UNITED STATES
 SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549
  FORM 20-F
 
  ̈
REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934
 OR
 x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 For fiscal year ended December 31, 2010
 OR
  ̈
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 For the transition period from ______ to ______
 OR
  ̈
SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 Date of event requiring this shell company report:
 
 Commission file number: 001-33491
 
 DEJOUR ENERGY INC.
 (Exact name of Registrant as specified in its charter)
 
 Province of British Columbia, Canada
 (Jurisdiction of incorporation or organization)
 
 598 - 999 Canada Place
 Vancouver, British Columbia
 (Address of principal executive offices)
 
 Mathew Wong
 598 - 999 Canada Place
 Vancouver, British Columbia
 Tel: (604) 638-5050
 Facsimile: (604) 638-5051
 (Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)
 Securities registered pursuant to Section 12(b) of the Act:
 Title of Each Class

Name of each exchange on which registeredCommon Shares, without par value

NYSE Amex Equities
 Securities registered pursuant to Section 12(g) of the Act: None
 Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None
 
 Indicate the number of outstanding shares of each of the Registrant’s classes of capital or common stock as of the close of the period covered by the annual report: 110,180,545 common shares as at December 31, 2010
 
 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  ̈No x
 
 If this report is an annual or transition report, indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes  ̈No x
 
 Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes xNo  ̈
 
 Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during thepreceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes  ̈No  ̈
 
 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. (Check one)
 
 Large accelerated filer  ̈
Accelerated filer  ̈
Non-accelerated filer x
 
 Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
 
 U.S. GAAP  ̈
International Reporting Standards as issued
 ̈
Other xby the International Accounting Standards Board
 
 If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow:
 
 Item 17  ̈Item 18 x
 
 If this is an annual report, indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  ̈ No x
  
  TABLE OF CONTENTS
  GENERAL INFORMATION
1CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
1CURRENCY AND EXCHANGE RATES
3ABBREVIATIONS
4PART I
5ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS.
5ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE.
5ITEM 3. KEY INFORMATION.
5ITEM 4. INFORMATION ON THE COMPANY
16ITEM 4A. UNRESOLVED STAFF COMMENTS
38ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
38ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES.
48ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS.
64ITEM 8. FINANCIAL INFORMATION.
68ITEM 9. THE OFFER AND LISTING
68ITEM 10. ADDITIONAL INFORMATION
71ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
87ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
89PART II
90ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
90ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS
90ITEM 15. CONTROLS AND PROCEDURES
90ITEM 16. [RESERVED]
91ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT
91ITEM 16B. CODE OF ETHICS
91ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES
92ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES
92ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS
92ITEM 16F. CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT
92ITEM 16G. CORPORATE GOVERNANCE
93PART III
94ITEM 17. FINANCIAL STATEMENTS
94ITEM 18. FINANCIAL STATEMENTS
94ITEM 19. EXHIBITS
95SIGNATURES
97
  
  GENERAL INFORMATION
 
 All references in this annual report on Form 20-F to the terms “we”, “our”, “us”, “the Company” and “Dejour” refer to Dejour Energy Ltd.
  CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
 
 This annual report on Form 20-F and the documents incorporated herein by reference contain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements concern our anticipated results and developments in the our operations in future periods, planned exploration and, if warranted, development of our properties, plans related to our business and other matters that may occur in the future. These statements relate to analyses and other information that are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management.
 
 Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as “expects” or “does not expect”, “is expected”, “anticipates” or “does not anticipate”, “plans”, “estimates” or “intends”, or stating that certain actions, events or results “may”, “could”, “would”, “might” or “will” be taken, occur or be achieved) are not statements of historical fact and may be forward-looking statements. The forward-looking statements contained in this annual report on Form 20-F concern, among other things:
 
 ·
drilling inventory, drilling plans and timing of drilling, re-completion and tie-in of wells;
  ·
productive capacity of wells, anticipated or expected production rates and anticipated dates of commencement of production;
  ·
drilling, completion and facilities costs;
  ·
results of our various projects;
  ·
ability to lower cost structure in certain of our projects;
  ·
our growth expectations;
  ·
timing of development of undeveloped reserves;
  ·
the performance and characteristics of the Company’s oil and natural gas properties;
  ·
oil and natural gas production levels;
  ·
the quantity of oil and natural gas reserves;
  ·
capital expenditure programs;
  ·
supply and demand for oil and natural gas and commodity prices;
  ·
the impact of federal, provincial, and state governmental regulation on Dejour;
  ·
expected levels of royalty rates, operating costs, general administrative costs, costs of services and other costs and expenses;
  ·
expectations regarding our ability to raise capital and to continually add to reserves through acquisitions, exploration and development;
  ·
treatment under governmental regulatory regimes and tax laws; and
  ·
realization of the anticipated benefits of acquisitions and dispositions.
  These statements relate to analyses and other information that are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of our management.
  1
 
 Forward-looking statements are subject to a variety of known and unknown risks, uncertainties and other factors that could cause actual events or results to differ from those expressed or implied by the forward-looking statements, including, without limitation:
 
 ·
risks related to the marketability and price of oil and natural gas being affected by factors outside our control;
  ·
risks related to world oil and natural gas prices being quoted in U.S. dollars and our production revenues being adversely affected by an appreciation in the Canadian dollar;
  ·
risks related to our ability to execute projects being dependent on factors outside our control;
  ·
risks related to oil and gas exploration having a high degree of risk and exploration efforts failing;
  ·
risks related to cumulative unsuccessful exploration efforts;
  ·
risks related to oil and natural gas operations involving hazards and operational risks;
  ·
risks related to seasonal factors and unexpected weather;
  ·
risks related to competition in the oil and gas industry;
  ·
risks related to the fact that we do not control all of the assets that are used in the operation of our business;
  ·
risks related to our ability to market oil and natural gas depending on its ability to transport the product to market;
  ·
risks related to high demand for drilling equipment;
  ·
risks related to title to our properties;
  ·
risks related to our ability to continue to meet its oil and gas lease or license obligations;
  ·
risks related to our anticipated substantial capital needs for future acquisitions;
  ·
risks related to our cash flow from reserves not being sufficient to fund its ongoing operations;
  ·
risks related to covenants in issued debt restricting the ability to conduct future financings;
  ·
risks related to our being exposed to third party credit risks;
  ·
risks related to our being able to find, acquire, develop and commercially produce oil and natural gas;
  ·
risks related to our properties not producing as projected;
  ·
risks related to our estimated reserves being based upon estimates;
  ·
risks related to future oil and gas revenues not resulting in revenue increases;
  ·
risks related to our managing growth;
  ·
risks related to our being dependent on key personnel;
  ·
risks related to our operations being subject to federal, state, local and other laws, controls and regulations;
  ·
risks related to uncertainty regarding claims of title and right of aboriginal people;
  ·
risks related to environmental laws and regulations;
  ·
risks related to our facilities, operations and activities emitting greenhouse gases;
  ·
risks related to our not having paid dividends to date;
  ·
risks related to our stock price being volatile; and
  ·
risks related to our being a foreign private issuer.
  2
 
 This list is not exhaustive of the factors that may affect any of our forward-looking statements. Some of the important risks and uncertainties that could affect forward-looking statements are described further under the section heading “Item 3. Key Information – D. Risk Factors” below. If one or more of these risks or uncertainties materializes, or if underlying assumptions prove incorrect, our actual results may vary materially from those expected, estimated or projected. Forward-looking statements in this document are not a prediction of future events or circumstances, and those future events or circumstances may not occur. Given these uncertainties, users of the information included herein, including investors and prospective investors are cautioned not to place undue reliance on such forward-looking statements. Investors should consult our quarterly and annual filings with Canadian and U.S. securities commissions for additional information on risks and uncertainties relating to forward-looking statements. We do not assume responsibility for the accuracy and completeness of these statements.
 
 Forward-looking statements are based on our beliefs, opinions and expectations at the time they are made, and we do not assume any obligation to update our forward-looking statements if those beliefs, opinions, or expectations, or other circumstances, should change, except as required by applicable law.
 
 We qualify all the forward-looking statements contained in this annual report on Form 20-F by the foregoing cautionary statements.
  CURRENCY AND EXCHANGE RATES
 
 Canadian Dollars Per U.S. Dollar
 
 Unless otherwise indicated, all references in this annual report are to Canadian dollars ("$" or "Cdn$").
 
 The following tables set forth the number of Canadian dollars required to buy one United States dollar (US$) based on the average, high and low nominal noon exchange rate as reported by the Bank of Canada for each of the last five fiscal years and each of the last six months.  The average rate means the average of the exchange rates on the last day of each month during the period.
 
