UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


Washington,
D.C. 20549





FORM
10-K





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





For the
fiscal year ended December 31, 2009





OR





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





DOCUMENTS
INCORPORATED BY REFERENCE: None.





KODIAK ENERGY,
INC.





Form
10-K


For the
Fiscal Year Ended December 31, 2009





TABLE OF
CONTENTS





PART
      IITEM
      1.
            BUSINESS
            3ITEM
      1A.
            RISK
      FACTORS
            13ITEM
      1B.
            UNRESOLVED
      STAFF COMMENTS
            20ITEM
      2.
            PROPERTIES
            20ITEM
      3.
            LEGAL
      PROCEEDINGS
            29ITEM
      4.
            [RESERVED]
            29PART
      IIITEM
      5.
            MARKET
      FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
      EQUITY SECURITIES
            30ITEM 6.
            SELECTED
      FINANCIAL DATA
            31ITEM 7.
            MANAGEMENT’S
      DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
      OPERATIONS
            31ITEM 7A.
            QUANTITATIVE
      AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
            41ITEM 8.
            FINANCIAL
      STATEMENTS AND SUPPLEMENTARY DATA
            42ITEM
      9.
            CHANGES
      IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
      DISCLOSURE
            68ITEM
      9A.
            CONTROLS
      AND PROCEDURES
            68ITEM
      9B.
            OTHER
      INFORMATION
            69PART
      IIIITEM
      10.
            DIRECTORS,
      EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
            70ITEM 11.
            EXECUTIVE
      COMPENSATION
            73ITEM
      12.
            SECURITY
      OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
      STOCKHOLDER MATTERS
            75ITEM
      13.
            CERTAIN
      RELATIONSHIPS AND RELATED PARTY TRANSACTIONS, AND DIRECTOR
      INDEPENDENCE
            76ITEM
      14.
            PRINCIPAL
      ACCOUNTING FEES AND SERVICES
            77PART
      IVITEM
      15.
            EXHIBITS,
      FINANCIAL STATEMENT SCHEDULES
            77







2





PART
I





ITEM
1. BUSINESS





HISTORY





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





GENERAL





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





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





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





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





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


3





OIL
AND GAS PRODUCTION





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





COMPETITIVE
STRENGTHS





Dominant
Position in the Trout Area, Alberta


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


Attractive
Underlying Economics


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





Stable
Base Production





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





Commodity
Position





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





Valuable
Acreage Positions





Trout Area,
Alberta
 
 As
described above, the Trout land position.





New Mexico, United
States





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





Development
and Exploration Opportunities





Core
Trout Project, Alberta





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





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




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


4





Lucy,
British Columbia





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





New
Mexico, United States





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





Little
Chicago, Northwest Territories





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





BUSINESS
STRATEGIES





Financial
Flexibility





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





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




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




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




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





DESCRIPTION
OF OUR EXPLORATION AND PRODUCTION PROPERTIES AND PROJECTS





OIL
AND GAS DATA


Reserves
Categories





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


5




Estimated
Reserves





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


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






6




NET
      PRESENT VALUE OF FUTURE NET REVENUE
              Based
      on Constant Prices and Costs
              December
      31, 2009Reserves
              Category
            Before
      Income Taxes
              Discounted
      at (% Per Year)
              $M
      Cdn0%
            5%
            10%
            15%
            20%PROVED
      – Developed producing
            4,367
            3,889
            3,507
            3,197
            2,941PROVED
      – Developed Non-producing
            1,326
            1,191
            1,079
            984
            903PROVED
      – Undeveloped
            0
            0
            0
            0
            0TOTAL
      PROVED
            5,693
            5,079
            4,585
            4,180
            3,844PROBABLE
            4,645
            4,006
            3,520
            3,139
            2,834TOTAL
      PROVED PLUS PROBABLE
            10,377
            9,086
            8,105
            7,320
            6,678Notes:
              1.    
      Numbers have not considered the 84.6% ownership of Cougar Energy, Inc by
      Kodiak, as Kodiak reports financial on a consolidated basis.
              2.    
      Numbers may not add exactly due to rounding.
              3.    
      Numbers are M $ CAD as reserve reports were calculated on that
      basis.


Proved Undeveloped
Reserves





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


Sensitivity of Reserves to Prices and
Costs





Fluctuations in the prices and costs
used in the estimation of reserves can cause significant variations in the
resulting reserve calculation. We believe it would be meaningful to consider
different price and cost sensitivities to the reserve calculation presented
above, particularly with respect to recent pronouncements from the U.S. SEC
regarding constant and variable pricing regarding oil and gas
reserves.  The following table represents reserve amounts as of
December 31, 2009 under the different pricing and cost scenarios explained
below. The reserves presented under the alternative price and cost assumptions
have been prepared by GLJ, independent petroleum engineers.
  7


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





Reserves





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





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





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





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





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





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


8





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





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





Internal
Controls





A
significant component of our internal controls in our reserve estimation effort
is our practice of using an independent third-party reserve engineering firm to
prepare 100% of our year-end proved reserves and, for 2009, our probable and
possible reserves. The qualifications of this firm are discussed below under
“Independence and Qualifications of Reserve Preparer.” The Board of Directors of
the Company has formed a Reserves Committee for the purposes of reviewing the
reserves estimates and procedures prior to acceptance of the
report.  The Committee is composed of two independent board members
and one non independent board member.
  Our
internal geologist is our Vice President, Exploration and reports to our Vice
President, Operations, who maintains oversight and compliance responsibility for
the internal reserve estimate process and provides appropriate data to our
independent third party reserve engineers to estimate our year-end reserves. Our
internal geologist staff consists of one degreed geologist, with over
25 years of diversified geological experience in the Canadian oil and gas
industry, including in the Western Canadian Sedimentary Basin.  He is
a member of the Association of Professional Engineers, Geologists and
Geophysicists of Alberta (APEGGA), Society of Petroleum Engineers (SPE), and
Canadian Society of Petroleum Geologists (CSPG).





Production Volumes, Sales Prices and
Production Costs


The
following table sets forth information regarding our oil and natural gas
properties. The oil and gas production figures reflect the net production
attributable to our revenue interest and are not indicative of the total volumes
produced by the wells.
  9


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





Independence and Qualifications of
Reserve Preparer





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





MAINTENANCE AND
PRODUCTION


General


As the operator of wells in which we
have an interest, we design and manage the development of these wells and
supervise operation and maintenance activities on a day-to-day basis. We employ
production and reservoir engineers, geologists and other
specialists.
 
 Field operations conducted by our
contractors include duties whose primary responsibility is to operate the wells.
Other contracted field personnel are experienced and involved in the activities
of well servicing, the development and completion of new wells and the
construction of supporting infrastructure for new and existing wells (such as
electric service , salt water disposal facilities, and gas feeder lines). We
utilize third-party contractors on an “as needed” basis to supplement our field
personnel and related equipment.


Oil and Gas Leases and Development
Rights





As of
December 31, 2009, we had approximately 130 leases covering approximately
285,949 gross acres. The typical oil and gas lease provides for the payment of
royalties to the mineral owner for all oil or gas produced from any well drilled
on the lease premises. This amount typically ranges from 12% to 30% resulting in
a 70% to 88% net revenue interest to us.
 
 Because
the acquisition of oil and gas leases is a very competitive process, and
involves certain geological and business risks to identify productive areas,
prospective leases are sometimes held by other oil and gas operators. In order
to gain the right to drill these leases, we may purchase leases from other oil
and gas operators. In some cases, the assignor of such leases will reserve an
overriding royalty interest, ranging from 5% to 15%, which further reduces the
net revenue interest available to us to between 55% and
73%.


10


As of
December 31, 2009, approximately 4% of our oil and gas leases were held by
production, which means that for as long as our wells continue to produce oil or
gas, we will continue to own those respective leases.
 
 In the
Trout Area, Alberta as of December 31, 2009, we held oil and gas leases on
approximately 7,680 gross acres, of which approximately 320 gross acres (4%) are
not currently held by production. The approximate 320 acres had an expiry date
in Q4 2009 and an application has been submitted to the regulatory agency to
extend the expiry of these leases.
 
 In the
Alexander Area, Alberta as of December 31, 2009, we held oil and gas leases
on approximately 160 gross acres, of which 0 gross acres (0%) are not currently
held by production. There are no expiry issues for this lease.
 
 In the
Crossfield Area, Alberta as of December 31, 2009, we held oil and gas
leases on approximately 160 gross acres, of which 0 gross acres (0%) are not
currently held by production. There are no expiry issues for this
lease.
 
 In the
Granlea Area, Alberta as of December 31, 2009, we held oil and gas leases
on approximately 1,265 gross acres, of which approximately 1,265 gross acres
(100%) are not currently held by production. The Granlea oil and gas leases will
expire in Q3 2010.
 
 In Lucy,
British Columbia as of December 31, 2009, we held oil and gas leases on
approximately 1,975 gross acres, of which approximately 1,975 gross acres (100%)
are not currently held by production. The Lucy mineral lease was extended as
part of an approved Experimental Scheme application to the regulatory agency.
The Lucy lease is currently extended indefinitely.
 
 In the
Little Chicago Area, N.W.T. as of December 31, 2009, we held oil and gas
leases on approximately 199,000 gross acres, of which approximately 199,000
gross acres (100%) are not currently held by production. The Little Chicago oil
and gas leases will expire in Q3 2010.
 
 In the
Sofia and Speardraw Areas, northeast New Mexico as of December 31, 2009, we
held CO2 and oil and gas leases on approximately 76,805 gross acres, of which
approximately 76,805 gross acres (100%) are not currently held by production.
There are no lease expiries in 2010.
 
 In the
Hill County Area, northwest Montana as of December 31, 2009, we held oil
and gas leases on approximately 879 gross acres, of which approximately 879
gross acres (100%) are not currently held by production. The Montana leases will
expire in Q3 2010.
 
 In the
Bison Lake area, northern Alberta as of December 31, 2009, we hold oil and
gas leases and development rights, by virtue of farm-out agreements or similar
mechanisms, on approximately 17,712 gross acres that are still within their
original lease or agreement term and are not earned or are not held by
production. The farm-in agreement specifies that we are entitled to earn 100% of
whatever leases we can extend as a result of drilling and completion operations.
The farm-in leases expire in Q3 2010.


Oil
Marketing Contracts





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





Exploration
and Production


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


11





·
            the
      location of wells;




·
            the
      method of drilling and casing
wells;




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




·
            the
      plugging and abandoning of
wells; and




·
            notice
      to surface owners and other third
parties.


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




See
additional discussion in Item 1A. Risk Factors.





Employees
and Consultants
 
 As of December 31, 2009, the
Company has a total of 8 executive and administrative personnel located at our
headquarters in Calgary, Alberta, Canada. The Company has a total of 3 field
contractors located in the Trout Area properties, north central Alberta, and 1
field contractor located in the Crossfield property, central Alberta Canada.
Professional consultants are utilized on an as needed basis.  Our
employees and consultants are covered by employment and consulting agreements.
Management considers its relations with our employees to be
satisfactory.
 
 Where to Find Additional
Information
 
 Additional information about us can be
found on our website at www.kodiakpetroleum.com. Information on our website is
not part of this document. The Company also provides free of charge on our
website our filings with the SEC, including our annual reports, quarterly
reports and current reports, along with any amendments thereto, as soon as
reasonably practicable after we have electronically filed such material with, or
furnished it to, the SEC.





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





·
            Code
      of Conduct




·
            Mandate
      of the Board of Directors




·
            Audit
      Committee Charter




·
            Corporate
      Disclosure & Insider Trading
Policy




·
            Whistleblower
      Policy




·
            Health,
      Safety and Environment Policy




·
            Compensation
      Committee Mandate.





GLOSSARY
OF SELECTED TERMS





The following is a description of the
meanings of some of the oil and natural gas industry terms used in this Annual
Report on Form 10-K. Some of the definitions below have been abbreviated
from the applicable definition contained in Rule 4-10(a) of
Regulation S-X.
 
 Equisetum Field. This is a
strike area where a gas or oilfield has been established and a spacing unit or
other approval had been issued by the Energy Resources Conservation Board (ERCB)
of the Province of Alberta.  The Equisetum Field is located in the
general area of West of the 5th
Meridian, Township 88, Ranges 5 to 6.


12





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, Ranges 3 to 7.




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





ITEM
1A. RISK FACTORS





BUSINESS
RISKS





Going
Concern Uncertainty





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





Financial
Markets Instability and Uncertainty





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





The
Oil and Gas Industry Is Highly Competitive





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


13





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:


14


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




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




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





We
Are a Development Stage Company Implementing a New Business Plan





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





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





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





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





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





Operational
Risks





Other
Regulation of the Oil and Gas Industry





The oil and gas industry is extensively
regulated by numerous federal, state, provincial, territorial and local
authorities. Legislation affecting the oil and gas industry is under constant
review for amendment or expansion, frequently increasing the regulatory burden.
Also, numerous departments and agencies – federal, state, provincial, and
territorial – are authorized by statute to issue rules and regulations binding
on the oil and gas industry and its individual members, some of which carry
substantial penalties for failure to comply.
 
 Legislation continues to be introduced
and revised.  Our operations may be subject to such laws and
regulations. Presently, it is not possible to accurately estimate the costs we
could incur to comply with any such facility, security laws or regulations, but
such expenditures could be substantial.
 
 The following is a summary of some of
the existing laws, rules and regulations to which our business operations are
subject.





Operating
Hazards and Insurance


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


15


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





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


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





Oil and Natural
Gas Properties


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


Pipeline
Rights-of-Way





Substantially all of our gathering
systems and pipelines are constructed within rights-of-way granted by property
owners named in the appropriate land records. All of our facilities are located
on property owned in fee or on property obtained via long-term leases or surface
easements.
 
 Our property or rights-of-way are
subject to encumbrances, restrictions and other imperfections. These
imperfections have not interfered, and we do not expect that they will
materially interfere, with the conduct of our business. In many instances, lands
over which rights-of-way have been obtained are subject to prior liens that have
not been subordinated to the right-of-way grants. In some cases, not all of the
owners named in the appropriate land records have joined in the right-of-way
grants, but in substantially all such cases signatures of the owners of majority
interests have been obtained. Substantially all permits have been obtained from
public authorities to cross over or under, or to lay facilities in or along,
water courses, county roads, municipal streets, and provincial or state
highways, where necessary.
 
