
Proceeds from majority owned warrants exercised		587,247			-
Net (repayments of) proceeds from long term debt		(829,145	)		369,179
Net cash provided by financing activities		1,794,096			1,968,796

Effect of foreign currency rate change on cash		316,637			4,486,857

Net increase (decrease) in cash and cash equivalents		16,677			(73,118	)

Cash and cash equivalents, beginning of period		2,058			75,175
Cash and cash equivalents, end of period	$	18,735		$	2,057

Supplemental disclosures of cash flow information:
Cash paid during the period for:
Interest	$	336,368		$	-
Taxes	$	-		$	-

Supplemental disclosures of non-cash investing and financing activities:

Common stock issued in exchange for debt	$	921,356		$	-
Common stock of Cougar Oil and Gas Canada Inc. issued for properties	$	-		$	188,195
Fair value of warrants issued in settlement of debt	$	595,724		$	-
Gain on settlement of debt in Cougar Oil and Gas Canada Inc.	$	72,657		$	-
Common stock of Cougar Oil and Gas Canada Inc. issued to acquire Kodiak debt from third party	$	1,296,888		$	-
Common stock issued of Cougar Oil and Gas of Canada in settlement of debt	$	477,610		$	481,928
The accompanying notes are an integral part of these consolidated financial statements

F-6

KODIAK ENERGY, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

NOTE 1 – SIGNIFICANT ACCOUNTING POLICIES

A summary of the significant accounting policies applied in the presentation of the accompanying financial statements follows:

Basis and Presentation

The accompanying consolidated financial statements include the accounts of Kodiak Energy Inc. and subsidiaries (collectively “Kodiak”, the “Company”, “we”, “us” or “our”). The Company was incorporated under the laws of the state of Delaware on December 15, 1999 under the name “Island Critical Care, Corp.” On December 30, 2004 the name was changed to “Kodiak Energy, Inc”. During the year ended December 31, 2009, the Company transitioned from a development stage enterprise to an operating company. The Company’s principal activity is in the exploration, development, production and sale of oil and natural gas.

The consolidated financial statements include the accounts of the Company, 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”), an inactive Delaware company; and one majority- owned subsidiary, Cougar Oil and Gas Canada Inc. In British Columbia, Canada, the Company operates under the assumed name of Kodiak Bear Energy, Inc. All significant inter-company transactions have been eliminated in consolidation.

Reverse Acquisition

In January 2010, Cougar Oil and Gas Canada ("COG"), formerly Ore-More Resources, Inc. entered into a stock purchase Agreement (the “Agreement”) with Cougar Energy, Inc, a majority-owned subsidiary of the Company (which we refer to as CEI) and CEI’s then shareholders whereby COG agreed to acquire the entire issued and outstanding shares of the common stock of CEI in two stages:

a) On January 20, 2010, COG finalized stock purchase agreements effective January 18, 2010 by and between COG and Zentrum Energie Trust AG, CAT Brokerage AG, LB (Swiss) Private Bank for its client, Mauschen Finanz Inc. and Rahn and Bodmer (collectively the “Vendors”), whereby COG purchased from the Vendors shares and warrants of the common stock of CEI held by the Vendors. The Vendors tendered a total of 884,616 common shares of CEI and 884,616 warrants granting the right to the holder, which would be COG pursuant to the transfer, to purchase an additional 884,616 common shares of CEI on or before December 4, 2011. As consideration for the common shares and warrants of CEI tendered by the Vendors, COG issued a total of 3,980,775 shares of its common stock to the Vendors and an equal number of warrants, entitling the holders to exercise a total of 5,348,085 warrants. The warrants have the following exercise prices and expiry dates:

1,246,155 warrants to purchase common shares exercisable at $0.288 per common share and expiring on March 4, 2011.

2,025,000 warrants to purchase common shares exercisable at $0.288 per common share and expiring on October 31, 2011.

2,076,930 warrants to purchase common shares exercisable at $0.577 per common share and expiring on December 4, 2011.

The shares and warrants were exchanged during the week ended January 30, 2010.

F-7

KODIAK ENERGY, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

NOTE 1 – SIGNIFICANT ACCOUNTING POLICIES (continued)

b) On January 25, 2010, COG finalized a share purchase agreement between COG and the Company whereby COG purchased from the Company a total of 8,461,549 shares of the common shares of CEI held by the Company. The share purchase agreement called for COG to issue a total of 1.5 shares of its common stock for each share of CEI tendered by the Company, resulting in COG issuing a total of 12,692,324 shares of common stock. As further consideration for the acquisition of the CEI common shares, COG forgave all current indebtedness owed to COG by the Company and guaranteed by CEI, which was in the amount of $1,296,888. An additional condition to the agreement was that a total of 12,000,000 restricted common shares of Ore-More Resources, Inc were cancelled.