 Canadian Dollars Per One U.S. Dollar2010


2009


2008


2007


2006


2005Average for the period


1.0345



1.1416



1.0592



1.0697



1.1338



1.2108
 
 May

2011


April

2011


March

2011


February

2011


January

2011


December

2010High for the period


0.9809



0.9450



0.9671



0.9710



0.9848



0.9931Low for the period


0.9490



0.9722



0.9974



0.9984



1.0060



1.0216
  Exchange rates are based on the Bank of Canada nominal noon exchange rates. The nominal noon exchange rate on June 21, 2011 as reported by the Bank of Canada for the conversion of United States dollars into Canadian dollars was US$1.00 = Cdn$0.9724.
  3
  ABBREVIATIONS
 
 Oil and Natural Gas Liquids

Natural Gasbbl
barrel

Mcf
thousand cubic feetbbls
barrels

MCFD
thousand cubic feet per dayBOPD
barrels per day

MMcf
million cubic feetMbbls
thousand barrels

MMcf/d
million cubic feet per dayMmbtu
million British thermal units

Mcfe
Thousand cubic feet of gas equivalent  OtherAECO
Intra-Alberta Nova Inventory Transfer Price (NIT net price of natural gas).BOE
Barrels of oil equivalent. A barrel of oil equivalent is determined by converting a volume of natural gas to barrels using the ratio of 6 Mcf to one barrel.BOE/D
Barrels of oil equivalent per day.BCFE
Billion cubic feet equivalentMBOE
Thousand barrels of oil equivalent.NYMEX
New York Mercantile Exchange.WTI
West Texas Intermediate, the reference price paid in U.S. dollars at Cushing Oklahoma for crude oil of standard grade.
  4
  PART I
  ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS.
 
 Not applicable.
 
 ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE.
 
 Not applicable.
 
 ITEM 3. KEY INFORMATION.
 
 A.           Selected Financial Data
 
 Our selected financial data and the information in the following table for the years ended December 31, 2006 - 2010 was derived from our audited consolidated financial statements. These audited consolidated financial statements have been audited by BDO Canada LLP, Chartered Accountants, for the year ended December 31, 2010, and Dale Matheson Carr-Hilton LaBonte LLP, Chartered Accountants, for the years ended December 31, 2006-2009. Certain prior years’ comparative figures have been reclassified, if necessary.
  The information in the following table should be read in conjunction with the information appearing under the heading “Item 5. Operating and Financial Review and Prospects” and our audited consolidated financial statements under the heading "Item 18. Financial Statements".
 
 The following table of selected financial data has been derived from financial statements prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”). Reference is made to Item 18: Note 21 of our audited consolidated financial statements as at December 31, 2010 and 2009 and for the years ended December 31, 2010, 2009 and 2008, included herein, for a discussion of the material measurement differences between Canadian GAAP and United States generally accepted accounting principles (“U.S. GAAP”), and their effect on our financial statements.
 
 We have not declared any dividends since incorporation and do not anticipate that we will do so in the foreseeable future.  Our present policy is to retain all available funds for use in our operations and the expansion of our business.
 
 Canadian Generally Accepted Accounting Principles (Cdn$ in 000, except per share data)
 
 Year Ended December 31,2010


2009


2008


2007


2006Revenue (Oil and natural gas)

$
8,086


$
6,471


$
5,766


Nil


NilNet Income (Loss) for the Year

$
(5,165
)

$
(12,807
)

$
(20,891
)

$
(26,810
)

$
23,888Basic Income (Loss) Per Share

$
(0.05
)

$
(0.16
)

$
(0.29
)

$
(0.40
)

$
0.45Dividends Per Share

Nil


Nil


Nil


Nil


NilWeighted Avg. Shares, basic (000)


99,789



78,926



72,211



66,588



52,564Weighted Avg. Shares, diluted (000)


99,789



78,926



72,211



66,588



56,558Year-end Shares (000)


110,181



95,791



73,652



70,128



60,900Working Capital

$
(1,984
)

$
(19,642
)

$
(12,712
)

$
11,335


$
11,769Resource Properties

$
40,271


$
41,758


$
57,684


$
35,411


$
25,880Long-term Investments


-



-


$
2,722


$
12,600


$
36,539Long-term Debt

$
573


$
2,594


$
3,446


Nil


$
2,852Capital Stock

$
75,575


$
72,560


$
64,939


$
61,394


$
48,671Retained Earnings (Deficit)

$
(44,551
)

$
(39,386
)

$
(26,579
)

$
(5,688
)

$
21,123Total Assets

$
46,355


$
45,886


$
62,643


$
63,143


$
80,678
  5
  Adjusted to United States Generally Accepted Accounting Principles
 
 Under U.S. GAAP the following financial information would be adjusted from Canadian GAAP, and certain prior years’ comparative figures have been reclassified or restated, if necessary.
 
 (Cdn$ in 000, except per share data)Year Ended December 31,2010


2009

(Restated)


2008


2007


2006Net Income (Loss ) for the Year

$
(3,887
)

$
(10,270
)

$
(34,181
)

$
(29,523
)

$
23,828Earnings (Loss) Per Share

$
(0.04
)

$
(0.13
)

$
(0.47
)

$
(0.44
)

$
0.45Resource Properties

$
31,240


$
31,041


$
44,232


$
34,783


$
25,252Retained Earnings (Deficit)

$
(58,673
)

$
(54,785
)

$
(44,515
)

$
(10,334
)

$
19,189Total Assets

$
37,324


$
35,169


$
49,192


$
62,515


$
80,050
 
 Exchange Rate History
 
 See the disclosure under the heading "Currency and Exchange Rates" above.
 
 Recently Adopted Accounting Policies and Future Accounting Pronouncements
 
 Canadian Pronouncements
 
 On January 1, 2010, we adopted the following Canadian Institute of Chartered Accountants (“CICA”) Handbook sections:
 
 ·
Business Combinations, Section 1582, which replaces the previous business combinations standard. The standard requires assets and liabilities acquired in a business combination, contingent consideration and certain acquired contingencies to be measured at their fair values as of the date of acquisition. In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination and included in the statement of operations. The adoption of this standard had no impact but will impact the accounting treatment of future business combinations entered into after January 1, 2010.
 
 ·
Consolidated Financial Statements, Section 1601, which, together with Section 1602 below, replace the former consolidated financial statements standard. Section 1601 establishes the requirements for the preparation of consolidated financial statements. The adoption of this standard had no impact on our consolidated financial statements.
 
 ·
Non-controlling Interests, Section 1602, which establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The standard requires a noncontrolling interest in a subsidiary to be classified as a separate component of equity. In addition, net earnings and components of other comprehensive income are attributed to both the parent and non-controlling interest. The adoption of this standard has had no impact on our consolidated financial statements.
 
 Future Accounting Pronouncements
 
 The following accounting pronouncements are applicable to the Company’s reporting periods commencing January 1, 2011:
  6
 
 In February 2008, the CICA’s Accounting Standards Board announced that Canadian publicly accountable enterprises will be required to adopt International Financial Reporting Standards (IFRS) effective January 1, 2011. As a result, we published our first consolidated financial statements, prepared in accordance with IFRS, for the quarter ended March 31, 2011. We also provided comparative data on an IFRS basis, including an opening balance sheet as at January 1, 2010.
  United States Pronouncements
 
 Effective January 1, 2009, the Company adopted EITF Issue No. 07-05, “Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock” (“EITF 07-05”). EITF 07-05 clarifies the determination of whether an instrument issued by an entity (or an embedded feature in the instrument) is indexed to an entity’s own stock, which would qualify as a scope exception under SFAS 133. Based on the Company’s analysis of the EITF 07-05 criteria, the Company determined that the foreign currency denominated warrants (“US dollar warrants”) issued in connection with private placement must be treated as derivative liabilities in the Company’s statement of financial position. Any issuance costs related to the US$ denominated warrants are expensed upon initial issuance.
 
 Prospectively, the US dollar warrants will be re-measured at each balance sheet date based on estimated fair value, and any resultant changes in fair value will be recorded as non-cash valuation adjustments as income or expense in the respective period.
  United States Future Accounting Pronouncements
 
 Effective January 1, 2011, the Company will be preparing consolidated financial statements in accordance with IFRS and a reconciliation to US GAAP will not be required. As a result, SAB Topic 11M, “Disclosure of the Impact that Recently Issued Accounting Standards Will Have on the Financial Statements of the Registrant When Adopted in a Future Period” was not provided for 2010.
  B.           Capitalization and Indebtedness
 
 Not Applicable.
 
 C.           Reasons for the Offer and Use of Proceeds
 
 Not Applicable.
 