 Certain of our rights to lay and
maintain pipelines are derived from recorded oil and gas leases for wells that
are currently in production, however, the leases are subject to termination if
the wells cease to produce. In most cases, the right to maintain existing
pipelines continues in perpetuity, even if the well associated with the lease
ceases to be productive. In addition, because some of these leases affect wells
at the end of lines, these rights-of-way will not be used for any other purpose
once the related wells cease to produce.


16


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.


17


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.


18


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.


19





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





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





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





ITEM
1B. UNRESOLVED STAFF COMMENTS





None





ITEM
2. PROPERTIES





CANADA





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





1.
            Cougar
      Trout Properties, Alberta (Core Area) – farm-in and acquired lands in the
      Trout, Kidney and Equisetum fields;




2.
            CREEnergy
      Project, Alberta – exploration and development opportunities within the
      CREEnergy Agreement;




3.
            Lucy,
      British Columbia – Horn River Basin Muskwa shale gas project;
      and




4.
            Other
      Alberta properties.





Cougar
Trout Properties, Alberta (Core Area)





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





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





1.
            100%
      working interest  in 28 sections of land in the area of the
      CREEnergy Project, northwest of Red Earth Creek, Alberta – pay 100% to
      earn 100% with a 3% gross overriding royalty (GOR) upon earning to the
      vendor.




20


2.
            The
      mineral rights within the farm-in agreement are currently held under
      several Alberta Crown 4-year initial term P&NG licenses expiring in
      September 2010.  The rights can be grouped and validated with a
      drilling program and subsequently continued under a 5 year intermediate
      term license.




3.
            Close
      to infrastructure consisting of existing pipelines, with capacity, and all
      weather roads. The target formations should contain sweet natural
      gas.  The existing regional natural gas infrastructure would
      reduce production and processing
charges.





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





1.
            Private Company
      Production and Property Acquisition (completed September 30,
      2009)





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




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




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




d)
            1
      observation wellbore and 21 suspended
wellbores.




e)
            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).




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




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




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




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





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


21





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.





2.
            Private Company
      Production and Property Acquisition (completed October 1,
      2009)





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




b)
            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.




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




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





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





Acquired Production and Properties
Additional Discussion





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





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




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




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




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




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




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




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




22




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


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





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





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





CREEnergy
Project, Alberta





History





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





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





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





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





Joint Venture Information and
Summary





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





Joint Venture
Agreement





Key prioritieswere established from
the discussions between CREEnergy and Kodiak:





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




23


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




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




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





Lucy,
Northern British Columbia





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





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





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





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





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





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





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





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





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


24


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)





1.
            2
      producing oil properties in the Crossfield and Alexander fields in Central
      Alberta.




2.
            100%
      working interest in the Crossfield property – 1 producing well with single
      well battery with approximately 5 barrels per day (bbl/d) net production –
      production continues to be stable with no capital commitment
      required.




3.
            55%
      working interest in the Alexander property – 1 shut in oil well with a
      single well battery, 1 suspended well. Expected production of
      approximately 10 bbl/d net production upon restarting shut in oil well
      after spring break up.





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





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




25


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.


26





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





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





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





Province/Granlea,
Southeast Alberta





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





UNITED
STATES





New
Mexico





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





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




27


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





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





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





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





Montana





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





OIL
AND GAS PROPERTIES





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





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




28




Land
Acreage





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





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








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





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





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





OFFICE
PROPERTY





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





ITEM
3. LEGAL PROCEEDINGS








ITEM 4. [RESERVED]


29




PART
II





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





MARKET
INFORMATION





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





Over
      the Counter
            
            TorontoBulletin
      Board
            
            Venture
      Exchange(U.
      S. Dollars)
            
            (Canadian
      Dollars)High
            
            Low
            
            High
            
            LowYear
      ended December 31, 2009First
      Quarter
            
            $
            0.64
            
            
            
            0.32
            
            
            $
            0.70
            
            
            
            0.37Second
      Quarter
            
            $
            0.41
            
            
            
            0.12
            
            
            $
            0.52
            
            
            
            0.17Third
      Quarter
            
            $
            0.77
            
            
            
            0.25
            
            
            $
            0.88
            
            
            
            0.21Fourth
      Quarter
            
            $
            0.72
            
            
            
            0.23
            
            
            $
            0.75
            
            
            
            0.30Year
      ended December 31, 2008First
      Quarter
            
            $
            2.51
            
            
            $
            1.36
            
            
            $
            2.56
            
            
            $
            1.40Second
      Quarter
            
            $
            3.08
            
            
            $
            1.46
            
            
            $
            3.10
            
            
            $
            1.50Third
      Quarter
            
            $
            2.40
            
            
            $
            0.75
            
            
            $
            2.29
            
            
            $
            0.81Fourth
      Quarter
            
            $
            0.95
            
            
            $
            0.41
            
            
            $
            0.97
            
            
            $
            0.51





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





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


30


EQUITY COMPENSATION PLAN
INFORMATION


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


Plan
      Category
            Number
      of Securities to be Issued Upon Exercise of Outstanding Options Warrants
      and Rights
              (#)
            Weighted-Average
      Exercise Price of Outstanding Options Warrants and Rights
              ($)
            Number
      of Securities Remaining Available for Future Issuance Under Equity
      Compensation Plans
              (#)Equity
      compensation plans
              approved
      by security holders
            8,490,000
            1.41
            1,940,000Equity
      compensation plansnot
              approved
      by security holders
            --
            --
            --Total
            8,490,000
            1.41
            1,940,000




ITEM
6. SELECTED FINANCIAL DATA





None.





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





FORWARD
LOOKING STATEMENTS





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





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





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





PLAN
OF OPERATION





Canada


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


31





1.
            Cougar
      Trout Properties, Alberta (Core Area) – farm-in and acquired lands in the
      Trout, Kidney and Equisetum fields;




2.
            CREEnergy
      Project, Alberta – mineral leases, exploration and development
      opportunities within the CREEnergy Agreement and several current and
      proposed Northern Alberta Treaty Land Entitlement
  Claims;




3.
            Lucy,
      British Columbia – Horn River Basin Muskwa shale gas project;
      and




4.
            Other
      Alberta properties.





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





Cougar Trout Properties, Alberta (Core
Area)





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





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





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





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





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




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




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




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




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




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




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





Subsequent Maintenance and
Development Programs





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


32





·
            Acid
      wash of perforations




·
            Setting
      of bridge plugs to seal off water




·
            Cleanouts




·
            Re
      perforating




·
            Drill
      out plugs and open up previously unproduced
  zones




·
            Repairs
      to wells with separated rods




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




·
            Pump  and
      well site equipment optimization –
ongoing




·
            Waterflood
      programs – future




·
            Horizontal
      drilling – future




·
            Use
      of low damage drilling fluids –
future





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





Consolidate the Trout
Area





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





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





CREEnergy Project





Current
Status





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


33


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


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





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





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





Lucy, Northern British
Columbia





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 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.





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




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





Cougar Central Alberta Producing
Properties





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





1.
            2
      producing oil properties in the Crossfield and Alexander fields in Central
      Alberta.




2.
            100%
      working interest in the Crossfield property – 1 producing well with single
      well battery with approximately 5 barrels per day (bbl/d) net production –
      production continues to be stable with no capital commitment
      required.




3.
            55%
      working interest in the Alexander property – 1 shut in oil well with a
      single well battery, 1 suspended well. Expected production of
      approximately 10 bbl/d net production upon restarting shut in oil well
      after spring break up.





In
Summary





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


34


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.





Province/Granlea – Southeast
Alberta





No budget is assigned to this
prospect.





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.





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





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


35


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





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





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





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





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





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





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





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





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





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





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


36





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





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





Quarterly
Information





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




Kodiak
      Energy Inc.Consolidated
      Production Volume ScheduleTotal
      Production boeProduction
      By Product
            
            
            Q4
      2009
            
            
            
            Q3
      2009
            
            
            
            Q2
      2009
            
            
            
            Q1
      2009
            
            
            YTD
      2009Light
      Oil (bbls)
            
            
            10,323.8
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            10,323.8Natural
      Gas (mcf)
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Total
      (boe/d) (6:1)
            
            
            10,323.8
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            10,323.8Production
      By Area (boe)
            
            
            Q4
      2009
            
            
            
            Q3
      2009
            
            
            
            Q2
      2009
            
            
            
            Q1
      2009
            
            
            YTD
      2009Trout
            
            
            10,319.4
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            10,319.4Crossfield
            
            
            4.4
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            4.4Total
      (boe/d) (6:1)
            
            
            10,323.8
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            10,323.8boe/dProduction
      By Product
            
            
            Q4
      2009
            
            
            
            Q3
      2009
            
            
            
            Q2
      2009
            
            
            
            Q1
      2009
            
            
            YTD
      2009Light
      Oil (bbls/d)
            
            
            112.2
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            28.3Natural
      Gas (mcf/d)
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Total
      (boe/d) (6:1)
            
            
            112.2
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            28.3Production
      By Area (boe/d)
            
            
            Q4
      2009
            
            
            
            Q3
      2009
            
            
            
            Q2
      2009
            
            
            
            Q1
      2009
            
            
            YTD
      2009Trout
            
            
            112.2
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            28.3Total
      (boe/d) (6:1)
            
            
            112.2
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            28.3




37




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




Capital
Expenditures





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




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





Property
and Equipment





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





Liquidity
and Capital Resources





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





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





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





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


38




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







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





Kodiak
      Energy Inc.Consolidated
      Operating Expenses ScheduleOperating
      Expenses ($)
              
              
              Q4
      2009
              
              
              
              Q3
      2009
              
              
              
              Q2
      2009
              
              
              
              Q1
      2009
              
              
              YTD
      2009Operating
      Expenses
              
              
              411,879
              
              
              
              4,167
              
              
              
              1,002
              
              
              
              1,170.0
              
              
              
              418,218$/boe
      (6:1)
              
              
              39.90
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              40.51




39




Kodiak
      Energy Inc.Consolidated
      Netback Calculation ScheduleOperating
      Netback ($/boe)
            
            
            Q4
      2009
            
            
            
            Q3
      2009
            
            
            
            Q2
      2009
            
            
            
            Q1
      2009
            
            
            YTD
      2009Petroleum
      & Natural gas Revenue
            
            
            68.24
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            68.24Royalties
            
            
            10.64
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            10.64Operating
      Costs
            
            
            39.90
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            40.51Operating
      Netback
            
            
            17.71
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            17.09





Kodiak
      Energy Inc.Consolidated
      G&A ScheduleG&A
      Expenses ($)
              
              
              Q4
      2009
              
              
              
              Q3
      2009
              
              
              
              Q2
      2009
              
              
              
              Q1
      2009
              
              
              YTD
      2009G&A
      Expenses
              
              
              710,679
              
              
              
              658,872
              
              
              
              356,428
              
              
              
              493,462
              
              
              
              2,219,441$/boe(6:1)
              
              
              68.84
              
              
              
              N/A
              
              
              
              N/A
              
              
              
              N/A
              
              
              
              214.98




Kodiak
      Energy Inc.Consolidated
      Interest Income ScheduleInterest
      & Other Income ($)
                
                
                Q4
      2009
                
                
                
                Q3
      2009
                
                
                
                Q2
      2009
                
                
                
                Q1
      2009
                
                
                YTD
      2009Interest
      and Other Income
                
                
                11,800
                
                
                
                45
                
                
                
                725
                
                
                
                198.0
                
                
                
                12,768Gain/Loss
      on Disposal of Assets
                
                
                479,433
                
                
                
                
                
                
                
                
                
                
                
                (2,164.0
                )
                
                
                477,269Total
      Other Income
                
                
                491,233
                
                
                
                45
                
                
                
                725
                
                
                
                (1,966
                )
                
                
                490,037$/boe
      (6:1)
                
                
                47.58
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                47.47


40




Kodiak
      Energy Inc.Consolidated
      Interest Expense ScheduleInterest
      Expense ($)
              
              
              Q4
      2009
              
              
              
              Q3
      2009
              
              
              
              Q2
      2009
              
              
              
              Q1
      2009
              
              
              YTD
      2009
              
              
              Q4
      2008
              
              
              
              Q3
      2008
              
              
              
              Q2
      2008
              
              
              
              Q1
      2008
              
              
              YTD
      2008Interest
      Expense
              
              
              106,309
              
              
              
              -
              
              
              
              92
              
              
              
              211
              
              
              
              106,612
              
              
              
              160
              
              
              
              -
              
              
              
              1,257
              
              
              
              -
              
              
              
              1,417$/boe(6:1)
              
              
              10.30
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              10.33
              
              
              
              0
              
              
              
              0
              
              
              
              0
              
              
              
              0
              
              
              
              0


Consolidated
      DD&A ScheduleDD&A
      Expense ($)
            
            
            Q4
      2009
            
            
            
            Q3
      2009
            
            
            
            Q2
      2009
            
            
            
            Q1
      2009
            
            
            YTD
      2009
            
            
            
            Q4
      2008
            
            
            
            Q3
      2008
            
            
            
            Q2
      2008
            
            
            
            Q1
      2008
            
            
            YTD
      2008Depletion
      & Depreciation
            
            
            243,404
            
            
            
            5,409
            
            
            
            5,173
            
            
            
            4,600
            
            
            
            258,586
            
            
            
            7,266
            
            
            
            8,064
            
            
            
            6,840
            
            
            
            8,763
            
            
            
            30,933Accretion
            
            
            22,949
            
            
            
            3,461
            
            
            
            3,362
            
            
            
            3,188
            
            
            
            32,960
            
            
            
            4,266
            
            
            
            4,650
            
            
            
            4,808
            
            
            
            4,865
            
            
            
            18,589Asset
      Writedowns
            
            
            1,645,462
            
            
            
            211,156
            
            
            
            16,169,130
            
            
            
            -
            
            
            
            18,025,748
            
            
            
            869,847
            
            
            
            3,728
            
            
            
            
            
            
            
            
            
            
            
            873,575Total
      DD&A
            
            
            1,911,815
            
            
            
            220,026
            
            
            
            16,177,665
            
            
            
            7,788
            
            
            
            18,317,294
            
            
            
            881,379
            
            
            
            16,442
            
            
            
            11,648
            
            
            
            13,628
            
            
            
            923,097DD&A
      Expense $/boe (6:1)
            
            
            Q4
      2009
            
            
            
            Q3
      2009
            
            
            
            Q2
      2009
            
            
            
            Q1
      2009
            
            
            YTD
      2009
            
            
            
            Q4
      2008
            
            
            
            Q3
      2008
            
            
            
            Q2
      2008
            
            
            
            Q1
      2008
            
            
            YTD
      2008Depletion
      & Depreciation
            
            
            23.58
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            25.05
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Accretion
            
            
            2.22
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            3.19
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Asset
      Writedowns
            
            
            159.39
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            1,746.04
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Total
      DD&A $/boe (6:1)
            
            
            185.19
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            1,774.28
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -





ITEM
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK





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





PETROLEUM
AND NATURAL GAS AND RELATED HYDROCARBON PRICES





The
Company’s oil and gas business makes it vulnerable to changes in wellhead prices
of crude oil and natural gas. Such prices have been volatile in the past and can
be expected to be volatile in the future. By definition, proved reserves are
based on current oil and gas prices. Declines in oil and gas prices reduce the
estimated quantity of proved reserves and increase annual amortization expense
(which is based on proved reserves). Declines in oil and gas prices can reduce
the value of our oil and gas properties and increase impairment expense, as
occurred in 2009.
  We expect
oil and gas price volatility to continue. We do not currently utilize hedging
contracts to protect against commodity price risk. As our oil and gas production
grows, we may manage our exposure to oil and natural gas price declines by
entering into oil and natural gas price hedging arrangements to secure a price
for a portion of our expected future oil and natural gas
production.
 