Upon consummation of the acquisition, CEI became the only wholly-owned subsidiary of COG. Subsequently, on February 4, 2010, Ore-More Resources, Inc filed a Certificate of Amendment to its Certificate of Incorporation with the Registrar of Corporations in Alberta, Canada, changing the Company’s name to “Cougar Oil and Gas Canada, Inc.”.

The acquisition is accounted for as a “reverse acquisition”, since the stockholders of CEI owned a majority of COG’s common stock immediately following the transaction and their management has assumed operational, management and governance control. The reverse acquisition transaction is recorded as a recapitalization of CEI, pursuant to which CEI is treated as the surviving and continuing entity although Ore-More Resources, Inc is the legal acquirer, rather than a business combination. Cougar Oil and Gas Canada did not recognize goodwill or any intangible assets in connection with this transaction. Accordingly, the Company’s historical consolidated financial statements include those of CEI from its date of inception on November 21, 2008.

Functional currency

The reporting currency of the Company is the United States dollar, while the functional currency is the Canadian dollar. When a transaction is executed in a foreign currency, it is re-measured into Canadian dollars based on appropriate rates of exchange in effect at the time of the transaction. At each balance sheet date, all recorded balances are adjusted to the reporting currency of the Company to reflect the current exchange rate. The resulting foreign currency transactions gains (losses) are included in general and administrative expenses in the accompanying consolidated statements of operations.

The cumulative translation adjustments are included in accumulated other comprehensive loss in the equity section of the consolidated balance sheet.

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, stock-based compensation expense, contingencies and the results of current and future litigation.

F-8

KODIAK ENERGY, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

NOTE 1 – SIGNIFICANT ACCOUNTING POLICIES (continued)

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.

Reclassification

Certain reclassifications have been made to prior periods’ data to conform to the current year’s presentation. These reclassifications had no effect on reported income or losses.

Revenue Recognition

The Company uses the sales method of accounting for the recognition of natural gas and oil revenues. The Company is the operator on all of its properties. The Company has an agreement with the marketers of our product to sell, on its behalf, production from the properties for which it has working interest ownership. Since there is a ready market for natural gas, crude oil and natural gas liquids (“NGLs”), production is sold at various locations at which time title and risk of loss pass to the marketer.

The Company records its share of revenues based on sales volumes and contracted sales prices. The sales price for natural gas, natural gas liquids and crude oil are adjusted for transportation cost and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents once received by the Company. Historically, these adjustments have been insignificant. In addition, natural gas and crude oil volumes sold are not significantly different from the Company’s share of production.

The Company receives its share of revenue after all calculated crown royalties are paid on natural gas, crude oil and NGLs in accordance with the particular contractual provisions of the lease, license or concession agreements and the laws and regulations applicable to those agreements. Private royalties are accrued and paid upon receipt of payment.

F-9

KODIAK ENERGY, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

NOTE 1 – SIGNIFICANT ACCOUNTING POLICIES (continued)

Cash and Cash Equivalents, and Concentrations of Credit Risk

Cash and cash equivalents represent cash in banks. The Company considers any highly liquid debt instruments purchased with a maturity date of three months or less to be cash equivalents. The Company’s accounts receivable are concentrated among entities engaged in the energy industry, within Canada and the United States. Financial instruments and related items, which potentially subject the Company to concentrations of credit risk, consist primarily of cash, cash equivalents and receivables. The Company places its cash and temporary cash investments with credit quality institutions. At times, such investments may be in excess of the Canada Deposit Insurance Corporation or Federal Deposit Insurance Corporation's insurance limit.

Furniture and Fixtures

Furniture and fixtures are recorded at cost and depreciated on both straight-line and declining balance basis over estimated useful lives of five years. Repair and maintenance costs are charged to expense as incurred while acquisitions are capitalized as additions to the related assets in the period incurred. Gains or losses from the disposal of property, plant and equipment are recorded in the period incurred. The net book value of the property, plant and equipment that is retired or sold is charged to accumulated depreciation and amortization, and the difference is recognized as a gain or loss in the results of operations in the period the retirement or sale transpires.

Segment Information

The Company applies Accounting Standards Codification subtopic Segment Reporting 280-10 (“ASC 280-10”). ASC 280-10 establishes standards for reporting information regarding operating segments in annual consolidated financial statements and requires selected information for those segments to be presented in interim financial reports issued to stockholders. ASC 280-10 also establishes standards for related disclosures about products and services and geographic areas. Operating segments are identified as components of an enterprise about which separate discrete financial information is available for evaluation by the chief operating decision maker, or decision making group, in making decisions how to allocate resources and assess performance. The information disclosed herein, materially represents all of the financial information related to the Company's principal operating segments.