 D.           Risk Factors
 
 An investment in a company engaged in oil and gas exploration involves an unusually high amount of risk, both unknown and known, present and potential, including, but not limited to the risks enumerated below.
  Our failure to successfully address the risks and uncertainties described below would have a material adverse effect on our business, financial condition and/or results of operations, and the trading price of our common stock may decline and investors may lose all or part of their investment.  We cannot assure you that we will successfully address these risks or other unknown risks that may affect our business.
  Risks related to commodity price fluctuations
  The marketability and price of oil and natural gas are affected by numerous factors outside of our control.  Material fluctuations in oil and natural gas prices could adversely affect our net production revenue and oil and natural gas operations.
  Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:
  ·
the domestic and foreign supply of and demand for oil and natural gas;
  7
  ·
the price and quantity of imports of crude oil and natural gas;
  ·
overall domestic and global economic conditions;
  ·
political and economic conditions in other oil and natural gas producing countries, including embargoes and continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
  ·
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
  ·
the level of consumer product demand;
  ·
weather conditions;
  ·
the impact of the U.S. dollar exchange rates on oil and natural gas prices; and
  ·
the price and availability of alternative fuels.
  Our ability to market our oil and natural gas depends upon our ability to acquire space on pipelines that deliver such commodities to commercial markets. We are also affected by deliverability uncertainties related to the proximity of our reserves to pipelines and processing and storage facilities and operational problems affecting such pipelines and facilities, as well as extensive governmental regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business.
  Both oil and natural gas prices are unstable and are subject to fluctuation. Any material decline in prices could result in a reduction of our net production revenue. The economics of producing from some wells may change as a result of lower prices, which could result in reduced production of oil or natural gas and a reduction in the volumes and net present value of our reserves. We might also elect not to produce from certain wells at lower prices. All of these factors could result in a material decrease in our net production revenue and a reduction in our oil and natural gas acquisition, development and exploration activities.
  Because world oil and natural gas prices are quoted in U.S. dollars, our production revenues could be adversely affected by an appreciation of the Canadian dollar.
  World oil and natural gas prices are quoted in U.S. dollars, and the price received by Canadian producers, including us, is therefore affected by the Canadian/U.S. dollar exchange rate, which will fluctuate over time. In recent years, the Canadian dollar has increased materially in value against the U.S. dollar, which may negatively affect our production revenues. Further material increases in the value of the Canadian dollar would exacerbate this potential negative effect and could have a material adverse effect on our financial condition and results of operations. An increase in the exchange rate for the Canadian dollar and future Canadian/U.S. exchange rates could also negatively affect the future value of our reserves as determined by independent petroleum reserve engineers.
  Risks related to operating an exploration, development and production company
  Our ability to execute projects will depend on certain factors outside of our control.  If we are unable to execute projects on time, on budget or at all, we may not be able to effectively market the oil and natural gas that we produce.
  We manage a variety of small and large projects in the conduct of our business. Our ability to execute projects and market oil and natural gas will depend upon numerous factors beyond our control, including:
  ·
the availability of adequate financing;
 ·
the availability of processing capacity;
 ·
the availability and proximity of pipeline capacity;
 ·
the availability of storage capacity;
  8
 
 ·
the supply of and demand for oil and natural gas;
 ·
the availability of alternative fuel sources;
 ·
the effects of inclement weather;
 ·
the availability of drilling and related equipment;
 ·
accidental events;
 ·
currency fluctuations;
 ·
changes in governmental regulations; and
 ·
the availability and productivity of skilled labor.
  Because of these factors, we could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural gas that we produce.
  Oil and gas exploration has a high degree of risk and our exploration efforts may be unsuccessful, which would have a negative effect on our operations.
  There is no certainty that the expenditures to be made by us in the exploration of our current projects, or any additional project interests we may acquire, will result in discoveries of recoverable oil and gas in commercial quantities. An exploration project may not result in the discovery of commercially recoverable reserves and the level of recovery of hydrocarbons from a property may not be a commercially recoverable (or viable) reserve that can be legally and economically exploited. If exploration is unsuccessful and no commercially recoverable reserves are defined, we would be required to evaluate and acquire additional projects that would require additional capital, or we would have to cease operations altogether.
  Cumulative unsuccessful exploration efforts could result in us having to cease operations.
  The expenditures to be made by us in the exploration of our properties may not result in discoveries of oil and natural gas in commercial quantities. Many exploration projects do not result in the discovery of commercially recoverable oil and gas deposits, and this occurrence could ultimately result in us having to cease operations.
  Oil and natural gas operations involve many hazards and operational risks, some of which may not be fully covered by insurance.  If a significant accident or event occurs for which we are not fully insured, our business, financial condition, results of operations and prospects could be adversely affected.
  Our involvement in the oil and natural gas exploration, development and production business subjects us to all of the risks and hazards typically associated with those types of operations, including hazards such as fire, explosion, blowouts, sour gas releases and spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or personal injury. In particular, we may explore for and produce sour natural gas in certain areas. An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property, and may necessitate an evacuation of populated areas, all of which could result in liability to us. In accordance with industry practice, we are not fully insured against all of these risks. Although we maintain liability insurance in an amount that we consider consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event we could incur significant costs that could have a material adverse effect upon our business, financial condition, results of operations and prospects. In addition, the risks we face are not, in all circumstances, insurable and, in certain circumstances, we may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. For instance, we do not have insurance to protect against the risk from terrorism. Oil and natural gas production operations are also subject to all of the risks typically associated with those operations, including encountering unexpected geologic formations or pressures, premature decline of reservoirs and the invasion of water into producing formations. Losses resulting from the occurrence of any of these risks could have a material adverse effect on our business, financial condition, results of operations and prospects.
  9
  Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity.
  The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns. Oil and natural gas development activities, including seismic and drilling programs in northern Alberta and British Columbia, are restricted to those months of the year when the ground is frozen. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. In addition, certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain, and additional seasonal weather variations will also affect access to these areas. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity during certain parts of the year.
  The petroleum industry is highly competitive, and increased competitive pressures could adversely affect our business, financial condition, results of operations and prospects.
  The petroleum industry is competitive in all of its phases. We compete with numerous other organizations in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural gas. Our competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than us. Our ability to increase our reserves in the future will depend not only upon our ability to explore and develop our present properties, but also upon our ability to select and acquire other suitable producing properties or prospects for exploratory drilling. Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery and storage.
  We do not control all of the assets that are used in the operation of our business and, therefore, cannot ensure that those assets will be operated in a manner favorable to us.
  Other companies operate some of the assets in which we have an interest. As a result, we have a limited ability to exercise influence over the operation of those assets or their associated costs, which could adversely affect our financial performance.  Our return on assets operated by others will therefore depend upon a number of factors that may be outside of our control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants, the selection of technology and risk management practices.
  Our ability to market oil and natural gas depends on our ability to transport our product to market.  If we are unable to expand and develop the infrastructure in the areas surrounding certain of our assets, we may not be able to effectively market the oil and natural gas that we produce.
  Due to the location of some of our assets, both in Canada and the United States, there is minimal infrastructure currently available to transport oil and natural gas from our existing and future wells to market.  As a result, even if we are able to engage in successful exploration and production activities, we may not be able to effectively market the oil and natural gas that we produce, which could adversely affect our business, financial condition, results of operations and prospects.
  Demand and competition for drilling equipment could delay our exploration and production activities, which could adversely affect our business, financial condition, results of operations and prospects.
  Oil and natural gas exploration and development activities depend upon the availability of drilling and related equipment (typically leased from third parties) in the particular areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities. To the extent we are not the operator of our oil and natural gas properties, we depend upon the operators of the properties for the timing of activities related to the properties and are largely unable to direct or control the activities of the operators.
  Title to our oil and natural gas producing properties cannot be guaranteed and may be subject to prior recorded or unrecorded agreements, transfers, claims or other defects.
  Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, those reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat our claim. Unregistered agreements or transfers, or native land claims, may affect title.  If title is disputed, we will need to defend our ownership through the courts, which would likely be an expensive and protracted process and have a negative effect on our operations and financial condition. In the event of an adverse judgment, we would lose our property rights.  A defect in our title to any of our properties may have a material adverse effect on our business, financial condition, results of operations and prospects.
  10
   We may be unable to meet all of the obligations necessary to successfully maintain each of the licenses and leases and working interests in licenses and leases related to its properties, which could adversely affect our business, financial condition, results of operations and prospects.
  Our properties are held in the form of licenses and leases and working interests in licenses and leases.  If we or the holder of the license or lease fails to meet the specific requirement of a license or lease, the license or lease may terminate or expire.  None of the obligations required to maintain each license or lease may be met.  The termination or expiration of our licenses or leases or the working interests relating to a license or lease may have a material adverse effect on our business, financial condition, results of operations and prospects.
  Risks related to financing continuing and future operations
  We have a working capital deficiency and will be required to raise capital through financings.  We may not be able to obtain capital or financing on satisfactory terms, or at all.
  As of December 31, 2010, we had a working capital deficiency of approximately Cdn$2 million.  The working capital deficiency mainly consists of bridge loan drawn during 2010 which was initially due on March 31, 2011. In March 2011, the lender approved to extend the due date of the loan to October 31, 2011. Subsequent to December 31, 2010, we raised net proceeds of approximately Cdn$2.8 million.  In addition, we spent approximately Cdn$2.9 million in capital expenditures in the first quarter of 2011 on our Woodrush property and we expect to have general and administration expenses of approximately Cdn$3.5 million over the next twelve months.  We may also spend up to Cdn$3.5 million to fund our share of a joint venture with a New York Stock Exchange listed oil company, as announced on January 20, 2011, for land purchase and drilling of two horizontal wells. If we are unable to meet our general and administration expenses or our share of the joint venture costs or repay bridge loan through revenues and field operating netback from our oil and gas operations, we will need to raise capital through debt or equity financings.   We cannot assure you that debt or equity financing will be available to us, and even if debt or equity financing is available, it may not be on terms acceptable to us.  Our inability to access sufficient capital for our operations would have a material adverse effect on our business, financial condition, results of operations and prospects.
  We anticipate making substantial capital expenditures for future acquisition, exploration, development and production projects.  We may not be able to obtain capital or financing necessary to support these projects on satisfactory terms, or at all.
  We anticipate making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future.  If our revenues or reserves decline, we may not have access to the capital necessary to undertake or complete future drilling programs.  Debt or equity financing, or cash generated by operations, may not be available to us or may not be sufficient to meet our requirements for capital expenditures or other corporate purposes.  Even if debt or equity financing is available, it may not be on terms acceptable to us.  Our inability to access sufficient capital for our operations could have a material adverse effect on our business, financial condition, results of operations and prospects.
  Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times, thereby causing us to forfeit our interest in certain properties, miss certain acquisition opportunities and reduce or terminate our operations.
  Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times and we are currently utilizing our bank line of credit to fund our working capital deficit.  From time to time, we may require additional financing in order to carry out our oil and gas acquisition, exploration and development activities.  Failure to obtain such financing on a timely basis could cause us to forfeit its interest in certain properties, not be able to take advantage of certain acquisition opportunities and reduce or terminate our level of operations.  If our revenues from our reserves decrease as a result of lower oil and natural gas prices or otherwise, our ability to expend the necessary capital to replace our reserves or to maintain our production will be impaired.  If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or, if available, on favorable terms.
  11
  Debt that we incur in the future may limit our ability to obtain financing and to pursue other business opportunities, which could adversely affect our business, financial condition, results of operations and prospects.
  From time to time, we may enter into transactions to acquire assets or equity of other organizations.  These transactions may be financed in whole or in part with debt, which may increase our debt levels above industry standards for oil and natural gas companies of a similar size.  Depending upon future exploration and development plans, we may require additional equity and/or debt financing that may not be available or, if available, may not be available on acceptable terms.  None of our organizational documents currently limit the amount of indebtedness that we may incur.  The level of our indebtedness from time to time could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.
  We may be exposed to the credit risk of third parties through certain of our business arrangements.  Non-payment or non-performance by any of these third parties could have an adverse effect on our financial condition and results of operations.
  We may be exposed to third-party credit risk through our contractual arrangements with our current or future joint venture partners, marketers of our petroleum and natural gas production and other parties.  In the event those entities fail to meet their contractual obligations to us, those failures could have a material adverse effect on our financial condition and results of operations.  In addition, poor credit conditions in the industry and of joint venture partners may affect a joint venture partner's willingness to participate in our ongoing capital program, potentially delaying the program and the results of the program until we find a suitable alternative partner.
  Risks related to maintaining reserves and acquiring new sources of oil and natural gas
  Our success depends upon our ability to find, acquire, develop and commercially produce oil and natural gas, which depends upon factors outside of our control.
  Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome.  Our long-term commercial success depends upon our ability to find, acquire, develop and commercially produce oil and natural gas.  We have only recently commenced production of oil and natural gas.  There is no assurance that our other properties or future properties will achieve commercial production.  Without the continual addition of new reserves, our existing reserves and our production will decline over time as our reserves are exploited.  A future increase in our reserves will depend not only upon our ability to explore and develop any properties we may have from time to time, but also upon our ability to select and acquire new suitable producing properties or prospects.  No assurance can be given that we will be able to locate satisfactory properties for acquisition or participation.  Moreover, if acquisitions or participations are identified, we may determine that current market conditions, the terms of any acquisition or participation arrangement, or pricing conditions, may make the acquisitions or participations uneconomical, and further commercial quantities of oil and natural gas may not be produced, discovered or acquired by us, any of which could have a material adverse effect on our business, financial condition, results of operations and prospects.
  Properties that we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.
  Our long-term commercial success depends upon our ability to find, acquire, develop and commercially produce oil and natural gas reserves.  However, our review of acquired properties is inherently incomplete, as it generally is not feasible to review in depth every individual property involved in each acquisition.  Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential.  Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.
  Our estimated reserves are based on many assumptions that may prove to be inaccurate.  Any material inaccuracies in the reserve estimates or the underlying assumptions may adversely affect the quantities and present value of our reserves.
  12
  There are numerous uncertainties inherent in estimating quantities of oil, natural gas reserves and the future cash flows attributed to the reserves.  Our reserve and associated cash flow estimates are estimates only.  In general, estimates of economically recoverable oil and natural gas reserves and the associated future net cash flows are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results.  All estimates are to some degree speculative, and classifications of reserves are only attempts to define the degree of speculation involved.  For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves will vary from our estimates of them, and those variations could be material.
  Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history.  Recovery factors and drainage areas are estimated by experience and analogy to similar producing pools.  Estimates based on these methods are generally less reliable than those based on actual production history.  Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves, and those variations could be material.
  Our future oil and natural gas production may not result in revenue increases and may be adversely affected by operating conditions, production delays, drilling hazards and environmental damages.
  Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and other costs.  Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs.  In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells.  These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions.  While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.
  Risks related to management of the Company
  We may experience difficulty managing our anticipated growth.
  We may be subject to growth-related risks including capacity constraints and pressure on our internal systems and controls.  Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to attract and retain qualified management and technical personnel to meet the needs of our anticipated growth.  Our inability to deal with this growth could have a material adverse effect on our business, financial condition, results of operations and prospects.
  We depend upon key personnel and the absence of any of these individuals could result in us having to cease operations.
  While engaged in the business of exploring mineral properties, the nature of our business, our ability to continue our exploration of potential exploration projects, and to develop a competitive edge in the marketplace, depends, in large part, upon our ability to attract and maintain qualified key management and technical personnel.  Competition for such personnel is intense and we may not be able to attract and retain such personnel.
 