 OPERATING COST
RISK
  During
2008 and 2009, we have generally experienced fluctuations in operating costs
(including costs of drilling and completing wells) which impact our cash flow
from operating activities and profitability. We expect our drilling activity in
2010 to be focused on drilling oil wells. Several other companies seek to drill
similar wells in the general area in 2010 whereby drilling and operating costs
may rise in response to demand for limited rigs and services in the
area.
  Fluctuations
in drilling costs and production costs, as well as fluctuations in oil and gas
prices can have a significant impact on our profitability and may be deciding
factors on how many wells we will drill in a given project or even if severe
shut in production to control overall costs.


FOREIGN
CURRENCY EXCHANGE RATES





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





INTEREST
RATES





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





41





ITEM
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA






REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 OPINION
ON THE AUDIT OF THE FINANCIAL STATEMENTS
 
 To the
Board of Directors and the Stockholders of
 Kodiak
Energy, Inc.
 
 We have
audited the accompanying consolidated balance sheets of Kodiak Energy, Inc. (The
“Company and subsidiaries”) as of December 31, 2009 and 2008 and the
consolidated statements of operations, stockholder’s equity and cash flows for
each of the three years in the period ended December 31, 2009.  These
financial statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
 
 We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform an audit to obtain reasonable assurance whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluation of the overall
financial statement presentation. We believe that our audits provides a
reasonable basis for our opinion.
 
 In our
opinion, the financial statements referred to above present fairly, in all
material respects, the financial position of the Company and subsidiaries as of
December 31, 2009 and 2008 and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 2009 in conformity
with accounting principles generally accepted in the United States of
America.
 
 As
discussed in Note 1 to the consolidated financial statements, the Company’s
ability to continue as a going concern is dependent on obtaining sufficient
working capital to fund future operations.  Management’s plan in
regard to these matters is also described in Note 1.  These financial
statements do not include any adjustments that might result from the outcome of
this uncertainty.
 
 As
discussed in Note 3 to the consolidated financial statement, the Company and
subsidiaries have changed their reserve estimates and related disclosures as a
result of adopting new oil and gas reserve estimation and disclosure
requirements as fo December 31, 2009.
 
 /s/ MEYERS NORRIS PENNY
LLP
 
 Chartered
Accountants
 Calgary,
Canada
 March 19,
2009




42




KODIAK
      ENERGY, INC.Consolidated
      Balance Sheets(Going
      Concern Uncertainty - Note 1)Years
      ended December 31,
              
              2009
              
              
              2008AssetsCurrent
      Assets:Cash
      and Short Term Deposits
              
              $
              2,058
              
              
              $
              75,175Accounts
      Receivable (Note 5)
              
              
              403,907
              
              
              
              64,325Prepaid
      Expenses and Deposits
              
              
              151,390
              
              
              
              106,062557,355
              
              
              
              245,562Other
      Assets (Note 6)
              
              
              296,153
              
              
              
              290,903Oil
      and natural gas properties, Full cost accounting (Note 7)Evaluated
      properties
              
              
              6,823,400
              
              
              
              -Less  accumulated
      depreciation, depletion and amortization
              
              
              2,165,994
              
              
              
              -4,657,406
              
              
              
              -Unevaluated
      properties excluded from depletion
              
              
              26,081,783
              
              
              
              36,559,367Furniture
      and Fixtures, net
              
              
              64,862
              
              
              
              75,56530,804,051
              
              
              
              36,634,932Total
      Assets
              
              $
              31,657,559
              
              
              $
              37,171,397Liabilities
      and Stockholders' EquityCurrent
      Liabilities:Accounts
      Payable (Note 8)
              
              $
              2,267,139
              
              
              $
              984,590Accrued
      Liabilities
              
              
              281,522
              
              
              
              122,842Note
      Payable to Related Party (Note 18)
              
              
              -
              
              
              
              32,841Note
      Payable (Note 9)
              
              
              1,364,036
              
              
              
              -Current
      portion of long term debt (Note 10)
              
              
              538,831
              
              
              
              -4,451,528
              
              
              
              1,140,273Long-term
      Liabilities (Note 10)
              
              
              3,400,489
              
              
              
              39,262Asset
      Retirement Obligations (Note 11)
              
              
              1,285,614
              
              
              
              199,574Total
      Liabilities
              
              
              9,137,631
              
              
              
              1,379,109Share
      Capital: Authorized 300,000,000 Common Shares Par Value $.001; 10,000,000
      (2008 -10,000,000) Common Shares Issued and Outstanding 110,407,186 (2008
      -110,023,998) Common Shares
              
              
              110,407
              
              
              
              110,024Additional
      Paid in Capital
              
              
              50,851,469
              
              
              
              49,296,114Other
      Comprehensive Loss
              
              
              (416,905
              )
              
              
              (4,903,762
              )Deficit
              
              
              (28,283,170
              )
              
              
              (8,710,088
              )22,261,801
              
              
              
              35,792,288Non
      controlling interest (Note 14)
              
              
              258,127
              
              
              
              -Total
      Liabilities and Equity
              
              $
              31,657,559
              
              
              $
              37,171,397Commitments
      and Contingencies (Note 16)Subsequent
      Events (Note 21)(See
      accompanying notes to the consolidated financial
    statements)




43





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




44




KODIAK
      ENERGY INC.Consolidated
      Statements of Operations(Going
      Concern Uncertainty - Note 1)Years
      ended December 31,
              
              2009
              
              
              2008
              
              
              2007REVENUEOil
      Sales, net of royalties
              
              $
              594,701
              
              
              $
              -
              
              
              $
              -Other
              
              
              12,768
              
              
              
              1,065
              
              
              
              225607,469
              
              
              
              1,065
              
              
              
              225EXPENSESOperating
              
              
              418,218
              
              
              
              9,646
              
              
              
              20,543General
      and Administrative
              
              
              2,219,441
              
              
              
              2,206,015
              
              
              
              2,470,230Depletion,
      Depreciation and Accretionincluding
      Ceiling Test Impairment
              
              
              18,317,295
              
              
              
              923,097
              
              
              
              218,841Interest
      Expense
              
              
              106,612
              
              
              
              1,417
              
              
              
              94,08321,061,566
              
              
              
              3,140,175
              
              
              
              2,803,697Loss
      Before Other Expenses
              
              
              20,454,097
              
              
              
              3,139,110
              
              
              
              2,803,472Gain
      on non-monetary transfer of properties
              
              
              (477,269
              )
              
              
              -
              
              
              
              -Loss
      on sale of assets
              
              
              -
              
              
              
              4,145Interest
      Income
              
              
              -
              
              
              
              (89,771
              )
              
              
              (84,809
              )(477,269
              )
              
              
              (85,626
              )
              
              
              (84,809
              )Loss
      before income taxes
              
              
              19,976,828
              
              
              
              3,053,484
              
              
              
              2,718,663Recovery
      of deferred income taxes (Note 12)
              
              
              -
              
              
              
              (978,835
              )
              
              
              (147,000
              )Net
      Loss
              
              
              19,976,828
              
              
              
              2,074,649
              
              
              
              2,571,663Net
      Loss attributed to Non Controlling Interest (Note 14)
              
              
              (403,746
              )
              
              
              -
              
              
              
              -Net
      Loss attributed to Kodiak
              
              $
              19,573,082
              
              
              $
              2,074,649
              
              
              $
              2,571,663Basic
      and diluted loss per share (Note 15)
              
              $
              (0.18
              )
              
              $
              (0.02
              )
              
              $
              (0.03
              )(See
      accompanying notes to the consolidated financial
    statements)




45




KODIAK
      ENERGY, INC.Consolidated
      Statements of Cash Flows(Going
      Concern Uncertainty - Note 1)Years
      ended December 31,
                
                2009
                
                
                2008
                
                
                2007(Restated
      - Note 2)Operating
      Activities:Net
      Loss
                
                
                (19,573,082
                )
                
                $
                (2,074,649
                )
                
                $
                (2,571,663
                )Adjustments
      to reconcile net loss to net cash used in operating
      activities:Depletion,
      Depreciation and Accretion including Ceiling Test Impairments and
      Write-downs
                
                
                18,317,295
                
                
                
                923,097
                
                
                
                218,841Stock-Based
      Compensation
                
                
                774,199
                
                
                
                674,226
                
                
                
                643,934Recovery
      of Deferred Income Taxes
                
                
                -
                
                
                
                (978,835
                )
                
                
                (147,000
                )Bad
      Debts Written off
                
                
                -
                
                
                
                -
                
                
                
                11,908Gain
      on non-monetary transfer of properties
                
                
                (477,269
                )
                
                
                -
                
                
                
                -Non-Controlling
      interest
                
                
                (403,746
                )
                
                
                -
                
                
                
                -Non-Cash
      Working Capital Changes (Note 20)
                
                
                397,569
                
                
                
                772,037
                
                
                
                (660,101
                )Net
      Cash Used In Operating Activities
                
                
                (965,034
                )
                
                
                (684,124
                )
                
                
                (2,504,081
                )Investment
      Activities:Additions
      to Capital Assets
                
                
                (5,563,737
                )
                
                
                (6,427,666
                )
                
                
                (7,508,553
                )Decrease
      (Increase) in Other Assets
                
                
                -
                
                
                
                68,450
                
                
                
                (309,493
                )Net
      Cash Used In Investment Activities
                
                
                (5,563,737
                )
                
                
                (6,359,216
                )
                
                
                (7,818,046
                )Financing
      Activities:Shares
      Issued and Issuable
                
                
                552,692
                
                
                
                2,768,087
                
                
                
                16,500,995Shares
      Issued by subsidary for cash
                
                
                1,046,925
                
                
                
                -
                
                
                
                -Proceeds
      from note payable
                
                
                369,179
                
                
                
                -
                
                
                
                3,300,000Repayment
      of note payable
                
                
                -
                
                
                
                -
                
                
                
                (732,500
                )(Decrease)
      Increase in Long Term Liabilities
                
                
                -
                
                
                
                (71,693
                )
                
                
                110,955Cash
      Provided By Financing Activities
                
                
                1,968,796
                
                
                
                2,696,394
                
                
                
                19,179,450Foreign
      Currency Translation
                
                
                4,486,857
                
                
                
                (4,561,561
                )
                
                
                321,987Net
      Cash (Decrease) Increase
                
                
                (73,118
                )
                
                
                (8,908,507
                )
                
                
                8,535,336Cash
      beginning of year
                
                
                75,175
                
                
                
                8,983,682
                
                
                
                448,346Cash
      end of year
                
                $
                2,057
                
                
                $
                75,175
                
                
                $
                8,983,682Cash
      is comprised of:Balances
      with banks
                
                $
                2,057
                
                
                $
                75,175
                
                
                $
                1,238,796Short
      term deposits
                
                $
                -
                
                
                $
                -
                
                
                $
                7,744,886$
                2,057
                
                
                $
                75,175
                
                
                $
                8,983,682(See
      accompanying notes to the consolidated financial
    statements)




46


KODIAK
ENERGY, INC.
 NOTES TO
THE CONSOLIDATED FINANCIAL STATEMENTS
 For the
Years Ended December 31, 2009 and 2008
 Stated in
US dollars
 
 1. ORGANIZATION,
BASIS OF PRESENTATION AND GOING CONCERN UNCERTAINTY
 
 The
accompanying consolidated financial statements include the accounts of Kodiak
Energy Inc. and subsidiaries (collectively “Kodiak”, the “Company”, “we”, “us”
or “our”) as at December 31, 2009 and December 31, 2008 , and are presented in
accordance with accounting principles generally accepted in the United States of
America (“U. S. GAAP”).
 
 The
Company was incorporated under the laws of the state of Delaware on December 15,
1999 under the name “Island Critical Care, Corp.” with authorized common stock
of 50,000,000 shares with a par value of $0.001. On December 30, 2004 the name
was changed to “Kodiak Energy, Inc.”  During 2008, the Company
increased its authorized capital to include 10,000,000 preferred
shares.
 
 With the
commencement of production in the fourth quarter, the Company is no longer an
exploration stage company.
 