Impairment of long lived assets

The Company applies Accounting Standards Codification subtopic 360-10, Property, Plant and Equipment (“ASC 360-10”). The Statement requires that long-lived assets and certain identifiable intangibles held and used by the Company be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Events relating to recoverability may include significant unfavorable changes in business conditions, recurring losses, or a forecasted inability to achieve break-even operating results over an extended period. The Company evaluates the recoverability of long-lived assets based upon forecasted undiscounted cash flows. Should impairment in value be indicated, the carrying value of intangible assets will be adjusted, based on estimates of future discounted cash flows resulting from the use and ultimate disposition of the asset. ASC 360-10 also requires assets to be disposed of is reported at the lower of the carrying amount or the fair value less costs to sell.

F-10

KODIAK ENERGY, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

NOTE 1 – SIGNIFICANT ACCOUNTING POLICIES (continued)

Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas properties. Accordingly, all costs associated with the acquisition, exploration, and development of properties within a relatively large geopolitical cost center in our case, by country, and are capitalized when incurred and are amortized as mineral reserves in the cost center are produced, subject to a limitation that the capitalized costs not exceed the value of those reserves. In some cases, however, certain significant costs designated as unproven properties are deferred separately without amortization until the specific property to which they relate is found to be either productive or nonproductive, at which time those deferred costs and any reserves attributable to the property are included in the computation of amortization in the cost center. All costs incurred in oil and gas producing activities are regarded as integral to the acquisition, discovery, and development of whatever reserves ultimately result from the efforts as a whole, and are thus associated with the Company’s reserves. The Company capitalizes internal costs directly identified with performing or managing acquisition, exploration and development activities. The Company has not capitalized any internal costs or interest at December 31, 2010 and 2009. Unevaluated and undeveloped costs are excluded from the full cost pool and are periodically evaluated for impairment rather than amortized. Upon evaluation, costs associated with productive properties are transferred to the full cost pool and amortized. Gains or losses on the sale of oil and natural gas properties are generally included in the full cost pool unless the entire pool is sold.

Capitalized costs and estimated future development costs are amortized on a unit-of-production method based on proved reserves associated with the applicable country cost center. The Company has assessed the impairment for oil and natural gas properties for the full cost pool at December 31, 2010 and 2009 and will assess quarterly thereafter using a ceiling test to determine if impairment is necessary. Specifically, the net unamortized costs for each full cost pool less related deferred income taxes is compared to (a) the present value, discounted at 10%, of future net cash flows from estimated production of proved oil and gas reserves plus (b) all costs being excluded from the amortization base plus (c) the lower of cost or estimated fair value of unproved properties included in the amortization base less (d) the income tax effects related to differences between the book and tax basis of the properties involved. The present value of future net revenues is based on current prices, with consideration of price changes only to the extent provided by contractual arrangements, as of the latest balance sheet presented. The full cost ceiling test takes into account the prices of qualifying cash flow hedges in calculating the current price of the quantities of the future production of oil and gas reserves covered by the hedges as of the balance sheet date. In addition, the use of the hedge-adjusted price is consistently applied in all reporting periods and the effects of using cash flow hedges in calculating the ceiling test, the portion of future oil and gas production being hedged, and the dollar amount that would have been charged to income had the effects of the cash flow hedges not been considered in calculating the ceiling limitation should be disclosed. Any excess is charged to expense during the period that the excess occurs. The Company did not have any hedging activities since inception through December 31, 2010. Application of the ceiling test is required for reporting purposes, and any write-downs are not reinstated even if the cost ceiling subsequently increases by year-end. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income. Abandonment of properties is accounted for as adjustments of capitalized costs with no loss recognized.

F-11

KODIAK ENERGY, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

NOTE 1 – SIGNIFICANT ACCOUNTING POLICIES (continued)

Reserves

In December 2008, the SEC issued its final rule, Modernization of Oil and Gas Reporting, which is effective for reporting 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. Under the SEC’s final rule, prior period reserves were not restated. The Company has used this guidance in reporting reserve information.

Fair Values

The Company applies Accounting Standards Codification subtopic 820-10, Fair Value Measurements and Disclosures (“ASC 820-10”). ASC 820-10 defines fair value, establishes a framework for measuring fair value, and enhances fair value measurement disclosure. ASC 820-10 delayed, until the first quarter of fiscal year 2009, the effective date for ASC 820-10 for all non-financial assets and non-financial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The adoption of ASC 820-10 did not have a material impact on the Company’s financial position or operations. Refer to Note 13 for further discussion regarding fair valuation.