 Risks related to federal, state, local and other laws, controls and regulations
  We are subject to complex federal, provincial, state, local and other laws, controls and regulations that could adversely affect the cost, manner and feasibility of conducting our oil and natural gas operations.
  13
  Oil and natural gas exploration, production, marketing and transportation activities are subject to extensive controls and regulations imposed by various levels of government, which may be amended from time to time.  Governments may regulate or intervene with respect to price, taxes, royalties and the exportation of oil and natural gas. Regulations may be changed from time to time in response to economic or political conditions.  The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for crude oil and natural gas and increase our costs, any of which may have a material adverse effect on our business, financial condition, results of operations and prospects.  In addition, in order to conduct oil and natural gas operations, we require licenses from various governmental authorities.  We cannot assure you that we will be able to obtain all of the licenses and permits that may be required to conduct operations that we may desire to undertake.
  There is uncertainty regarding claims of title and rights of the aboriginal people to properties in certain portions of western Canada, and such a claim, if made in respect of our property or assets, could adversely affect our business, financial condition, results of operations and prospects.
  Aboriginal peoples have claimed aboriginal title and rights to a substantial portion of western Canada.  We are not aware that any claims have been made in respect of its property and assets.  However, if a claim arose and was successful it would have an adverse effect on our business, financial condition, results of operations and prospects.
  We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities, which could adversely affect our business, financial condition, results of operations and prospects.
  All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation under a variety of federal, provincial, state and local laws and regulations.  Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations.  The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.  Compliance with legislation can require significant expenditures, and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material.  Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs.  The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy any discharge. Environmental laws may result in a curtailment of production or a material increase in the costs of production, development or exploration activities, or otherwise adversely affect our business, financial condition, results of operations and prospects.
  Our facilities, operations and activities emit greenhouse gases, which will likely subject us to future legislation regarding the regulation of emissions of greenhouse gases.
  Announcements from governments on regulations for greenhouse gas and air emissions legislation have caused uncertainty and changed the environmental regulation of natural resource development.  Our exploration and production facilities and other operations and activities emit greenhouse gases.  Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nationwide emissions of carbon dioxide, methane, nitrous oxide and other greenhouse gases.  While the Canadian federal government has largely abandoned its intent to comply with its Kyoto Protocol obligations, the Canadian federal government has provided a draft framework for the federal regulation of greenhouse gases in Canada.  As such, there is no federal legislative scheme in Canada for the regulation of greenhouse gases.  Until that time, the impact of federal greenhouse gas regulation on our operations is unknown.  These regulations may require the reduction of emissions produced by our operations and facilities and the direct and indirect cost of compliance with the regulations may adversely affect our business, financial condition, results of operations and prospects.
  In 2007, the Alberta government’s Climate Change Emissions Management Act and Specified Gas Emitters Regulation came into effect and require that facilities emitting more than 100,000 tonnes of greenhouse gases reduce their greenhouse gas emission intensity by 12 percent over their average intensity levels of 2003, 2004 and 2005.  If the emissions intensity target is not met through improvements in operations, compliance tools include: per tonne payment into the climate change emissions management fund; purchase of Alberta-based offsets or purchase of emission performance credits from a different Alberta facility.  Failure to comply with these regulations may result in a penalty of $200 per tonne of greenhouse gases over the allowable greenhouse gas emission intensity limit.
  14
  During 2010, we discovered that our internal control over financial reporting is not effective, and we have identified a material weakness in our internal control over financial reporting.  If we are unable to remedy this material weakness, we will not be able to provide reasonable assurance regarding the reliability of our financial reporting and the preparation and fair presentation of financial statements for external purposes in accordance with generally accepted accounting principles.
  Review of our internal control over financial reporting by our Chief Executive Officer and Chief Financial Officer during 2010 identified that such internal control was not effective, with the result that misstatements were not prevented or detected in our interim financial statements for the three and six months ended June 30, 2010 and in the Note 21 to the consolidated financial statements for the year ended December 31, 2009 regarding reconciliation between Canadian and US GAAP.  Specifically, period end review of the interim financial statements for the three and six month period ended June 30, 2010 by our management did not identify misstatements over certain non-cash items. As a result, the above financial statements were restated and refilled.  To remedy the weaknesses, we have improved staff training and our period end review process.  If necessary, we will engage external consultants to review complex accounting and financial reporting matters.  However, any failure to effectively remediate this material weakness could result in us being unable to provide reasonable assurance regarding the reliability of our financial reporting and the preparation and fair presentation of our financial statements for external purposes in accordance with applicable generally accepted accounting principles, cause us to fail to meet reporting obligations, or result in our principal executive officer and principal financial officer being required to give a qualified assessment of our internal control over financial reporting or our independent auditors providing an adverse opinion regarding our principal executive officer and principal financial officer’s assessment of our internal control over financial reporting.  Any such result could cause investors to lose confidence in our reported financial information, which could have a material adverse effect on the trading price of our common shares and our ability to raise capital.
  As a public company, our compliance costs and risks have increased in recent years.
  Legal, accounting and other expenses associated with public company reporting requirements have increased significantly in the past few years.  We anticipate that general and administrative costs associated with regulatory compliance will continue to increase with on-going compliance requirements under the Sarbanes-Oxley Act of 2002, as well as any new rules implemented by the SEC, Canadian Securities Administrators, the NYSE Amex Equities and the Toronto Stock Exchange in the future.  These rules and regulations have significantly increased our legal and financial compliance costs and made some activities more time-consuming and costly.  We cannot assure you that we will continue to effectively meet all of the requirements of these regulations, including Section 404 of the Sarbanes-Oxley Act and National Instrument 52-109 of the Canadian Securities Administrators.  Any failure to effectively implement internal controls, or to resolve difficulties encountered in their implementation, could harm our operating results, cause us to fail to meet reporting obligations, or result in our principal executive officer and principal financial officer being required to give a qualified assessment of our internal control over financial reporting or our independent auditors providing an adverse opinion regarding our principal executive officer and principal financial officer’s assessment of our internal control over financial reporting.  Any such result could cause investors to lose confidence in our reported financial information, which could have a material adverse effect on the trading price of our common shares and our ability to raise capital.  These rules and regulations have made it more difficult and more expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage in the future.  As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers.
  Risks Related to Our Being a Foreign Private Issuer
  As a foreign private issuer, our shareholders may receive less complete and timely data.
  We are a “foreign private issuer” as defined in Rule 3b-4 under the United States Securities Exchange Act of 1934.  Our equity securities are accordingly exempt from Sections 14(a), 14(b), 14(c), 14(f) and 16 of the Exchange Act, pursuant to Rule 3a12-3 of the Exchange Act.  Therefore, we are not required to file a Schedule 14A proxy statement in relation to our annual meetings of shareholders.  The submission of proxy and annual meeting of shareholder information on Form 6-K may result in shareholders having less complete and timely information in connection with shareholder actions.  The exemption from Section 16 rules regarding reports of beneficial ownership and purchases and sales of common shares by insiders and restrictions on insider trading in our securities may result in shareholders having less data and there being fewer restrictions on insiders’ activities in our securities.
  15
  It may be difficult to enforce judgments or bring actions outside the United States against us and certain of our directors and officers.
  It may be difficult to bring and enforce suits against us.  We are incorporated in British Columbia, Canada.  Many of our directors and officers are not residents of the United States and some of our assets are located outside of the United States.  As a result, it may be difficult for U.S. holders of our common shares to effect service of process on these persons within the United States or to enforce judgments obtained in the U.S. based on the civil liability provisions of the U.S. federal securities laws against us or our officers and directors.  In addition, a shareholder should not assume that the courts of Canada (i) would enforce judgments of U.S. courts obtained in actions against us or our officers or directors predicated upon the civil liability provisions of the U.S. federal securities laws or other laws of the United States, or (ii) would enforce, in original actions, liabilities against us or our officers or directors predicated upon the U.S. federal securities laws or other laws of the United States.
  Risks related to investing in our common shares
  We have not paid any dividends on our common shares.  Consequently, your only opportunity currently to achieve a return on your investment will be if the market price of our common shares appreciates above the price that you pay for our common shares.
  We have not declared or paid any dividends on our common shares since our incorporation.  Any decision to pay dividends on our common shares will be made by our board of directors on the basis of our earnings, financial requirements and other conditions existing at such future time.  Consequently, your only opportunity to achieve a return on your investment in our securities will be if the market price of our common shares appreciates and you are able to sell your common shares at a profit.
  Our common share price has been volatile and your investment in our common shares could suffer a decline in value.
  Our common shares are traded on the Toronto Stock Exchange and the NYSE Amex Equities.  The market price of our common shares may fluctuate significantly in response to a number of factors, some of which are beyond our control.  These factors include price fluctuations of precious metals, government regulations, disputes regarding mining claims, broad stock market fluctuations and economic conditions in the United States.
  Dilution through officer, director, employee, consultant or agent options could adversely affect our shareholders.
  Because our success is highly dependent upon our officers, directors, employees, consultants and agents, we have granted to some or all of our key officers, directors, employees, consultants and agents options to purchase common shares as non-cash incentives.  To the extent that we grant significant numbers of options and those options are exercised, the interests of our other shareholders may be diluted.  As of June 21, 2011, there were 9,859,000 common share purchase options outstanding, of which 4,282,313 common share purchase options are vested and exercisable.  If all the vested options were exercised, it would result in an additional 4,282,313 common shares being issued and outstanding.
  The issuance of additional common shares may negatively affect the trading price of our common shares.
  We have issued equity securities in the past and may continue to issue equity securities to finance our activities in the future, including to finance future acquisitions, or as consideration for acquisitions of businesses or assets.  In addition, outstanding options and warrants to purchase our common shares may be exercised, resulting in the issuance of additional common shares.  The issuance by us of additional common shares would result in dilution to our shareholders, and even the perception that such an issuance may occur could have a negative effect on the trading price of our common shares.
 