 Going Concern
Uncertainty
 
 These
consolidated financial statements have been prepared assuming the Company will
continue as a going concern, which presumes the realization of assets and
discharge of liabilities in the normal course of business for the foreseeable
future. The Company has not generated positive cash flow since inception and has
incurred operating losses and will need additional working capital for its
future planned activities. The success of these programs is yet to be
determined. These conditions raise doubt about the Company’s ability to continue
as a going concern. Continuation of the Company as a going concern is dependent
upon obtaining sufficient working capital to finance ongoing operations. The
Company’s strategy to address this uncertainty includes additional equity and
debt financing; however, there are no assurances that any such financings can be
obtained on favorable terms, if at all. These financial statements do not
reflect the adjustments or reclassification of assets and liabilities that would
be necessary if the Company were unable to continue its operations.
 
 2. RESTATEMENT
 
 In March,
2009, we determined that it was necessary to restate our financial statements as
at December 31, 2007. The purpose of the restatement is to correct an error in
measurement and an error in the application of US GAAP in the course of
recording the following 2007 transactions:
 
 Issue of common shares of
the Company in consideration for the acquisition of
properties.
 
 On
September 28, 2007, the Company issued to Thunder River Energy, Inc. (“Thunder”)
7,000,000 common shares of the Company as partial consideration for the
acquisition of properties. The shares issued were recorded at a negotiated price
per share of US$2.00 or $14,000,000. In the course of a review by the Securities
and Exchange Commission (“SEC”) of the Company’s Form 10-Q for the Fiscal
Quarter Ended September 30, 2007 and Form 10-K for the Fiscal Year Ended
December 31, 2007, the SEC questioned the measurement date and the $2.00 per
share value at which the transaction was recorded. Following an exchange of
correspondence and discussions between the Company and the SEC during 2008 and
2009 regarding this issue, the Company has determined that the acquisition
should have been recorded at a value per share of $2.50 or $17,500,000, which
represents the fair value of exactly comparable common shares issued at the same
$2.50 price per share as a private placement financing for 2,756,000 common
shares which closed on September 28, 2007, the same date that the Thunder
transaction closed. Management believes that the $2.50 Kodiak share price to be
the most reliable measurement for the fair value of the shares issued and that
September 28, 2008 to be the appropriate measurement date because that was the
date when the parties’ closing conditions were satisfied and Thunder’s (the
counterparty’s) performance was complete. The result of the restatement
adjustment was an increase of $3,500,000 in the recorded acquisition cost and
related issuance of common shares.
  47
 
 Issue of flow-through common
shares of the Company at a premium.
 
 On
September 28, 2007, October 3, 2007 and October 30, 2007, the Company issued on
a Canadian flow-through share basis 2,251,670 common shares of the Company at
US$3.00 per share or $6,755,010, which amount represented a premium of $.50 per
share or $1,125,835 when compared to other non-flow through shares issued at the
same time at $2.50 per share. At the time of the transactions, the issues of the
flow through common shares were recorded as credits to par value of common
shares and additional paid in capital. Following discussions with the Company’s
tax consultant, the Company has determined that the $1,125,835 premium on
flow-through common shares issued should have, in accordance with US GAAP, been
recorded as a liability at the time the shares were issued rather than as
additional paid in capital. A $147,000 portion of the premium liability
discharged during the period October 1, 2007 to December 31, 2007, when
flow-through eligible expenditures amounting to $879,922 were incurred by the
Company, was recognized as a reduction of deferred tax expense.
 
 Effects
of the restatement by line item follow:
 
 Consolidated Balance
Sheets
 December31,
      2007
              
              
              
              
              
              DecemberAs
      Previously
              
              
              Impact
              
              
              31,
      2007Reported
              
              
              of
      Changes
              
              
              RestatedCash
      and Short Term Deposits
              
              $
              8,983,682
              
              
              
              -
              
              
              $
              8,983,682Accounts
      Receivable
              
              
              1,214,253
              
              
              
              -
              
              
              
              1,214,253Prepaid
      Expenses and Deposits
              
              
              90,475
              
              
              
              -
              
              
              
              90,475Total
      current assets
              
              
              10,288,410
              
              
              
              -
              
              
              
              10,288,410Other
      Assets
              
              
              359,353
              
              
              
              -
              
              
              
              359,353Unproved
      Oil and Gas Properties
              
              
              23,967,351
              
              
              
              3,500,000
              
              
              
              27,467,351Furniture
      and Fixtures
              
              
              75,654
              
              
              
              -
              
              
              
              75,654Total
      Property, Plant and Equipment
              
              
              24,043,005
              
              
              
              3,500,000
              
              
              
              27,543,005Total
      Assets
              
              $
              34,690,768
              
              
              
              3,500,000
              
              
              
              38,190,768Accounts
      Payable
              
              $
              1,547,273
              
              
              
              -
              
              
              
              1,547,273Accrued
      Liabilities
              
              
              755,282
              
              
              
              -
              
              
              
              755,282Premium
      on Flow-through Shares Issued
              
              
              -
              
              
              
              978,835
              
              
              
              978,835Total
      current liabilities
              
              
              2,302,555
              
              
              
              978,835
              
              
              
              3,281,390Long
      Term Liabilities
              
              
              110,955
              
              
              
              -
              
              
              
              110,955Asset
      Retirement Obligations
              
              
              151,814
              
              
              
              -
              
              
              
              151,814Deferred
      Income Taxes
              
              
              57,000
              
              
              
              (57,000
              )
              
              
              -Share
      Capital
              
              
              106,692
              
              
              
              -
              
              
              
              106,692Additional
      Paid in Capital
              
              
              39,143,392
              
              
              
              2,374,165
              
              
              
              41,517,557Other
      Comprehensive Loss
              
              
              (342,201
              )
              
              
              -
              
              
              
              (342,201
              )Deficit
      Accumulated during the Exploration Stage
              
              
              (6,839,439
              )
              
              
              204,000
              
              
              
              (6,635,439
              )Total
      Shareholders’ Equity
              
              
              32,068,444
              
              
              
              2,578,165
              
              
              
              34,646,609Total
      Liabilities and Shareholders’ Equity
              
              $
              34,690,768
              
              
              
              3,500,000
              
              
              
              38,190,768
  48
  Consolidated Statement of
Shareholders' Equity Period April 7, 2004 (Date of Inception) to December 31,
2007
 
 Par
      Value
              
              
              Additional
                Paid
      in
                Capital
              Deficit
                Accumulated
                during
      the
                Development
                Stage
              
              
              Accumulated
                Other
                Comprehensive
                Loss
              Total
                Shareholders'
                EquityBalance
      December 31, 2007 as Previously Reported
              
              
              106,692
              
              
              
              39,143,392
              
              
              $
              (6,839,439
              )
              
              $
              (342,201
              )
              
              $
              32,068,444Impact
      of Changes
              
              
              -
              
              
              
              2,374,165
              
              
              
              204,000
              
              
              
              -
              
              
              
              2,578,165Balance
      December 31, 2007 as Restated
              
              
              106,692
              
              
              
              41,517,560
              
              
              $
              (6,635,439
              )
              
              $
              (342,201
              )
              
              $
              34,646,609
  3.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
 Basis of
Presentation
 
 These
consolidated financial statements include the accounts of the Company and its
wholly-owned subsidiaries, Kodiak Petroleum ULC, Kodiak Petroleum (Montana),
Inc., Kodiak Petroleum (Utah), Inc. and its 84.62% owned subsidiary Cougar
Energy, Inc. (formerly 1438821 Alberta Ltd.)  (“Cougar”). In British
Columbia, Canada, the Company operates under the assumed name of Kodiak Bear
Energy, Inc. All intercompany balances and transactions have been
eliminated.
 
 Use of
Estimates
 
 The
preparation of financial statements in conformity with U.S. generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the consolidated financial
statements and the reported amounts of revenues and expenses during the periods
reported. Actual results could differ from these estimates.
 
 Significant
estimates include volumes of oil and natural gas reserves used in calculating
depletion of proved oil and natural gas properties, future net revenues and
abandonment obligations, impairment of unproved properties, future taxable
income and related assets/liabilities, the collectability of outstanding
accounts receivable, fair values of derivatives, stock-based compensation
expense, contingencies and the results of current and future
litigation.
 
 Oil and
natural gas reserve estimates which are the basis for unit-of-production
depletion and the ceiling test, have numerous inherent uncertainties. The
accuracy of any reserve estimate is a function of the quality of available data
and of engineering and geological interpretation and judgment. Subsequent
drilling results, testing and production may justify revision of such estimates.
Accordingly, reserve estimates are often different from the quantities of oil
and natural gas that are ultimately recovered. In addition, reserve estimates
are vulnerable to changes in wellhead prices of crude oil and natural gas. Such
prices have been volatile in the past and can be expected to be volatile in the
future.
 
 The
significant estimates are based on current assumptions that may be materially
affected by changes to future economic conditions such as the market prices
received for sales of volumes of oil and natural gas, the creditworthiness of
counterparties, interest rates, the market value of the Company’s common stock
and corresponding volatility and the Company’s ability to generate future
taxable income. Future changes in these assumptions may affect these significant
estimates materially in the near term. The Company has also evaluated subsequent
events for recording and disclosures, including assumptions used in its
estimates.
  49
  Joint Venture
Operations
 
 In
instances where the Company’s oil and gas activities are conducted jointly with
others, the Company’s accounts reflect only its proportionate interest in such
activities.
 
 Cash and Short-term
Deposits
 
 Cash
consists of balances with financial institutions and investments in money market
instruments, which have terms to maturity of three months or less at time of
purchase.
 
 Oil and Gas
Properties
 
 Under the
full cost method of accounting for oil and gas operations all costs associated
with the exploration for and development of oil and gas reserves are capitalized
on a country-by-country basis. Such costs include land acquisition costs,
geological and geophysical expenses, carrying charges on non-producing
properties, costs of drilling both productive and non-productive wells,
production equipment and overhead charges directly related to acquisition,
exploration and development activities. Proceeds from the sale of oil and gas
properties are applied against capitalized costs with no gain or loss
recognized, unless such a sale would alter the rate of depletion and
depreciation by 25% in a particular country, in which case a gain or loss on
disposal is recorded.
 
 Capitalized
costs, less accumulated amortization and related deferred income taxes, are
limited to a “ceiling-test” based on the estimated future net revenues,
discounted at 10% per annum, from proved oil and natural gas reserves, less
estimated future expenditures to be incurred in developing and producing the
proved reserves, less any related income tax effects. If net capitalized costs
exceed this limit, the excess is charged to earnings. The option to use a
pricing date subsequent to the balance sheet is no longer available to the
Company effective December 31, 2009 due to the adoption of the new oil and
natural gas reporting requirements as described below under “Recently Adopted
Accounting Pronouncements.”
 
 Capitalized
costs within each country are depleted and depreciated on the unit-of-production
method based on the estimated gross proved reserves as determined by independent
petroleum engineers. Oil and gas reserves and production are converted into
equivalent units on the basis of 6,000 cubic feet of natural gas to one barrel
of oil. Depletion and depreciation is calculated using the capitalized costs,
including estimated asset retirement costs, plus the estimated future costs to
be incurred in developing proved reserves, net of estimated salvage
value.
 
 Costs of
acquiring and evaluating unproved properties and major development projects are
initially excluded from the depletion and depreciation calculation until it is
determined whether or not proved reserves can be assigned to such properties.
Costs of unproved properties and major development projects are transferred to
depletable costs based on the percentage of reserves assigned to each project
over the expected total reserves when the project was initiated. These costs are
assessed periodically to ascertain whether impairment has occurred.
 
 Property and
Equipment
 
 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.
 
 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.
  50
  Environmental
 
 Oil and
gas activities are subject to extensive federal, provincial, state and local
environmental laws and regulations. These laws, which are constantly changing,
regulate the discharge of materials into the environment and may require the
Company to remove or mitigate the environmental effects of the disposal or
release of petroleum or chemical substances at various sites.
 
 Environmental
expenditures are expensed or capitalized depending on their future economic
benefit. Expenditures that relate to an existing condition caused by past
operations and that have no future economic benefits are expensed. Liabilities
for expenditures of a non-capital nature are recorded when environmental
assessment and/or remediation is probable, and the costs can be reasonably
estimated
 
 Income
Taxes
 
 Income
taxes are determined using assets and liability method. Deferred tax assets and
liabilities are recognized for the future tax consequences attributable to
differences between the financial statement carrying amounts of existing assets
and liabilities and their respective tax bases. Deferred tax assets and
liabilities are measured using the enacted tax rates expected to apply to
taxable income in the years in which those temporary differences are expected to
be recovered or settled. The effect on deferred tax assets and liabilities of a
change in tax rates is recognized in the period that includes the enactment
date. In addition, a valuation allowance is established to reduce any deferred
tax asset for which it is determined that it is more likely than not that some
portion of the deferred tax asset will not be realized.
 
 Per FASB
ASC 740 “Income taxes” under the liability method, it is the Company’s policy to
provide for uncertain tax positions and the related interest and penalties based
upon management’s assessment of whether a tax benefit is more likely than not to
be sustained upon examination by tax authorities. At December 31, 2009, the
Company believes it has appropriately accounted for any unrecognized tax
benefits. To the extent the Company prevails in matters for which a liability
for an unrecognized benefit is established or is required to pay amounts in
excess of the liability, the Company’s effective tax rate in a given financial
statement period may be affected. Interest and penalties associated with the
Company’s tax positions are recorded as Interest Expense.
 
 Flow-through
Shares
 
 From time
to time the Company finances a portion of its Canadian exploration programs with
flow-through common shares issued pursuant to certain provisions of the Income
Tax Act (Canada) (the “Act”). Under the Act, where the proceeds are used for
eligible expenditures, the related income tax deductions may be renounced to
subscribers. Accordingly, the tax credits associated with the renunciation of
such expenditures are recorded as an increase to deferred income tax
liabilities. Any premium received from subscribers on the sale of such
flow-through common shares is recorded initially as a current liability and then
discharged and recognized as a reduction of deferred income taxes when the
flow-through eligible expenditures relating to the flow-through premium are
incurred by the Company.
 