Comprehensive Income (Loss)

The Company applies Statement of Accounting Standards Codification subtopic 220-10, Comprehensive Income (“ASC 220-10”). ASC 220-10 establishes standards for the reporting and displaying of comprehensive income and its components. Comprehensive income is defined as the change in equity of a business during a period from transactions and other events and circumstances from non-owners sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. ASC 220-10 requires other comprehensive income (loss) to include foreign currency translation adjustments and unrealized gains and losses on available for sale securities.

Net Loss per Share

The Company applies Accounting Standards Codification subtopic 260-10, Earnings Per Share (“ASC 260-10”) specifying the computation, presentation and disclosure requirements of earnings per share information. Basic loss per share has been calculated based upon the weighted average number of common shares outstanding. Stock options and warrants have been excluded as common stock equivalents in the diluted loss per share because their effect is anti-dilutive on the computation.

Stock based compensation

The Company follows Accounting Standards Codification subtopic 718-10, Compensation (“ASC 718-10”) which requires that all share-based payments to both employees and non-employees be recognized in the income statement based on their fair values. 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.

F-12

KODIAK ENERGY, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

NOTE 1 – SIGNIFICANT ACCOUNTING POLICIES (continued)

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

The Company applies Accounting Standards Codification subtopic 740-10, Income Taxes (“ASC 740-10”) which requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statement or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The adoption of ASC 740-10 did not have a material impact on the Company’s consolidated results of operations or financial condition. Please refer to Note 18.

F-13

KODIAK ENERGY, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

NOTE 1 – SIGNIFICANT ACCOUNTING POLICIES (continued)

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.

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 2010 the Company’s ownership interest in Cougar Energy Inc. changed which were accounted for as equity transactions. See Note 11 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 Company's majority owned subsidiary issued common shares in various transactions, which resulted in a dilution of the Corporation's percentage ownership in the Subsidiary. The Company 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.

F-14

KODIAK ENERGY, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

NOTE 1 – SIGNIFICANT ACCOUNTING POLICIES (continued)

Recent Accounting Pronouncements

In December 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-28, When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts. This ASU updates ASC Topic 350, Intangibles—Goodwill and Other, to amend the criteria for performing Step 2 of the goodwill impairment test for reporting units with zero or negative carrying amounts and requires performing Step 2 if qualitative factors indicate that it is more likely than not that a goodwill impairment exists. The ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2010. The Company does not currently have any reporting units with zero or negative carrying values.

In July 2010, the FASB issued Accounting Standards Update 2010-20 which amend “Receivables” (Topic 310). ASU 2010-20 is intended to provide additional information to assist financial statement users in assessing an entity’s risk exposures and evaluating the adequacy of its allowance for credit losses. The disclosures as of the end of a reporting period are effective for interim and annual reporting periods ending on or after December 15, 2010. The disclosures about activity that occurs during a reporting period are effective for interim and annual reporting periods beginning on or after December 15, 2010. The amendments in ASU 2010-20 encourage, but do not require, comparative disclosures for earlier reporting periods that ended before initial adoption. However, an entity should provide comparative disclosures for those reporting periods ending after initial adoption. The Company does not expect to have a significant impact on its financial statements with the adoption of ASU 2010-20.

There were various other updates recently issued, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on the Company's consolidated financial position, results of operations or cash flows.

NOTE 2 - GOING CONCERN MATTERS

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.

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KODIAK ENERGY, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2010 AND 2009

NOTE 3 - OIL AND GAS PROPERTIES

Major classes of oil and gas properties under the full cost method of accounting at December 31, 2010 and 2009 consist of the following:

	2010			2009
Proved properties, net of cumulative impairment charges	$	9,266,193		$	6,823,400
Unevaluated and Unproved properties		22,622,246			26,081,786
Gross oil and gas properties		31,888,439			32,905,186
Less: accumulated depletion, accretion and impairments		(3,493,865	)		(2,165,997	)
Net oil and gas properties	$	28,394,574		$	30,739,189

Unevaluated and Unproved Properties

The Company has certain unevaluated and unproved properties, valued at cost, that have been excluded from costs subject to depletion. These costs amounting to $22,622,246 and $26,081,786 as at December 31, 2010 and 2009, respectively, are subject to a test for impairment which is separate from the test applied to proved properties.

During the year ended December 31, 2010 certain unproved properties in the United States were returned due to other business opportunities. These properties were removed from undeveloped properties at their carrying value of $4,144,000 and have been included in depletion and depreciation the statement of operations.

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

Quarterly, the Company assesses the value of unamortized capitalized costs within its cost center over the discounted present value of cash flows associated with it

KODIAK ENERGY, INC. 10-K