 ITEM 4.   INFORMATION ON THE COMPANY
 
 A.           History and Development of the Company
  16
 
 Introduction
 
 Our executive office is located at:
 
 598 – 999 Canada Place
 Vancouver, British Columbia, Canada V6C 3E1
 Telephone: (604) 638-5050
 Facsimile: (604) 638-5051
 Website: www.dejour.com
 Email: rhodgkinson@dejour.com or mwong@dejour.com
 
 The contact person is: Mr. Robert L. Hodgkinson, Chairman and Chief Executive Officer or Mr. Mathew H. Wong, Chief Financial Officer and Corporate Secretary.
 
 Our common shares trade on the Toronto Stock Exchange and the NYSE Amex Equities Stock Exchange under the symbol “DEJ”.
 
 Our authorized capital consists of three classes of shares: an unlimited number of common shares; an unlimited number of preferred shares designated as First Preferred Shares, issuable in series; and an unlimited number of preferred shares designated as Second Preferred Shares, issuable in series. There are no indentures or agreements limiting the payment of dividends and there are no conversion rights, special liquidation rights, pre-emptive rights or subscription rights.
 
 The First Preferred Shares have priority over the Common Shares and the Second Preferred Shares with respect to the payment of dividends and in the distribution of assets in the event of a winding up of Dejour. The Second Preferred Shares have priority over the Common Shares with respect to dividends and surplus assets in the event of a winding up of Dejour.
 
 As of December 31, 2010 there were 110,180,545 common shares issued and outstanding. As of December 31, 2010 there were no First Preferred Shares and no Second Preferred Shares issued and outstanding. As of March 31, 2011, the latest fiscal period for which financial statements are available, there were 121,390,545 common shares issued and outstanding, and no First Preferred Shares and no Second Preferred Shares issued and outstanding.
 
 Incorporation and Name Changes
 
 Dejour Enterprises Ltd. was originally incorporated as Dejour Mines Limited on March 29, 1968 under the laws of the Province of Ontario. By articles of amendment dated October 30, 2001, our issued shares were consolidated on the basis of one (1) new for every fifteen (15) old shares and our name was changed to Dejour Enterprises Ltd.  On June 6, 2003, our shareholders approved a resolution to complete a one-for-three-share consolidation which became effective on October 1, 2003. In 2005, we were continued into British Columbia under the Business Corporations Act(British Columbia). On March 9, 2011, we changed our name from Dejour Enterprises Ltd. to Dejour Energy Inc.
 
 Financings
 
 We have financed our operations through funds raised in loans, public/private placements of common shares, common shares issued for property, common shares issued in debt settlements, and shares issued upon exercise of stock options and share purchase warrants.  The following table summarizes our financings for the past three fiscal years.
  17
 
 Fiscal Year

Nature of Share Issuance

Number of Shares


Gross Proceeds

(Cdn$)Fiscal 2008

Conversion of Convertible Debentures (4)


884,242



1,214,497Exercise of Warrants


958,263



1,447,464Exercise of Stock Options


1,681,048



887,621Fiscal 2009

Exercise of Stock Options


631,856



273,223Private Placement(5)


2,710,332



1,626,199Public Offering(6)


10,766,665



3,425,060Fiscal 2010

Private Placement(7)


2,907,334



1,017,567Private Placement(8)


2,000,000


$
750,000Public Offering/Private Placement (9)


7,142,858


$
2,000,000Private Placement (10)


2,339,315


$
888,940Fiscal 2011

Public Offering (11)


11,010,000


$
3,288,641
 
 (1)
The private placement consisted of 3,773,980 common share units at Cdn$2.65 per unit for gross proceeds of Cdn$10,001,047. Each unit consisted of one common share and one-half of a common share purchase warrant. Each full warrant is convertible to one common share at a price of Cdn$3.35 before May 25, 2009. Finders’ fees of Cdn$493,215 and other related costs of Cdn$30,564 were paid in relation to the placement. We also issued 217,139 agent compensation warrants, exercisable at Cdn$3.35 per share before December 31, 2008.
 
 (2)
The private placement consisted of 1,000,000 flow-through common shares at a price of Cdn$1.82 per share. Gross proceeds from the placement were Cdn$1,820,000, which is committed to be spent on qualifying Canadian Exploration Expenditures. In relation to the placement, we paid Cdn$9,600 in related costs.
 