 Financial
Instruments
 
 The
Company’s financial instruments consist of cash, accounts receivables, accounts
payables, accrued liabilities, notes payable and long-term debt. The carrying
amount of cash, accounts  receivables, accounts payable, accrued
liabilities, and notes payable approximates fair value because of the short-term
nature of these items. The carrying amounts of long-term debt approximate the
fair values as these borrowings have been discounted at market
rates.
  51
  Concentration of Credit
Risk
 
 Substantially
all of the Company’s accounts receivable result from oil and natural gas sales,
joint interest billings to third parties in the oil and natural gas industry or
drilling and completion advances to third-party operators for development costs
of in-progress wells. This concentration of customers and joint interest owners
may impact the Company’s overall credit risk in that these entities may be
similarly affected by changes in economic and other industry conditions. The
Company does not require collateral from its customers. The Company generally
has the right to offset revenue against related billings to joint interest
owners
 
 Stock-Based
Compensation
 
 The
Company records compensation expense for share based payments using the fair
value method in accordance with FASB ASC 718 “Compensation- Stock Compensation”.
The fair value of share-based compensation to employees will be determined using
an option pricing model at the time of grant. Fair value for common shares
issued for goods or services rendered by non-employees are measured based on the
fair value of the goods or services received. Stock-based compensation expense
is included in general and administrative expense with a corresponding increase
to Additional Paid in Capital. Upon the exercise of the stock options,
consideration paid together with the previously recognized Additional Paid in
Capital is recorded as an increase in share capital.
 
 Foreign Currency
Translation
 
 The
functional currency for the Company’s foreign operations is the Canadian dollar.
The translation from the applicable foreign currencies to U.S. dollars is
performed for asset and liability accounts using current exchange rates in
effect at the balance sheet date, while income, expenses and cash flows are
translated at the average exchange rates for the period. The resulting
translation adjustments are recorded as a component of other comprehensive loss.
Gains or losses resulting from foreign currency transactions are included in
other income/expenses.
 
 Revenue
Recognition
 
 Revenues
from the sale of petroleum and natural gas are recorded when title passes from
the Company to its petroleum and/or natural gas purchaser and collectability is
reasonably assured.
 
 Loss Per Common
Share
 
 Basic
loss per common share is computed by dividing net loss by the weighted average
number of common shares outstanding for the period. Diluted loss per common
share is computed after giving effect to all dilutive potential common shares
that were outstanding during the period. Dilutive potential common shares
consist of incremental shares issuable upon exercise of stock options and
warrants, contingent stock, conversion of debentures and preferred stock
outstanding. The dilutive effect of potential common shares is not considered in
the EPS calculations for these periods if the impact would have been
anti-dilutive.
 
 Non-controlling
Interests
 
 We
adopted the accounting standard for non-controlling interests in the
consolidated financial statements as of January 1, 2009. This standard
establishes accounting and reporting standards for ownership interests in
subsidiaries held by parties other than the parent, the amount of consolidated
net income attributable to the parent and to the non-controlling interest,
changes in a parent’s ownership interest and the valuation of retained
non-controlling equity investments when a subsidiary is deconsolidated. This
standard also establishes reporting requirements that provide sufficient
disclosures that clearly identify and distinguish between the interest of the
parent and the interests of the non-controlling owner.
  52
  Accounting for Changes in
Ownership Interests in Subsidiaries
 
 The
Company’s ownership interest in a consolidated subsidiary may change if it sells
a portion of its interest, or if the subsidiary issues or re-purchases its own
shares. If the transaction does not result in a change in control over the
subsidiary and it is not deemed to be a sale of real estate, the transaction is
accounted for as an equity transaction. If the transaction results in a change
in control it would result in the deconsolidation of a subsidiary with a gain or
loss recognized in the statement of operations. During 2009 the Company’s
ownership interest in Cougar Energy Inc. changed in three separate transactions
which were accounted for as equity transactions. See Note 14 Non-Controlling
Interest for a description of the transactions and the impact to the financial
statements.
 
 Accounting for Sales of
Stock by a Subsidiary
 
 The
Corporation issued common shares in various transactions, which resulted in a
dilution of the Corporation's percentage ownership in the Subsidiary. The
Corporation accounted for the sale of the Subsidiary common shares in accordance
with guidance related to equity transactions. The guidance allows for the
election of an accounting policy of recording such increase or decreases in a
parent's investment either in income or in equity. The Corporation adopted a
policy of recording such gains or losses directly to additional paid in
capital.
  4.  RECENT
ACCOUNTING PRONOUNCEMENTS
 
 In
December 2007, the Financial Accounting Standards Board (the "FASB") issued FASB
Accounting Standards Codification (ASC) 805, "Business Combinations",formerly Statement No. 141R, "Business Combinations"("SFAS No. 141R"). Under ASC 805, a company is required to recognize the
assets acquired, liabilities assumed, contractual contingencies, and any
contingent consideration measured at their fair value at the acquisition date.
It further requires that research and development assets acquired in a business
combination that have no alternative future use are to be measured at their
acquisition-date fair value and then immediately charged to expense, and that
acquisition-related costs are to be recognized separately from the acquisition
and expensed as incurred. Among other changes, this statement also requires that
"negative goodwill" be recognized in earnings as a gain attributable to the
acquisition, and any deferred tax benefits resultant in a business combination
be recognized in income from continuing operations in the period of the
combination. ASC 805 is effective for business combinations for which the
acquisition date is on or after the beginning of the first annual reporting
period beginning after December 15, 2008. On January 1, 2009, the Company
adopted ASC 805 and applies its provisions prospectively to business
combinations that occur after adoption. The adoption did not have any immediate
effect on the financial statements and related disclosures.
 
 In
September 2008, the EITF reached a consensus for exposure on Issue No. 08-6,
“Equity Method Investment Accounting Considerations”. This issue addresses the
accounting for equity method investments as a result of the accounting changes
prescribed by SFAS 141(R) and SFAS 160. The issue includes clarification on the
following: (a) transaction costs should be included in the initial carrying
value of the equity method investment, (b) an impairment assessment of an
underlying indefinite-life intangible asset of an equity method investment need
only be performed as part of any other-than-temporary impairment evaluation of
the equity method investment as a whole and does not need to be performed
annually, (c) the equity method investee’s issuance of shares should be
accounted for as the sale of a proportionate share of the investment, which may
result in a gain or loss in income, and (d) a gain or loss should not be
recognized when changing the method of accounting for an investment from the
equity method to the cost method. For the Company, this issue was effective
January 1, 2009. The impact of this issue did not have a material effect on our
consolidated financial statements.
 
 In June
2009, the Financial Accounting Standards Board (“FASB”) issued an accounting
standard ASC 855
-
 "Subsequent events"for
subsequent events which establishes general standards of accounting for and
disclosure of events that occur after the balance sheet date but before
financial statements are issued. This standard is effective for interim or
annual periods ending after June 15, 2009.
 
 In June
2009, the FASB issued an accounting standard that codifies and modifies the
hierarchy of generally accepted accounting principles. This standard is the
source of authoritative GAAP recognized by the FASB to be applied by
nongovernmental entities. Rules and interpretive releases of the Securities and
Exchange Commission (“SEC”) under authority of federal securities laws are also
sources of authoritative GAAP for SEC registrants. This standard superseded all
then-existing non-SEC accounting and reporting standards. All other non
grandfathered non-SEC accounting literature not included in this standard is now
non authoritative. This standard is effective for financial statements issued
for interim and annual periods ending after September 15, 2009. The adoption of
this standard did not have an impact on our consolidated financial position,
results of operations or cash flows.
  53
  Effective
July 1, 2009, the Company adopted FASB ASU No. 2009-05, Fair Value
Measurements and Disclosures (Topic 820) (“ASU 2009-05”). ASU 2009-05 provided
amendments to ASC 820-10, “Fair Value Measurements and Disclosures – Overall,
for the fair value measurement of liabilities”. ASU 2009-05 provides
clarification that in circumstances in which a quoted price in an active market
for the identical liability is not available, a reporting entity is required to
measure fair value using certain techniques. ASU 2009-05 also clarifies that
when estimating the fair value of a liability, a reporting entity is not
required to include a separate input or adjustment to other inputs relating to
the existence of a restriction that prevents the transfer of a liability. ASU
2009-05 also clarifies that both a quoted price in an active market for the
identical liability at the measurement date and the quoted price for the
identical liability when traded as an asset in an active market when no
adjustments to the quoted price of the asset are required are Level 1 fair value
measurements. Adoption of ASU 2009-05 did not have a material impact on the
Company’s consolidated results of operations or financial
condition.
 
 On
December 31, 2008 the SEC issued the final rule, "Modernization of Oil and Gas
Reporting"(the "Final Reporting Rule"). The Final Reporting Rule adopts
revisions to the SEC's oil and gas reporting disclosure requirements and is
effective for annual reports on Forms 10-K for years ending on or after December
31, 2009. The revisions are intended to provide investors with a more meaningful
and comprehensive understanding of oil and gas reserves to help investors
evaluate their investments in oil and gas companies. The amendments are also
designed to modernize the oil and gas disclosure requirements to align them with
current practices and changes in technology. Revised requirements in the Final
Reporting Rule include, but are not limited to:
 
 • Oil and
gas reserves must be reported using the un-weighted arithmetic average of the
first day of the month price for each month within a 12 month period, rather
than year-end prices;
 
 •
Companies will be allowed to report, on an optional basis, probable and possible
reserves;
 
 •
Non-traditional reserves, such as oil and gas extracted from coal and shales,
will be included in the definition of "oil and gas producing
activities;"
 
 •
Companies will be permitted to use new technologies to determine proved
reserves, as long as those technologies have been demonstrated empirically to
lead to reliable conclusions with respect to reserve volumes;
 
 •
Companies will be required to disclose, in narrative form, additional details on
their proved undeveloped reserves ("PUDs"), including the total quantity of PUDs
at year end, and any material changes to PUDs that occurred during the year,
investments and progress made to convert PUDs to developed oil and gas reserves
and an explanation of the reasons why material concentrations of PUDs in
individual fields or countries have remained undeveloped for five years or more
after disclosure as PUDs; and Companies will be required to report the
qualifications and measures taken to assure the independence and objectivity of
any business entity or employee primarily responsible for preparing or auditing
reserves estimate.
 
 We have
complied with the disclosure requirements in our annual report on Form 10-K for
the year ended December 31, 2009.
 
 Application
of the new reserves rules resulted in the use of lower prices at December 31,
2009 for crude oil than would have been used under the previous
rules.
  54
  The
following new accounting standards have been issued, but have not yet been
adopted by the Company:
 
 Effective
April 1, 2009, FASB ASC 820-10-65, Fair Value Measurements and Disclosures –
Overall – Transition and Open Effective Date Information (“ASC 820-10-65”). ASC
820-10-65 provides additional guidance for estimating fair value in accordance
with ASC 820-10 when the volume and level of activity for an asset or liability
have significantly decreased. ASC 820-10-65 also includes guidance on
identifying circumstances that indicate a transaction is not
orderly.
 
 Effective
April 1, 2009, FASB ASC 825-10-65, Financial Instruments – Overall – Transition
and Open Effective Date Information (“ASC 825-10-65”). ASC 825-10-65 amends ASC
825-10 to require disclosures about fair value of financial instruments in
interim financial statements as well as in annual financial statements and also
amends ASC 270-10 to require those disclosures in all interim financial
statements.
 
 Effective
April 1, 2009, FASB ASC 855-10, Subsequent Events – Overall (“ASC 855-10”). ASC
855-10 establishes general standards of accounting for and disclosure of events
that occur after the balance sheet date but before financial statements are
issued or are available to be issued.
  Effective
July 1, 2009,  FASB 107-1 (ASU No. 825) which amends FASB 107,
Disclosures about Fair Value of Financial Instruments (SFAS 107) to require
entities to disclose, among other things, the methods and significant
assumptions used to estimate the fair value of financial instruments in both
interim and annual financial statements.  This FSP also amends APB
Opinion No. 28, Interim Financial Reporting (Opinion 28) to require those
disclosures in summarized financial information at interim reporting
periods.
 
 In
October 2009, the FASB issued ASU 2009-13, Multiple-Deliverable Revenue
Arrangements, (amendments to FASB ASC Topic 605, Revenue Recognition ) (“ASU
2009-13”) and ASU 2009-14, Certain Arrangements That Include Software Elements ,
(amendments to FASB ASC Topic 985, Software ) (“ASU 2009-14”). ASU 2009-13
requires entities to allocate revenue in an arrangement using estimated selling
prices of the delivered goods and services based on a selling price hierarchy.
The amendments eliminate the residual method of revenue allocation and require
revenue to be allocated using the relative selling price method. ASU
2009-14 removes tangible products from the scope of software revenue guidance
and provides guidance on determining whether software deliverables in an
arrangement that includes a tangible product are covered by the scope of the
software revenue guidance. ASU 2009-13 and ASU 2009-14 should be applied on
a prospective basis for revenue arrangements entered into or materially modified
in fiscal years beginning on or after June 15, 2010, with early adoption
permitted. The Company does not expect adoption of ASU 2009-13 or ASU 2009-14 to
have a material impact on the Company’s consolidated results of operations or
financial condition.
  5.
ACCOUNTS RECEIVABLE
 
 Accounts
receivable consist of the following:
 
 2009
              
              
              2008Non-operating
      Partner joint venture accounts
              
              $
              309,667
              
              
              $
              1,193Government
      of Canada Goods and Services Tax Claims
              
              
              14,547
              
              
              
              16,733Other
              
              
              79,693
              
              
              
              46,399$
              403,907
              
              
              $
              64,325
  55
  6. OTHER
ASSETS
 
 Other
assets represent long term deposits required by governmental regulatory
authorities for environmental obligations relating to well abandonment and site
restoration activities.
 