 (3)
During the year, we issued 273,399 shares pursuant to the conversion of US$349,850 in principal and US$12,493 of interest payable of convertible debentures.
 
 (4)
During the year, we issued 884,242 common shares pursuant to the conversion of US$1,047,995 in principal and US$145,731 of interest payable of convertible debentures.
 
 (5)
In October 2009, we completed a private placement and issued 2,710,332 flow-through shares (“FTS”) at Cdn$0.60 per share. Gross proceeds raised were Cdn$1,626,199. In connection with this private placement, we paid finders’ fees of Cdn$83,980 and other related costs of Cdn$73,427.
 
 (6)
In December 2009, we completed a public offering and issued 10,766,665 units at US$0.30 per unit. Each unit consists of 10,766,665 common shares and 8,075,000 share purchase warrants, exercisable at US$0.40 per share on or before December 23, 2014. Gross proceeds raised were Cdn$3,425,060 (US$3,230,000). In connection with this public offering, we paid finders’ fees of Cdn$203,180 and other related costs of Cdn$140,790. We also issued 645,999 agent’s warrants, exercisable at US$0.46 per share on or before November 3, 2014. The grant date fair values of the warrants and agent’s warrants, estimated to be $888,250 and $71,060 respectively, have been included in share capital on a net basis and accordingly have not been recorded as a separate component of shareholders’ equity.
 
 (7)
In March 2010, we completed a private placement and issued 2,907,334 flow-through units at Cdn$0.35 per unit.  Each unit consists of 2,907,334 common shares and 1,453,667 share purchase warrants, exercisable at $0.45 per share on or before March 3, 2011. Gross proceeds raised were Cdn$1,017,567. In connection with this private placement, we paid finders’ fees of Cdn$54,575 and other related costs of $52,819. We also issued 37,423 agent’s warrants, exercisable at Cdn$0.45 per share on or before March 3, 2011.
 
 (8)
In September 2010, we completed a private placement and issued 2,000,000 flow-through shares at Cdn$0.375 per share. Gross proceeds raised were Cdn$750,000. In connection with this private placement, we paid finders’ fees of Cdn$37,500 and other related costs of Cdn$38,890.
 
 (9)
In November 2010, we completed an offering of 7,142,858 units at Cdn$0.28 per unit, partially pursuant to a public offering and partially pursuant to a private placement. Each unit consists of one common share and 0.65 of a common share purchase warrant. Each whole common share purchase warrant is exercisable into one common share at Cdn$0.40 per share on or before November 17, 2015. Gross proceeds raised were Cdn$2,000,000. In connection with this offering, we paid finders’ fees of Cdn$120,000 and other related costs of Cdn$123,423.
 
 (10)
In December 2010, we completed a private placement and issued 2,339,315 flow-through shares at Cdn$0.38 per share. Gross proceeds raised were Cdn$888,940. In connection with this private placement, we paid finders’ fees of Cdn$53,337 and other related costs of Cdn$61,862. We also issued 140,359 agent’s warrants, exercisable at Cdn$0.38 per share on or before December 23, 2011. Directors and Officers of the Company purchased 513,157 shares of this offering.
  18
 
 (11)
In February 2011, we completed a public offering of 11,010,000 units at US $0.30 per unit. Each unit consists of one common share and one-half of one common share purchase warrant. Each whole warrant entitles the holder to acquire one additional common share of the Company at US$0.35 per common share on or before February 10, 2012. Gross proceeds raised were US$3,303,000. In connection with this private placement, the Company paid finders’ fees of US$199,710 in cash.
 
 Past Capital Expenditures
 
 Fiscal Year

Cash flows used for equipment and resource propertiesFiscal 2008

Cdn$27,658,300 (1)Fiscal 2009

Cdn$2,626,488 (2)Fiscal 2010

Cdn$5,042,934 (3)
 
 (1)
$67,049 of these funds were spent on the purchase of equipment; and $27,591,251 was spent on our resource properties. (For a breakdown on the resource property expenditures, see Note 7 to our audited consolidated financial statements for the fiscal year ended December 31, 2008, filed with our annual report on Form 20-F on June 30, 2009.)
 
 (2)
$39,279 of these funds were spent on the purchase of equipment; and $2,587,209 was spent on our resource properties. (For a breakdown on the resource property expenditures, see Note 6 to our audited consolidated financial statements for the fiscal year ended December 31, 2009, filed with our annual report on Form 20-F on June 30, 2010.)
 
 (3)
$26,945 of these funds were spent on the purchase of equipment; and $5,015,989 was spent on our resource properties. (For a breakdown on the resource property expenditures, see Note 6 to our audited consolidated financial statements for the fiscal year ended December 31, 2010, filed with this annual report on Form 20-F.)
 
 Capital Expenditures
 
 Our business objective remains the economic development of key projects and growth opportunities, resulting in the enhancement of shareholder value. This was accomplished in 2010 through prudent investment in and management of our portfolio of producing and non-producing assets. As the business environment continues to improve we expect to accelerate prudent investment in our core assets and possibly a limited program of strategic acquisitions and divestitures when such activities allow us to enhance to our core assets and operations.
 
 As 2010 began, oil prices had stabilized at a level of approximately US$80/barrel and many in the industry were projecting that the natural gas would strengthen throughout the year as the market returned to a supply demand balance reflecting the costs of shale gas developments. As 2010 progressed, natural gas prices sustained higher levels than they had achieved in 2009, but remained below early expectations as continuing advances in the drilling of new natural gas resource plays kept the market slightly oversupplied. While natural gas prices were disappointing, oil prices provided the industry a lift as they continued to strengthen throughout the year and surpassed $100/barrel in early 2011.
 
 We tailored our 2010 development plan to allow us to continue our growth despite the potential for this commodity price divergence driven by delay in the recovery of the natural gas prices. In 2010, all of our capital investments were targeted to developing our oil resources. As a result, we successfully completed the development of the Halfway oil pool located in our Woodrush property. At the same time, significant progress was made in the permitting and planning stages of our Piceance properties and in particular our project at Gibson Gulch, but capital commitments were delayed by six months and are now projected for the third and fourth quarter of 2011.
 
 While some additional development drilling is anticipated, the start-up of the waterflood marks the end of major capital investments in Woodrush. In 2011 we will concentrated on optimizing injection and production in the waterflood, controlling cost and increasing margins on gas production as the oil production is gradually ramped up to its maximum level in the second half of 2012.
  19
 
 In Colorado, we still anticipate drilling one oil play and one gas play in 2011. In June 2011, we announced that it has drilled and set casing on an initial vertical well to test the Mancos/Niobrara potential on its South Rangely. After a thorough review of the well data the well will be completed, fractured and flow tested to determine the commercial potential of the Lower Mancos “C” Sand in this area. In the fourth quarter of 2011, a multi-well drilling program is projected to commence on our Gibson Gulch acreage where major Piceance operators Williams E&P and Bill Barrett Corp. have announced plans to increase drilling in 2011 on the properties surrounding our leasehold.
 
 Currently, we have no capital expenditure commitments.
 
 During first quarter of 2011, we spent approximately Cdn$2.8 million in capital expenditures on our Woodrush property.  The Company’s share of wateflood capital expenditures for the remaining of 2011 is approximately $1.2 million.  We may also spend up to Cdn$3.5 million to fund our share of a joint venture with a New York Stock Exchange listed oil company, as announced on January 20, 2011, for land purchase and drilling of two horizontal wells.
 
 B.           Business Overview
 
 General
 
 We are in the business of acquiring, exploring and developing energy projects with a focus on oil and gas exploration in Canada and the United States.  We hold approximately 120,000 net acres of oil and gas leases in the following regions:
 
 ·
The Peace River Arch of northwestern British Columbia and northeastern Alberta, Canada
 ·
The Piceance, Paradox and Uinta Basins in the US Rocky Mountains
 
 In the second quarter of 2008, we commenced production and started receiving revenue from our Peace River Arch oil and gas properties, realizing the shift from a pure play exploration company to an exploration and production company.
 
 Summary
 
 Over the past three years, we have evolved our forward focus from acquiring resource potential toward conversion of resources into reserves. This process involved several distinct steps on the same continuum including:
 
 ·
Classification and prioritization of acreage based on economic promise, technical robustness, infrastructural and logistic advantage and commercial maturity
 ·
Evaluation and development planning for top tier acreage positions
 ·
Developing partnerships within financial and industry circles to speed the exploitation process, and
 ·
Aggressively bringing production on line where feasible.
 
 As a result of these moves, our asset characterization has moved toward more tangible low risk near term development projects, moderate risk appraisal opportunities and modest risk exploration potential with a benign lease expiration profile.
 
 Our business objective is to grow our oil and gas production and generate sufficient cash flow to continue to expand company operations and enhance shareholder value.  We intend to achieve our objectives through a strategy of acquiring oil and gas assets in areas and projects that we believe have high potential and through prudent investment and management.
 
 Three Year History
 
 2010
  20
  
 In 2010, our focus was on increasing production, reserves, and operational efficiency at the Drake/Woodrush properties, while maintaining all prospective acreage holdings and positioning for renewed drilling activities as both the business environment and commodity prices improved.
 
 During the year, we achieved the following major objectives and also made significant progress on key strategic initiatives that resulted in:
 
 1.
Extended the limits of the Woodrush halfway pool by drilling three successful development wells in 2010.
 
 2.
Received approval from the British Columbia Oil and Gas Commission to implement a waterflood in the Halfway oil pool at Woodrush and began project implementation in October.
 
 3.
Raised gross proceeds of $4.7 million in equity under challenging market conditions, allowing us to support the development of oil and gas properties in the Drake/Woodrush properties.
 
 4.
Obtained a bridge loan credit facility of up to $5 million, allowing us to refinance its existing bank facility and fund its working capital and capital expenditures.
 
 2009
 
 In 2009, our focus was on the restructuring of current assets and operations to reduce debt and lower operating costs while maintaining all prospective acreage holdings and positioning for renewed drilling activities as both the business environment and commodity prices improved.
 
 Despite the difficult environment faced in 2009, we were able to achieve all major objectives and also make significant progress on key strategic initiatives that resulted in the following:
 
 1.
Increased Net Proved Reserves to 64 BCFE as at December 31, 2009.  The before tax discounted (NPV10) value of our proved reserves, net of all future costs for development is now valued at  $16 million. The major increase in reserves results from developments in the Gibson Gulch field in the Piceance Basin where we hold a 72% working interest in 2200 gross acres.  This property is discussed in more detail later in this report.
 
 2.
Reduced debt from $18.3 million to $6.2 million.
 
 3.
Eliminated working capital deficit of $12.7 million at the end of 2008 and end 2009 with a positive working capital of $410,000.
 
 4.
Raised $5 million of equity under challenging market conditions that allowed us to execute our winter drilling program in Woodrush Field.
 
 5.
Strengthening our Board of Directors with the addition of Stephen Mut as Co-Chairman of the Board and Darren Devine as Director.
 
 6.
In 2009, we disposed of all of its holdings in Titan Uranium for proceeds of $2,305,491.  We retain a 10% carried interest and 1% Net Smelter Return on approximately 578,365  acres of uranium leases.
 
 2008
 
 1.
Piceance and Uinta Basins, US
 
 ·
Increased land holdings to 128,000 net acres
 ·
Established a joint venture on 14,000 gross acres with Fidelity Exploration & Production Company, a subsidiary of a NYSE listed company with US$4.2 billion in revenues, MDU Resources Group Inc.
 ·
Established a joint venture on 22,000 gross acres with Laramie Energy II LLC (“Laramie”)
  21
  2.
Peace River Arch, Canada
 
 ·
Tied in seven of the eleven wells drilled to production, capable of producing 1,000 boe / day
 ·
Acquired 6,350 net acres in a new “Montney” formation natural gas prospect in British Columbia
  3.
Common share listing upgraded to TSX from TSX Venture Exchange
  4.
Obtained a $7 million bank line of credit and $2.55 million loan from a related party for exploration program in Canada
  5.
Obtained a US$4 million loan from a working interest partner to purchase additional acreage in the United States
 
 US Activities
 
 Gibson Gulch
 
 We have moved forward aggressively to begin the process of bringing this development project into production. We have a 72% working interest in this 2,200 acre project which is ideally situated for exploitation of thick columns of both the Williams Fork and Mancos shale bodies.
 
 Dejour USA is working closely with important constituents including local citizenry and government, the Bureau of Land Management and the Colorado Division of Wildlife to develop a mutually acceptable development plan for this environmentally sensitive area.  After all permits are received, current plans call for drilling to commence in the fourth quarter of 2011 with production expected to begin later in that year or early 2012.  In 2010, we were granted approval to develop a 660 acre portion of the Gibson Gulch leases with 10-acre spacing. Approval of this spacing on the remainder of the lease acreage would enable us and our partner to drill up to 220 wells (158 wells net to us) from a few multi-well drilling pads to optimally exploit the gas reserves in the subsurface.
 
 South Rangely
 
 Evaluation and subsequent exploitation of an oil prospect at South Rangely, was deferred from the fourth quarter of 2010 to the second quarter of 2011, as a result of minor delays in the permitting process that prevented drilling from occurring before the winter drilling prohibitions designed to protect big game habitat.  Despite a minor delay, we have not altered our plans to drill an evaluation well on the 7,000 acre lease located just south of Rangely field. Recent advances in horizontal drilling and fracture stimulation technology have moved this previously marginal development into robust economic status. Successful drilling and production by an operator on offsetting acreage makes this project relatively low risk with the degree of economic success to be a function of the quality of the completion design. Success at South Rangely may allow us to revisit plans to evaluate and potentially exploit a 22,000 acre tract at our North Rangely prospect. This acreage had previously been subject to farm-out with Laramie Energy II LLC. Due to market conditions, Laramie declined to follow through with the farm-out terms and the acreage has reverted to our control.
 
 In May 2011 we announced that we and our partners had executed a development alliance with a private Dallas based US E&P with adjacent properties and in June 2011 we announced that it has drilled and set casing on an initial vertical well to test the Mancos/Niobrara potential on its South Rangely. After a thorough review of the well data the well will be completed, fractured and flow tested to determine the commercial potential of the Lower Mancos “C” Sand in this area.
 
 West Grand Valley
 
 In West Grand Valley, we operate approximately 5,100 gross acres with a 72% working interest in an area of active drilling by EnCana, Laramie Partners II and Axia.  Here, success in developing the gas in the Lower Mancos (Niobrara) section has revitalized drilling interest in this area of the Piceance Basin.  Included in this acreage is the 1400+ acre Roan Creek evaluation project. While it is likely that the Williams Fork as Roan Creek will be somewhat thinner than is found to the east and west, Roan Creek has Mancos potential which can be tested via an exploratory tail to a Williams Fork appraisal well. During 2009, the various geologic and commercial studies conducted by us highlighted the potential at Roan Creek which provided the driving force for a single well drilling program.  Permits have been applied for and drilling at Roan Creek will follow the first increment of drilling at Gibson Gulch.
  22
 
 Future Exploration and Evaluation
 
 We retain a substantial amount of acreage prospective for oil and gas exploitation in other sections of the Piceance and Uinta basins. We have approximately 109,000 net acre position that was sculpted over the 2006-2008 period.  We are operator of approximately 130,000 acres and are a non-operator in another 110,000 acres where Retamco Operating Inc. and Fidelity Exploration and Production Company operate.
  As a result of a reasonably comprehensive geologic and commercial study in 2009, we have high graded three future development and appraisal projects including:
 
 ·
Plateau - This 4,500 acre (gross) project located south of Roan Creek in the Piceance Basin has significant Williams Fork potential.
 ·
North Rangely – This 22,000 acre (gross) project located north of the Rangely Field, is prospective for oil in the Lower Mancos (Niobrara) and Dakota formations.
 
 These potential developments will be deferred to at least 2012 as the slow recovery of natural gas prices has caused us to delay the start of investments in Colorado. Exploitation of these opportunities will in all likelihood proceed only after developments at Gibson Gulch, South Rangely and Roan Creek reach equilibrium stage.
 
 Canadian Activities
 
 The Company’s wholly-owned subsidiary, Dejour Energy (Alberta) Ltd. (“DEAL”), currently has interests in oil and gas properties in the Peace River Arch located principally in northeastern British Columbia.
 
 For fiscal 2010, production from our operated wells averaged about 640 BOE/D (100% gross), comprising of 320 BOPD of oil and natural gas liquids and 1,920 MCFD of gas, an increase of 7% over 2009 production.  This was accomplished by successfully drilling two additional oil wells and one gas well during the year.
 
 As at December 31, 2010, DEAL’s holdings approximately 13,000 net acres concentrated in the Peace River Arch.
 
 Woodrush/Drake
 
 After completing a 3-D seismic program over the field in January 2010, we finalized drilling plans and in March commenced drilling of two development wells.  The first found the target Halfway sand tight, but encountered a new Gething Gas pool that was subsequently put on production at more than 1,000 MCFD (100% gross).  The second development well encountered the Halfway sand as expected, was completed and flow tested at rates in excess of 500 BOPD (100% gross).  In October the first water injection well was drilled to the southeast limit of the reservoir.  This well was produced briefly without the assistance of at 60 BOPD prior to conversion to injection.
 
 With the success of the drilling in March 2010, field production reached a record level in May 2010, averaging 970 BOED (100% gross), where 75% is oil.  In the fourth quarter of 2010, production from the field was reduced to approximately 560 BOED (100% gross) in response to increasing gas production resulting from the decreasing pressure in the Halfway oil sand.  In December 2010, a waterflood project application was expedited and approval was received.   The project was fully implemented in early 2011 with water injection commencing in March 2011.  Water injection will be gradually ramped up to a level of 1,500 to 2,000 BWPD with the resulting oil production expected to reach a peak of approximately 900 BOPD (100% gross) in the second half of 2012.
 
 While some additional development drilling is anticipated, the start-up of the waterflood marks the end of major capital investments in Woodrush. In 2011, we will concentrate on optimizing injection and production in the waterflood, controlling cost and increasing margins on gas production as the oil production is gradually ramped up to its maximum level in the second half of 2012 when operating netback is expected to reach approximately $1.5 million per month.
  23
  On May 4, 2011, we announced that purchased 3 additional sections of oil and gas leases at the April 27, 2011 B.C. Crown sale covering approximately 2,500 acres adjacent to its current landholdings of conventional oil/gas production at the Woodrush project. Following the acquisition, we hold 75% of 11 sections covering approximately 8,500 acres at the Woodrush project.
 