 2009
              
              
              2008Alberta
      Energy and Utility Board Drilling Deposit
              
              $
              43,738
              
              
              $
              73,507Department
      of Energy Reclaimation Deposit
              
              
              476
              
              
              
              -British
      Columbia Oil and Gas Commission Deposit
              
              
              251,939
              
              
              
              217,396$
              296,153
              
              
              $
              290,903
  7.
CAPITAL ASSETS
  Cost
              
              
              Accumulated
      Depreciation and Depletion
              
              
              Net
      book Value December 31, 2009Oil
      and Gas Properties:DevelopedCanada
              
              $
              6,823,400
              
              
              $
              2,165,994
              
              
              $
              4,657,406UndevelopedCanada
              
              
              32,441,500
              
              
              
              17,634,527
              
              
              
              14,806,973United
      States
              
              
              11,773,677
              
              
              
              498,867
              
              
              
              11,274,81044,215,177
              
              
              
              18,133,394
              
              
              
              26,081,783Furniture
      and Fixtures
              
              
              168,166
              
              
              
              103,304
              
              
              
              64,862Total
              
              $
              51,206,743
              
              
              $
              20,402,692
              
              
              $
              30,804,051Cost
              
              
              Accumulated
      Depreciation and Depletion
              
              
              Net
      book Value December 31, 2008Oil
      and gas Properties:UndevelopedCanada
              
              $
              27,244,206
              
              
              $
              1,935,428
              
              
              $
              25,308,778United
      States
              
              
              11,749,456
              
              
              
              498,867
              
              
              
              11,250,58938,993,662
              
              
              
              2,434,295
              
              
              
              36,559,367Furniture
      and Fixtures
              
              
              148,025
              
              
              
              72,460
              
              
              
              75,565Total
              
              $
              39,141,687
              
              
              $
              2,506,755
              
              
              $
              36,634,932
  During
the year ended December 31, 2009, the Company capitalized $182,202 (2008 -
$292,824) of general and administrative personnel costs attributable to
acquisition, exploration and development activities.   Future
capital costs included in the depletion calculation for December 31, 2009 was
$619,000 (2008-Nil)
 
 Capital
addition for the years ended December 31, 2009 and 2008 were as
follows:
 
 2009
              
              
              2008Land
      acquisition and carrying costs
              
              $
              8,044,239
              
              
              $
              5,536,736Geological
      and geophysical
              
              
              1,523,613
              
              
              
              4,827,123Intangible
      drilling and completion
              
              
              545,475
              
              
              
              3,892,511Tangible
      completion and facilities
              
              
              882,267
              
              
              
              140,151Long
      Lived Assets
              
              
              1,049,321
              
              
              
              -Other
      fixed assets
              
              
              9,851
              
              
              
              33,470Total
      Capital Costs Incurred
              
              $
              12,054,766
              
              
              $
              14,429,991
  56
  Unproved
Properties
 
 Included
in oil and gas properties are the following costs related to Canadian and United
States unproved properties, valued at cost, that have been excluded from costs
subject to depletion:
  2009
              
              
              2008CanadaLand
      acquisition and retention
              
              $
              1,503,314
              
              
              $
              15,039,607Geological
      and geophysical costs
              
              
              10,867,335
              
              
              
              9,330,180Exploratory
      drilling
              
              
              2,220,826
              
              
              
              619,409Tangible
      Equipment and Facilities
              
              
              215,501
              
              
              
              244,450Other
              
              
              0
              
              
              
              75,132$
              14,806,976
              
              
              $
              25,308,778United
      StatesLand
      acquisition and retention
              
              $
              8,168,134
              
              
              $
              8,158,899Geological
      and geophysical costs
              
              
              937,924
              
              
              
              941,836Exploratory
      drilling
              
              
              1,993,244
              
              
              
              1,974,346Tangible
      Equipment and Facilities
              
              
              95,699
              
              
              
              95,699Other
              
              
              79,809
              
              
              
              79,809$
              11,274,810
              
              
              $
              11,250,589
  In
Canada, a stimulation and horizontal drilling program is planned for our British
Columbia property during the next year. In the United States, an initial seismic
and drilling program has been conducted on our New Mexico property with
additional drilling to follow. These planned activities, when completed, will
enable the Company to evaluate the economic viability of these
properties.
 
 The costs
associated with the unproved properties are subject to a test for impairment
which is separate from the test applied to proved resource
properties.
 
 Property
Acquisition
 
 On
September 30, 2009, Cougar acquired from an unrelated private company certain
wells, facilities and producing operations in and adjacent to the CREEnergy
Project in Alberta, Canada. The purchase price of the acquisition was $5,604,000
of which $934,000 was paid in cash and the remainder in the form of non-interest
bearing debt. At December 31, 2009, the non-interest bearing balance of
$4,471,990 was payable in accordance with the terms set out in Note
10.
 
 On
October 1, 2009 Cougar acquired wells, facilities and production from a private
company with operations in the Trout area of Alberta, Canada.  The
purchase price of the acquisition was $291,650, $107,241 in cash payable over 18
months with the balance to be paid by the issuance of 155,000 common shares of
Cougar.
 
 On
October 1, 2009, Cougar received as a default payment in a farmout agreement,
two oil and natural gas leases. The transaction was accounted for as a
non-monetary transaction in relation to the receipt of assets for no cash
consideration.  As a result, a gain of $477,269 was recorded in the
financial statements.
 
 During
the year, Cougar entered into an agreement with CREEnergy Oil and Gas Inc. 
The agreement provides for an "exclusivity contract" with CREEnergy for oil and
gas properties for up to 15 townships or 345,000 gross acres of mineral rights
in north central Alberta, Canada. The initial leases, as outlined in the
agreement, are for mineral rights on a total of 46,000 gross acres for a lease
term of 10 years. As the project moves forward, additional leases will be
identified and added to the joint venture.  The cash payment of $951,474
was funded with a private equity issue in Cougar.
 
 Full Cost Accounting Ceiling
Test on Canadian Proved Oil and Gas Properties
 
 At
December 31, 2009, a ceiling test was performed on the Company's properties
subject to depletion. Costs of unproved properties aggregating $6,277,616 and
future abandonment costs of $306,375 have been excluded from this test. This
test disclosed that the carrying costs of the Company's depletable Canadian
properties exceeded their net present value by $1,570,607 and consequently a non
cash ceiling test write-down of that amount has been
recorded.
  57
  Reserves
  In
December 2008, the SEC issued its final rule, Modernization of Oil and Gas
Reporting, which is effective for reporting 2009 reserve information. In January
2010, the FASB issued its authoritative guidance on extractive activities for
oil and gas to align its requirements with the SEC’s final rule. We adopted the
guidance as of December 31, 2009 in conjunction with our year-end reserve report
as a change in accounting principle that is inseparable from a change in
accounting estimate. Under the SEC’s final rule, prior period reserves were not
restated.
 
 For the
United States, the primary impact of the SEC’s final rule on our reserve
estimates include the use of the unweighted 12 month average of the
first-day-of-the-month reference price of $58.21 USD per barrel.
 
 The
impact of the adoption of the SEC’s final rule on our financial statements is
not practicable to estimate due to the operational and technical challenges
associated with calculating a cumulative effect of adoption by preparing reserve
reports under both the old and new rules.
  8.
ACCOUNTS PAYABLE
 
 Included
in accounts payable at December 31, 2009 is $517,026 (2008 – Nil) which related
to funds advanced to the Company by outside investors pursuant to an agreement
to convert the balance of the advances to working interests in certain
properties subject to regulatory and other approvals.
 
 9. NOTE
PAYABLE
 
 During
the year, the Company entered into a loan agreement with Ionic Capital Corp.
("Ionic"), under the terms of which Ionic loaned $1,292,675 to the Company to
enable it to close the CREEnergy property acquisition described in Note 7. The
indebtedness bears interest at the rate of 12% per annum payable monthly in
arrears and is repayable at any time up to but no later than June 30, 2010. As
additional financing consideration for the loan, the Company agreed to issue
common shares based on a 10% discount to the 10 day weighted average closing
trading price on September 25, 2009 that equated to 12% of the principal amount
of the financing. The 383,188 common shares of the Company that were issued to
satisfy that obligation were recorded at a value of $187,762 based on the
closing market price of the Company’s common shares on September 30,
2009.  Share issue costs associated with this transaction were
$33,172.  In December of 2009 the debt was assumed by Zentrum Energie
AG (“Zentrum”) under the existing terms and conditions.  The
indebtedness above is governed by several operational covenants. As at December
31, 2009 the Company was in compliance with all covenants. On January 25, 2010,
the debt converted to equity(Note 21).
 
 During
the year, Zentrum advanced an additional $71,361 to the Company. The note bears
interest at 1% per annum and the principle less prepayments and accrued interest
is due on or before November 17, 2010.
 
 10. LONG
TERM LIABILITIES
 
 The
Company has the following long-term liabilities:
 
 2009
              
              
              2008Amount
      due to vendor of CREEnergy properties
              
              $
              4,471,930Amount
      of Discount to be accreted in the future (at 7.5% annually - .0625% per
      month)
              
              
              (650,425
              )
              
              
              -Present
      value of amount due
              
              
              3,821,505
              
              
              
              -Amount
      due to vendor of Trout area properties
              
              
              72,312Total
      indebtedness from the purchase of properties
              
              
              3,893,817Less
      current portion
              
              
              538,831
              
              
              
              -Long-term
      portion
              
              
              3,354,986
              
              
              
              -Funds
      advanced by partners for their share of a drilling deposit required to be
      lodged by the Company with the British Columbia Oil and Gas Commission
      (See Note 6) as security for future well abandonment and site restoration
      activities
              
              
              45,502
              
              
              
              39,262Total
              
              
              3,400,488
              
              
              
              39,262
  The total
amount due to the vendor of the Trout Core properties is payable in
accordance with the following schedule:
 
 Due in 2010 in 11
      monthly installments
              
              $
              732,635Due
      in 2011 in 12 monthly installments
              
              
              970,504Due
      in 2012 in 12 monthly installments
              
              
              1,141,769Due
      in 2013 in 12 monthly installments
              
              
              1,313,035Due
      in 2014 in 2 monthly installments
              
              
              313,987$
              4,471,930
  The Company has the right to prepay the
vendor loan in full, without penalty, semi-annually commencing March 31, 2010 at
a proportionate discount to the original purchase price. The indebtedness is
secured by a debenture covering a fixed and floating charge over Cougar's
interest in the acquired properties.
 
 During
the year, non cash interest of $73,983 was recorded as interest expense in
relation to the discount on the Trout
Core indebtedness.
  58
  11. ASSET
RETIREMENT OBLIGATIONS
 
 Changes
in the carrying amounts of the asset retirement obligations associated with the
Company’s oil and natural gas properties are as follows:
 
 Asset
      retirement obligations, December 31, 2007
              
              
              151,814Obligations
      incurred
              
              
              62,642Accretion
              
              
              14,044Retirements
              
              
              (28,926
              )Asset
      retirement obligations, December 31, 2008
              
              
              199,574Obligations
      incurred
              
              
              1,022,582Accretion
              
              
              32,960Retirements
              
              
              (2,276
              )Foreign
      Exchange Gain (Loss)
              
              
              32,774Asset
      retirement obligations, December 31, 2009
              
              $
              1,285,614
  At
December 31, 2009, the estimated total undiscounted amount required to settle
the asset retirement obligations was $3,033,143 (2008 - $302,273). These
obligations will be settled at the end of the useful lives of the underlying
assets, which currently extends up to 8 years into the future. This amount has
been discounted using a credit adjusted risk-free interest rate of 7.5% and a
rate of inflation of 2.5%.
  12.
INCOME TAXES
 
 As at
December 31, 2009, the Company's deferred tax asset is attributable to its net
operating loss carry forward of approximately $3,357,000 (2008 - $2,802,000;
2007 - $2,000,000), which will expire if not utilized in the years 2024, 2025,
2026, 2027, 2028 and 2029. As reflected below, this benefit has been fully
offset by a valuation allowance based on management's determination that it is
not more likely than not that some or all of this benefit will be
realized.
 
 For the
years ended December 31, 2009, 2008, and 2007, a reconciliation of income tax
benefit at the U.S. federal statutory rate to income tax benefit at the
Company's effective tax rates is as follows.
 
 2009
              
              
              2008
              
              
              2007
      (Restated)Income
      tax benefit at statutory rate
              
              $
              7,563,000
              
              
              $
              1,156,000
              
              
              $
              944,000Permanent
      Differences
              
              
              -
              
              
              
              (4,000
              )
              
              
              2,000State
      tax benefit, net of federal tax
              
              
              -
              
              
              
              -
              
              
              
              48,000Foreign
      taxes, net of federal benefit
              
              
              -
              
              
              
              (2,224,000
              )
              
              
              (323,000
              )Revision
      to tax account estimates
              
              
              -
              
              
              
              (177,000
              )
              
              
              -Previously
      unrecognized tax asset
              
              
              -
              
              
              
              -
              
              
              
              308,000Other
              
              
              (2,000
              )
              
              
              (2,000
              )
              
              
              -Change
      in valuation allowance
              
              
              (7,268,000
              )
              
              
              1,251,000
              
              
              
              (979,000
              )Deferred
      tax asset before the following
              
              
              -
              
              
              
              -
              
              
              
              -Deferred
      tax credit arising from flow-through share premiums
              
              
              -
              
              
              
              978,835
              
              
              
              147,000Deferred
      Tax Recovery
              
              
              -
              
              
              
              978,835
              
              
              
              147,000
  59
 
 Deferred
tax assets (liabilities) at December 31, 2009 and 2008 are comprised of the
following:
 
 2009
              
              
              2008Deferred
      tax assetsCapital
      assets
              
              $
              1,428,000
              
              
              $
              -Net
      operating loss carryover
              
              
              7,286,000
              
              
              
              2,802,000Asset
      retirement obligations
              
              
              -
              
              
              
              -Other
              
              
              -
              
              
              
              75,000Total
      deferred tax asset
              
              
              8,714,000
              
              
              
              2,877,000Deferred
      Tax liabilitiesCapital
      assets
              
              
              -
              
              
              
              345,000Net
      deferred tax asset before valuation allowance
              
              
              8,714,000
              
              
              
              2,532,000Less
      valuation allowance
              
              
              (8,714,000
              )
              
              
              (2,532,000
              )Net
      deferred tax asset
              
              $
              -
              
              
              $
              -
  The
valuation allowance of $8,714,000 (2008 - $2,532,000) includes $1,806,000 (2008
- $1,690,000) relating to year end currency revaluation adjustments that have
not been charged to expense but are included in comprehensive loss in
shareholders’ equity.
  Accounting for uncertainty
for Income Tax
 
 Effective January 1, 2009,
we adopted the interpretation for accounting for uncertainty in income taxes
which was an interpretation of the accounting standard accounting for income
taxes. This interpretation created a single model to address accounting for
uncertainty in tax positions. This interpretation clarifies the accounting for
income taxes, by prescribing a minimum recognition threshold a tax position is
required to meet before being recognized in the financial
statements.
 
 We or one
of our subsidiaries files income tax returns in the U.S. federal jurisdiction,
and various states and foreign jurisdictions. With few exceptions, we are no
longer subject to U.S. federal, state and local, or non-U.S. income tax
examinations by tax authorities for years prior to 2006. To date, the Internal
Revenue Service (“IRS”) has not performed an examination of our U.S. income tax
returns for 2006 through 2008.
 
 We do not
have any unrecognized tax benefits or loss contingencies.
 60
 
 13. STOCK OPTION PLAN AND
STOCK BASED COMPENSATION
 
 The
Company has a stock option plan under which it may grant options to its
directors, officers, employees and consultants for up to a maximum of 10% of its
issued and outstanding common shares at market price at the date of grant for up
to a maximum term of five years. Options are exercisable equally over the first
three years of the term of the option.
 
 A summary
of the status of our stock option plans as of December 31, 2009, 2008 and 2007
and changes during the years ending on those dates is presented below (shares in
thousands):
 
 Weighted
      average Exercise
              
              
              Weighted
      average Exercise
              
              
              Weighted
      average ExercisePrice
              
              
              Shares
              
              
              Price
              
              
              Shares
              
              
              Price
              
              
              SharesOutstanding
      at beginning of year
              
              $
              1.50
              
              
              
              1,796,666
              
              
              $
              1.62
              
              
              
              2,035,000
              
              
              $
              1.48
              
              
              
              1,125,000Options
      Granted
              
              
              0.29
              
              
              
              4,630,000
              
              
              
              0.92
              
              
              
              125,000
              
              
              
              1.80
              
              
              
              910,000Options
      cancelled
              
              
              1.61
              
              
              
              366,666
              
              
              
              1.99
              
              
              
              363,334
              
              
              
              -
              
              
              
              -Outstanding
      at end of year
              
              
              0.57
              
              
              
              6,060,000
              
              
              
              1.50
              
              
              
              1,796,666
              
              
              
              1.62
              
              
              
              2,035,000Exersicable
      at end of year
              
              $
              1.45
              
              
              
              1,303,333
              
              
              $
              1.52
              
              
              
              976,670
              
              
              $
              1.48
              
              
              
              375,000
 
 Significant
option groups outstanding at December 31, 2009 and related weighted average
price and life information follow:
 
 Outstanding
              
              
              ExerciseableRange
      of exercise Price
              
              
              Number
      outstanding at December 31, 2009
              
              
              Weighted
      Average remaining Contracual life
              
              
              Weighted
      average Exercsie Price
              
              
              Aggregate
      intrinsic value
              
              
              Number
      Exersiceable at December 31, 2009
              
              
              Weighted
      average Exercise price
              
              
              Aggregate
      Intrinsic Value0.28-1.28
              
              
              
              4,855,000
              
              
              
              4.38
              
              
              
              0.32
              
              
              
              -
              
              
              
              225,000
              
              
              
              1.02
              
              
              
              -1.29-2.28
              
              
              
              1,105,000
              
              
              
              1.89
              
              
              
              1.45
              
              
              
              -
              
              
              
              1,011,666
              
              
              
              1.47
              
              
              
              -2.29-3.28
              
              
              
              100,000
              
              
              
              2.92
              
              
              
              2.58
              
              
              
              -
              
              
              
              66,667
              
              
              
              2.58
              
              
              
              -
  The
Black-Scholes option pricing model was developed for use in estimating the value
of traded options. Option pricing models require the input of highly subjective
assumptions, including the expected stock price volatility and expected life.
The expected volatility is based on historical volatilities of our stock.
Historical data is used to estimate option exercise and employee termination
within the valuation model. The expected term of options granted is derived from
the output of the option valuation model and represents the period of time that
options are expected to be outstanding. The risk-free rate for the periods
within the contractual life of the option is based on the U.S. Treasury yield
curve in effect at the time of grant.
  For
      options granted during
              
              2009
              
              
              2008
              
              
              2007Weighted
      average fair value
              
              $
              0.23
              
              
              $
              0.46
              
              
              $
              1.34Weighted
      average expected life
              
              
              4.94
              
              
              
              3.00
              
              
              
              5.00Valuation
      assumptions:Expected
      Volitility
              
              
              100
              %
              
              
              75
              %
              
              
              75
              %Risk
      - free interest rate
              
              
              1.89-2.68
              
              
              
              2.96-3.05
              
              
              
              3.65-4.57Expected
      dividend yield
              
              
              0
              
              
              
              0
              
              
              
              0Expected
      annual forfeitures
              
              Nil
              
              
              Nil
              
              
              Nil
  61
  A summary
of options granted and outstanding under the plan is presented
below.
  Nonvested
      Options
              
              
              Weighted-Average
      Grant Date Fair ValueNonvested
      at December 31,2008
              
              
              1,660,000
              
              
              
              1.11Granted
              
              
              125,000
              
              
              
              0.46Vested
              
              
              (601,671
              )
              
              
              1.08Forfeited
              
              
              (363,333
              )
              
              
              1.31Nonvested
      at January 1, 2009
              
              
              819,996
              
              
              
              0.96Granted
              
              
              4,630,000
              
              
              
              0.23Vested
              
              
              (559,996
              )
              
              
              0.83Forfeited
              
              
              (133,333
              )
              
              
              1.16Nonvested
      at December 31, 2009
              
              
              4,756,667
              
              
              
              0.25
 
 
 Warrants
 
 During
years ended December 31, 2006, 2007, 2008 and 2009, the Company, as part of
certain private placement financings, issued warrants that are exercisable in
common shares of the Company. A summary of such outstanding warrants
follows:
 
 Exercise
      Price ($)
              
              Expiry
      Date
              
              Equivalent
      Shares Outstanding
              
              
              Weighted
      Average Years to ExpiryIssued
      June 30, 2006
              
              
              3.50
              
              Jun.
      30/11
              
              
              1,130,000
              
              
              
              1.50Issued
      June 18, 2008
              
              
              3.50
              
              Jun.
      18/10
              
              
              1,300,000
              
              
              
              0.50Balance
      December 31, 2009
              
              
              
              
              
              
              
              2,430,000
              
              
              
              1.04
 
 
 During
the twelve months ended December 31, 2009, warrants exercisable into 3,693,014
common shares of the Company expired unexercised.
 
 In
accordance with FASB ASC 718, the Company uses the Black-Scholes option pricing
method to determine the fair value of each warrant granted and the amount is
recognized as additional expense in the statement of earnings over the vesting
period of the warrants. The fair value of each warrants granted has been
estimated using the following average assumptions:
 
 2009
              2008Risk
      free interest rate
              1.89-2.57
      %
              2.96-3.05%Expected
      holding period
              3
      Years
              3
      YearsShare
      price volatility
              100%
              75%Estimated
      annual common share dividend
              -
              -
  Cougar
Stock Option Plan
  Cougar
has a stock option plan under which it may grant options to its directors,
officers, employees and consultants for up to a maximum of 10% of its issued and
outstanding common shares at market price at the date of grant for up to a
maximum term of five years. Options are exercisable equally over the first three
years of the term of the option.
  62
  A summary
of options granted and outstanding under the plan is as follows:
  2009
              
              
              2008
              
              
              2007Weighted
      average Exercise
              
              
              Weighted
      average Exercise
              
              
              Weighted
      average ExercisePrice
              
              
              Shares
              
              
              Price
              
              
              Shares
              
              
              Price
              
              
              SharesOutstanding
      at beginning of year
              
              $
              -
              
              
              
              -
              
              
              $
              -
              
              
              
              -
              
              
              $
              -
              
              
              
              -Options
      Granted
              
              
              0.72
              
              
              
              850,000
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Options
      cancelled
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Outstanding
      at end of year
              
              
              0.72
              
              
              
              850,000
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Exersicable
      at end of year
              
              $
              0.72
              
              
              
              850,000
              
              
              $
              -
              
              
              
              -
              
              
              $
              -
              
              
              
              -
   Outstanding
              
              ExerciseableRange
      of exersise Price
              Number
      outstanding at December 31, 2009
              Weighted
      Average remaining Contracual life
              Weighted
      average Exercsie Price
              Aggregate
      intrensic value
              
              Number
      Exersiceable at December 31, 2009
              Weighted
      average Exercise price
              Aggregate
      Intrensic Value0.65
              750,000
              4.04
              0.65
              -
              
              -
              -
              -1.30
              100,000
              4.83
              1.30
              -
              
              -
              -
              -
   Nonvested
      Options
              
              
              Weighted-Average
      Grant Date Fair ValueNonvested
      at January 1, 2009
              
              
              -
              
              
              
              -Granted
              
              
              850,000
              
              
              $
              0.72Vested
              
              
              -
              
              
              
              -Forfeited
              
              
              -
              
              
              
              -Nonvested
      at December 31, 2009
              
              
              850,000
              
              
              $
              072
  Cougar
warrants
  During
2009 Cougar issued 893,000 warrants in conjunction with various private
placement made during the year.  The exercise price and expiry dates are
disclosed in the tables below.
  Exercise
      Price ($)
                  Expiry
      Date
                  Equivalent
      Shares Outstanding
                  Weighted
      Average Years to ExpiryIssued
      Jan 12, 2009
                  1.30
                  Jan
      12/11
                  126,923
                  1.03Issued
      Feb 12, 2009
                  1.30
                  Feb
      12/11
                  157,000
                  1.12Issued
      Feb 12, 2009
                  2.60
                  Feb
      12/11
                  145,415
                  1.12Issued
      Feb 27,2009
                  2.60
                  Feb
      27/11
                  38,462
                  1.16Issued
      Mar 25, 2009
                  2.60
                  Mar
      4/11
                  13,846
                  1.17Issued
      Mar 25, 2009
                  2.60
                  Mar
      23/11
                  7,692
                  1.22Issued
      Mar 25, 2009
                  1.30
                  Mar
      4/11
                  76,923
                  1.17Issued
      Apr 27, 2009
                  2.60
                  Apr
      27/11
                  1,000
                  1.32Issued
      June 1, 2009
                  2.60
                  Jun
      1/11
                  325,739
                  1.42Balance
      December 31, 2009
                  
                  
                  893,000
                  1.22
  63
  14.
              NON
      CONTROLLING INTEREST
 
 Following
is a summary of the interest of the non controlling shareholders of
Cougar:
 
 Net
      Income Attributable to the Company's transfers (to) from Non contolling
      interest for the year ended December 31, 2009Net
      loss attributable to Kodiak
              
              
              (19,573,082
              )Transfer
      (to) from the non-controlling interestIncrease
      in Kodiak's paid-in capital for sale of 556,261 Cougar common shares to a
      third party.
              
              
              101,764Increase
      in Kodiak's paid-in capital for sale of 19,046 Cougar common shares to a
      third party.
              
              
              13,521Increase
      in Kodiak's paid-in capital for sale of 962,693 Cougar common shares to a
      third party.
              
              
              511,664Net
      transfers (to) from noncontrolling interest
              
              
              626,949Net
      Loss attributable to the Company and transfers from (to) noncontrolling
      interest
              
              
              (18,946,133
              )
  64
 
 15.
              LOSS
      PER SHARE
 
 A
reconciliation of the numerator and denominator of basic and diluted loss per
share is provided as follows:
 
 Years
      ended December 31,
              
              2009
              
              
              2008
              
              
              2007Numerator:Numerator
      for basic and diluted loss per share.Net
      loss
              
              $
              19,573,082
              
              
              $
              2,074,649
              
              
              $
              2,571,663Denominator:Denominator
      for basic  and diluted loss per shareWeighted
      average shares outstanding
              
              
              110,121,632
              
              
              
              108,323,376
              
              
              
              95,850,148Basic
      and diluted loss per share
              
              $
              0.18
              
              
              $
              0.02
              
              
              $
              0.03
  Basic
loss per share is based on the weighted average number of shares outstanding
during the periods. Diluted loss is per share is based on the weighted average
number of shares and all dilutive potential shares outstanding during the
periods. The Company had outstanding stock options and warrants as at 31
December, 2009, 2008 and 2007, as disclosed in note 13, that were antidilutive
due to the net loss of those periods.
  16.
COMMITMENTS AND CONTINGENCIES
 
 Lease
Commitments
 
 As of
December 31, 2009 and 2008, the Company had lease commitments for vehicles,
office rent and office equipment.  The following lease commitments for
the years shown:
  2009
              
              
              2008Amounts
      payable in:2009
              
              $
              -
              
              
              $
              -2010
              
              
              150,816
              
              
              
              26,0992011
              
              
              166,642
              
              
              
              23,8562012
              
              
              162,337
              
              
              
              3,1722013
              
              $
              39,797
              
              
              $
              -
 
 17.
FINANCIAL INSTRUMENTS
 
 The
Company, as part of its operations, carries a number of financial instruments.
It is management’s opinion that the Company is not exposed to significant
interest, credit or currency risks arising from these financial instruments
except as otherwise disclosed.
 
 The
Company’s financial instruments, including cash and short term deposits,
accounts receivable, accounts payable and accrued liabilities are carried at
values that approximate their fair values due to their relatively short maturity
periods.
  65
 
 18.
RELATED PARTY TRANSACTIONS
  For
the twelve months ended December 31, 2009, the Company paid $73,245 (2008 -
$Nil) to Sicamous Oil & Gas Consultants Ltd. (“Sicamous”), a company
controlled by the CEO, President and COO of the Company for consulting services
rendered by him. Of this amount, $27,727 was payable as at December 31, 2009
(2008 - $ Nil). These amounts were charged to General and Administrative
Expense.
 
 For the
twelve months ended December 31, 2009, the Company paid $24,107 (2008 –
$113,481), to Harbour Oilfield Consulting Ltd., a company owned by the
Vice-President Operations of the Company for consulting services. Of this
amount, $6,910 (2008 - $ 39,394) was capitalized to Unproved Oil and Gas
Properties and $17,197 (2008 - $49,041) was charged to General and
Administrative Expense. Of this amount, $13,115 was payable as at December 31,
2009 (2008 – $ Nil).
 
 For the
twelve months ended December 31, 2009, the Company paid $124,353 (2008 -
$171,376) to the Chief Financial Officer. Of this amount, $20,846 was payable as
at December 31, 2009 (2008 - Nil). These amounts were charged to General and
Administrative Expense.
 
 These
related party transactions were non arm's length transactions in the normal
course of business and agreed to by the related parties and the Company based on
negotiations and Board approval and accordingly had been measured at the
exchange amounts.
 
 Note payable to related
party
 
 On
November 24, 2008 the Company borrowed Cdn. $40,000 from Sicamous under the
terms of a demand note bearing interest at the Royal Bank of Canada prime rate
plus 1% per annum. Following is a summary of transactions regarding this related
party indebtedness:
 Advance
      received, November 2008 (Cdn. $40,000)
              
              
              37,915Currency
      revaluation adjustment December 31, 2008
              
              
              5,074Balance
      December 31, 2008 (Cdn $ 40,000)
              
              
              32,841Repayment,
      January 2009 (Cdn. $20,000)
              
              
              (15,857
              )Advance
      March, 2009 (Cdn. $3,000)
              
              
              2,378Repayment
      June, 2009 (Cdn. $23,000)
              
              
              (19,362
              )Balance,
      December 31, 2009
              
              $
      Nil
  19.
SEGMENTED INFORMATION
 
 The
Company’s two geographical segments are the United States and Canada. Both
segments use accounting policies that are identical to those used in the
consolidated financial statements. The Company’s geographical segmented
information is as follows:
 
 Year
      Ended December 31, 2009U.
      S.
              
              
              Canada
              
              
              TotalRevenue,
      net of Royalites
              
              
              -
              
              
              
              607,469
              
              
              
              607,469Net
      Loss
              
              
              36,715
              
              
              
              19,536,367
              
              
              
              19,573,082Capital
      Assets
              
              
              11,274,809
              
              
              
              19,529,242
              
              
              
              30,804,051Total
      Assets
              
              
              11,282,903
              
              
              
              20,374,656
              
              
              
              31,657,559Capital
      Expenditures
              
              
              24,221
              
              
              
              7,454,821
              
              
              
              7,479,042Year
      Ended December 31, 2008U.
      S.
              
              
              Canada
              
              
              TotalRevenue,
      net of Royalites
              
              $
              -
              
              
              $
              1,065
              
              
              $
              1,065Net
      Loss
              
              
              (490,044
              )
              
              
              (1,584,605
              )
              
              
              (2,074,649
              )Capital
      Assets
              
              
              11,250,589
              
              
              
              25,384,344
              
              
              
              36,634,932Total
      Assets
              
              
              9,861,161
              
              
              
              24,190,538
              
              
              
              37,171,397Capital
      Expenditures
              
              
              3,270,212
              
              
              
              11,159,779
              
              
              
              14,429,991Year
      Ended December 31, 2007U.
      S.
              
              
              Canada
              
              
              TotalRevenue,
      net of Royalites
              
              $
              -
              
              
              $
              225
              
              
              $
              225Net
      Loss
              
              
              (57,193
              )
              
              
              (2,514,470
              )
              
              
              (2,571,663
              )Capital
      Assets
              
              
              8,423,346
              
              
              
              19,119,659
              
              
              
              27,543,005Total
      Assets
              
              
              8,949,538
              
              
              
              29,241,230
              
              
              
              38,190,768Capital
      Expenditures
              
              
              7,858,511
              
              
              
              18,519,418
              
              
              
              26,377,929
  66
  20.
CHANGES IN NON-CASH WORKING CAPITAL
  2009
              
              
              2008
              
              
              2007Operating
      Activities:Accounts
      Receivable
              
              $
              (339,582
              )
              
              $
              620,554
              
              
              $
              (650,850
              )Prepaid
      Expenses and Deposits
              
              
              35,608
              
              
              
              (17,251
              )
              
              
              (49,613
              )Accounts
      Payable
              
              
              536,624
              
              
              
              147,886
              
              
              
              11,471Accrued
      Liabilities
              
              
              164,919
              
              
              
              20,848
              
              
              
              28,891Total
              
              $
              397,569
              
              
              $
              772,037
              
              
              $
              (660,101
              )Investing
      ActivitiesThe
      total changes in investing activities non-cash working capital accounts,
      which is detailed below, pertains to capital asset additions and has been
      included in that caption in the Statement of Cash Flow:Accounts
      Receivable
              
              $
              -
              
              
              $
              529,374
              
              
              $
              122,572Prepaid
      Expenses and Deposits
              
              
              (5,250
              )
              
              
              1,664
              
              
              
              155,976Accounts
      Payable
              
              
              282,139
              
              
              
              (638,152
              )
              
              
              867,152Accrued
      Liabilities
              
              
              -
              
              
              
              (433,288
              )
              
              
              232,542Total
              
              $
              276,889
              
              
              $
              (540,402
              )
              
              $
              1,378,242Financing
      ActivitiesThe
      total changes in financing activities non-cash working capital accounts,
      which is detailed below, pertains to shares issued and issuable and has
      been included in that caption in the Statement of Cash
    Flow:Deposits
      and Prepaids
              
              
              (32,841
              )
              
              
              -
              
              
              
              -Accounts
      Payable
              
              
              430,946
              
              
              
              (72,417
              )
              
              
              83,396Accrued
      Liabilities
              
              
              -
              
              
              
              (220,000
              )
              
              
              220,000Note
      Payable to Related Party
              
              
              -
              
              
              
              32,841
              
              
              
              -Flow-through
      Share Premium Liabilty
              
              
              -
              
              
              
              -
              
              
              
              1,125,835Total
              
              $
              398,105
              
              
              $
              (259,576
              )
              
              $
              1,429,231
  21.
SUBSEQUENT EVENTS
 
 On
January 25, 2010 the Company sold its interest in Cougar to Ore-More Resources
Inc (“Ore-More”) in exchange for shares. This transaction effected the
cancellation of certain indebtedness of the Company, which Ore More recently
acquired from Zentrum and also resulted in the disposition of the
non-controlling interest in Cougar and the acquisition of the controlling
interest of Ore More.  Following the closing of the transaction,
Ore-More changed its name to Cougar Oil and Gas Canada.
  On
February 26, 2010, Cougar Oil and Gas Canada closed a formal agreement (the
"Agreement") with a Canadian bank for two credit facilities. The first credit
facility is a revolving demand loan in the amount of Cdn$1,000,000 at a per
annum rate of prime interest plus 3.5%. The second credit facility is a
non-revolving acquisition/development demand loan bearing an annual per annum
interest rate of prime plus 3.0%. Under the terms of the Agreement, the two
credit facilities are committed for the development of existing proved
non-producing /undeveloped petroleum and natural gas reserves.


67





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





None.





ITEM
9A. CONTROLS AND PROCEDURES





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





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





MANAGEMENT’S REPORT ON INTERNAL
CONTROL OVER FINANCIAL REPORTING





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





SEGREGATION
OF DUTIES AND ACCESS TO CRITICAL ACCOUNTING SYSTEMS





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





REMEDIATION
OF MATERIAL WEAKNESS IN INTERNAL CONTROL





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


68





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





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





CHANGES
IN INTERNAL CONTROL OVER FINANCIAL REPORTING





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





ITEM
9B. OTHER INFORMATION





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





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





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





The primary reasons for the voluntary
delisting request were:





1.
            Since
      the Company’s TSX-V listing effective December 24, 2007 to market close on
      October 30, 2009, liquidity analysis revealed an average daily
      trading volume of 270,413 shares on the OTCBB and 14,022 on the TSX-V for
      the period – a difference in trading volume and liquidity of over 19
      times.





2.
            Following
      the initial Canadian based financing associated with the TSX-V listing,
      the Company has repeatedly experienced little to no investment interest or
      support from the Canadian financial community consisting of investment
      banks, capital markets and retail brokerage firms, and private equity
      firms.  The primary source of equity financing has been from
      Europe over the last 18 months, and we do not expect that to change in the
      foreseeable future. Our European investors have a stated preference for
      the OTCBB listing versus the TSX-V, of which the latter listing they do
      not follow.


69


3.
            The
      Company’s Board of Directors believes that voluntarily delisting from the
      TSX-V and focusing on U.S. and European markets is in the best interests
      of our shareholders.  This will eliminate the substantial
      cross-border financing and reporting
issues.





4.
            As
      of October 31, 2009, the Company’s transfer agent, Computershare, revealed
      the shareholder geographic position of all foreign based shareholders at
      61.54% and Canadian based shareholders at 38.46%, of which the vast
      majority of the latter is founder shareholdings and only a nominal amount
      in the Canadian float.  As a result, the OTCBB quotation system
      serves shareholders of the majority of Kodiak’s shares, where the
      Company’s stock has been trading since December 27,
  2004.





5.
            The
      internal and external compliance costs to maintain the listing of the
      Company’s shares on the TSX-V are relatively significant to a company of
      this size, which has not resulted in an additional benefit for
      shareholders in view of the low trading volume on the
    TSX-V.





6.
            The
      Financial Industry Regulatory Authority (FINRA) is the largest independent
      regulator for securities firms in the United States and is responsible for
      establishing rules governing its broker/dealer members, including OTCBB
      subscribing members, on conduct, qualification standards, examinations,
      investigations, violations, and investor and member inquiries – thus,
      there is a previous and demonstrated, current market for Kodiak
      shareholders.





Other
factors:





7.
            To
      maintain quotation eligibility on the OTCBB, Kodiak Energy, Inc. is
      required to file periodic financial information with the U.S. Securities
      and Exchange Commission (SEC).  All of the Company’s filings are
      located under the “Kodiak Energy, Inc.” profile on the Electronic Data
      Gathering, Analysis, and Retrieval (EDGAR) system through the U.S. SEC
      website at http://www.sec.gov.





8.
            Kodiak
      intends on maintaining its “foreign reporting issuer status” with the
      Alberta Securities Commission.





9.
            Kodiak
      was Sarbanes Oxley (SOX) compliant for 2008, is a fully reporting filer,
      and adheres to the security laws, rules, regulations and filing
      requirements of the U.S. SEC.





PART
III





ITEM
10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE





DIRECTORS
AND EXECUTIVE OFFICERS





Name
            
            Age
            
            TitleWilliam
      Tighe
            
            59
            
            Chairman
      of the Board, CEO, COO and PresidentGlenn
      Watt
            
            36
            
            Vice
      President Operations and DirectorLeslie
      Owens
            
            46
            
            DirectorGordon
      Taylor
            
            62
            
            DirectorGreg
      Juneau
            
            43
            
            DirectorWilliam
      Brimacombe
            
            67
            
            DirectorDavid
      Wilson
            
            47
            
            Chief
      Financial Officer, Vice President,
Finance





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


70





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





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





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





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


71





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





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





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





COMPLIANCE
WITH SECTION 16(A) OF THE EXCHANGE ACT





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





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





AUDIT
COMMITTEE AND FINANCIAL EXPERT





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




The Audit Committee is directly
responsible for the appointment, compensation, retention and oversight of
Kodiak’s independent registered accounting firm. The Audit Committee, among
other things, also reviews and discusses Kodiak’s audited financial statements
with management.
 
 Our Audit Committee is comprised of
three directors:  Gordon Taylor, Leslie Owens and Greg Juneau, who are
independent.




72




CODE
OF ETHICS





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





1.
            Honest
      and ethical conduct, including the ethical handling of actual or apparent
      conflicts of interest between personal and professional
      relationships.




2.
            Full,
      fair, accurate, timely and understandable disclosure in reports and
      documents that are filed with, or submitted to the Securities and Exchange
      Commission and in other public communications made by the
      Company.




3.
            Compliance
      with applicable government laws, rules and
  regulations.




4.
            The
      prompt internal reporting of violations of the code to an appropriate
      person or persons identified in the
code.




5.
            Accountability
      for adherence to the code.





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





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





ITEM
11. EXECUTIVE COMPENSATION





COMPENSATION
OF EXECUTIVE OFFICERS





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




73




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








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


74


COMPENSATION
DISCUSSION AND ANALYSIS
 
 Overview
of Compensation Program and Philosophy




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





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





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





Compensation
of Directors





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





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


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


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


DIRECTOR
COMPENSATION TABLE





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





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





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





SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT





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


75





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





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





DIRECTOR
INDEPENDENCE





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





RELATED
TRANSACTIONS





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





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





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





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





76




ITEM
14. PRINCIPAL ACCOUNTANTING FEES AND SERVICES





AUDIT
FEES





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





AUDIT-RELATED
FEES





None





TAX
FEES





None





ALL
OTHER FEES





None





AUDIT
COMMITTEE POLICIES AND PROCEDURES





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





PART
IV





ITEM
15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES





(a)
            Exhibits







23.1
            Consent
      of Meyers Norris Penny LLP





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





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





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





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


77





SIGNATURES





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





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





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





/s/ William
Tighe


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


(Principal
Executive Officer





/s/ Dave
Wilson


Dave
Wilson, Chief Financial Officer


(Principal
Financial and Accounting Officer)





/s/ Glenn
Watt


Glenn
Watt, Vice President Operations and Director





/s/ Gordon
Taylor


Gordon
Taylor, Director





/s/ Gregory
Juneau


Gregory
Juneau, Director





/s/ Leslie R.
Owens


Leslie
R. Owens, Director





/s/ William E.
Brimacombe


William
E. Brimacombe, Director




78