 Buick Creek (Montney Shale Basin)
 
 In December 2010, we sold our entire 90% interest in this area for net proceeds of approximately $952,000.
 
 Uranium Properties
 
 We have a 10% carried interest and 1% Net Smelter Return on certain uranium exploration leases in Saskatchewan operated by Titan Uranium Inc.
 
 United States vs. Foreign Sales/Assets
 
 Commencing the second quarter of fiscal 2008, we recorded our reported oil and gas revenue.
 
 Revenue for fiscal year ended:

Canada


United States12/31/2008

$
5,751,672


$
13,88312/31/2009

$
6,470,725



—12/31/2010

$
8,085,627



—
 
 Asset Location as of:

Canada


United States12/31/2006

$
55,495,194


$
25,182,53412/31/2007

$
35,181,268


$
27,962,23112/31/2008

$
32,758,495


$
29,884,69112/31/2009

$
16,874,298


$
29,011,57812/31/2010

$
17,132,794


$
29,222,372
  Commodity Price Environment
  Generally, the demand for and the price of natural gas increases during the colder winter months and decreases during the warmer summer months. Pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Crude oil and the demand for heating oil are also impacted by seasonal factors, with generally higher prices in the winter. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations.
  Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. The market for oil and natural gas is beyond our control and prices are difficult to predict.
  Forward Contracts
 
 We are not bound by an agreement (including any transportation agreement) directly or through an aggregator, under which it may be precluded from fully realizing, or may be protected from the full effect of, future market prices for oil and gas.
  Subsequent to December 31, 2010, we had the following put options, allowing us the right, but not the obligation, to sell Western Texas Instrument (“WTI”) crude oil:
  24
  Crude oil Contract

Contract Month

Volume

Price per barrelWTI Crude oil put options

April 2011

6,000 barrels per month

US$
93WTI Crude oil put options

May 2011

6,000 barrels per month

US$
93WTI Crude oil put options

June 2011

6,000 barrels per month

US$
93WTI Crude oil put options

July 2011

6,000 barrels per month

US$
93
 
 Government Regulations
 
 Our oil and natural gas exploration, production and related operations, when developed, are subject to extensive laws and regulations promulgated by federal, state, tribal and local authorities and agencies. These laws and regulations often require permits for drilling operations, drilling bonds and reports concerning operations, and impose other requirements relating to the exploration for and production of oil and natural gas. Many of the laws and regulations govern the location of wells, the method of drilling and casing wells, the plugging and abandoning of wells, the restoration of properties upon which wells are drilled, temporary storage tank operations, air emissions from flaring, compression, the construction and use of access roads, sour gas management and the disposal of fluids used in connection with operations.
 
 Our operations are subject to environmental regulations (including regular environmental impact assessments and permitting) in the jurisdictions in which it operates.  Such regulations cover a wide variety of matters, including, without limitation, emission of greenhouse gases, prevention of waste, pollution and protection of the environment, labour regulations and worker safety.  Under such regulations there are preventative obligations, clean-up costs and liabilities for toxic or hazardous substances which may exist on or under any of its properties or which may be produced as a result of its operations.  Environmental legislation and legislation relating to exploration and production of oil and natural gas will require stricter standards and enforcement, increased fines and penalties for non-compliance, more stringent environmental assessments of proposed projects and a heightened degree of responsibility for companies and their directors and employees.  Such stricter standards could impact our costs and have an adverse effect on results of operations.
  The Comprehensive Environmental, Response, Compensation, and Liability Act, or CERCLA, and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of "hazardous substances" found at such sites. It is not uncommon for the government to file claims requiring cleanup actions, demands for reimbursement for government-incurred cleanup costs, or natural resource damages, or for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize the imposition of substantial fines and penalties for noncompliance, as well as requirements for corrective actions. Although CERCLA currently excludes petroleum from its definition of "hazardous substance," state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum-related products. In addition, although RCRA classifies certain oil field wastes as "non-hazardous," such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements. CERCLA, RCRA and comparable state statutes can impose liability for clean-up of sites and disposal of substances found on drilling and production sites long after operations on such sites have been completed. Other statutes relating to the storage and handling of pollutants include the Oil Pollution Act of 1990, or OPA, which requires certain owners and operators of facilities that store or otherwise handle oil to prepare and implement spill response plans relating to the potential discharge of oil into surface waters. The OPA, contains numerous requirements relating to prevention of, reporting of, and response to oil spills into waters of the United States. State laws mandate oil cleanup programs with respect to contaminated soil. A failure to comply with OPA's requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions.
  The Endangered Species Act, or ESA, seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, or destroy or modify the critical habitat of such species. Under the ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. The ESA has been used to prevent or delay drilling activities and provides for criminal penalties for willful violations of its provisions. Other statutes that provide protection to animal and plant species and that may apply to our operations include, without limitation, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act. Although we believe that our operations are in substantial compliance with these statutes, any change in these statutes or any reclassification of a species as threatened or endangered or re-determination of the extent of "critical habit" could subject us to significant expenses to modify our operations or could force us to discontinue some operations altogether.
  25
  The National Environmental Policy Act, or NEPA, requires a thorough review of the environmental impacts of "major federal actions" and a determination of whether proposed actions on federal and certain Indian lands would result in "significant impact." For purposes of NEPA, "major federal action" can be something as basic as issuance of a required permit. For oil and gas operations on federal and certain Indian lands or requiring federal permits, NEPA review can increase the time for obtaining approval and impose additional regulatory burdens on the natural gas and oil industry, thereby increasing our costs of doing business and our profitability.
  The Clean Water Act, or CWA, and comparable state statutes, impose restrictions and controls on the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the Environmental Protection Agency (EPA) or an analogous state agency. The CWA regulates storm water run-off from oil and natural gas facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.
  The Safe Drinking Water Act, or SDWA, and the Underground Injection Control (UIC) program promulgated thereunder, regulate the drilling and operation of subsurface injection wells. EPA directly administers the UIC program in some states and in others the responsibility for the program has been delegated to the state. The program requires that a permit be obtained before drilling a disposal well. Violation of these regulations and/or contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SWDA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.
  The Clean Air Act, as amended, restricts the emission of air pollutants from many sources, including oil and gas operations. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to remain in compliance. In addition, the EPA has promulgated more stringent regulations governing emissions of toxic air pollutants from sources in the oil and gas industry, and these regulations may increase the costs of compliance for some facilities.
  Significant studies and research have been devoted to climate change and global warming, and climate change has developed into a major political issue in the United States and globally. Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment. Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural gas exploration and production. Many state governments have enacted legislation directed at controlling greenhouse gas emissions, and future state and federal legislation and regulation could impose additional restrictions or requirements in connection with our operations and favor use of alternative energy sources, which could increase operating costs and demand for oil products. As such, our business could be materially adversely affected by domestic and international legislation targeted at controlling climate change.
  We expect to incur abandonment and site reclamation costs as existing oil and gas properties are abandoned and reclaimed; however, we do not anticipate making material expenditures beyond normal compliance with environmental regulations in 2011 and future years.
 
 The health and safety of employees, contractors and the public, as well as the protection of the environment, is of utmost importance to us. We endeavour to conduct our operations in a manner that will minimize adverse effects of emergency situations by:
 
 ·
complying with government regulations and standards;
 ·
following industry codes, practices and guidelines;
 ·
ensuring prompt, effective response and repair to emergency situations and environmental incidents; and
  26
 
 ·
educating employees and contractors of the importance of compliance with corporate safety and environmental rules and procedures.
 
 We believe that all of our personnel have a vital role in achieving excellence in environmental, health and safety performance. This is best achieved through careful planning and the support and active participation of everyone involved
 
 Competition
 
 We operate in geographical areas where there is strong competition by other companies for reserve acquisitions, exploration leases, licences and concessions and skilled industry personnel. Our competitors include major integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual producers and operators, many of whom have greater financial and personnel resources than us.  Our ability to acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers is dependent upon developing and maintaining close working relationships with its current industry partners and joint operators, and its ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.
 
 We compete with many companies possessing greater financial resources and technical facilities for the acquisition of oil and gas properties, exploration and production equipment, as well as for the recruitment and retention of qualified employees.
  Seasonality
  All of our operations in Canada are affected by seasonal operating conditions.  DEAL holds properties in northwestern Alberta and northeastern British Columbia which are accessible to heavy equipment in winter only when the ground is frozen, typically between December to early April. For this reason drilling and pipeline construction ceases over the remainder of the year, limiting growth to winter only. Production operations continue year round in these areas once production is established. The prices that we will receive for oil and gas production in the future are weighted to world benchmark prices and may be adversely affected by mild weather conditions.
 
 C.           Organizational Structure
 
 Dejour Energy Inc. (formerly Dejour Enterprises Ltd.) is incorporated under the laws of British Columbia, Canada. The Company was originally incorporated as “Dejour Mines Limited” on March 29, 1968 under the laws of the Province of Ontario. By articles of amendment dated October 30, 2001, the issued shares were consolidated on the basis of one (1) new for every fifteen (15) old shares and the name of the Company was changed to Dejour Enterprises Ltd. On June 6, 2003, the shareholders approved a resolution to complete a one-for-three-share consolidation, which became effective on October 1, 2003. In 2005, the Company was continued in British Columbia under the Business Corporations Act(British Columbia). On March 9, 2011, the Company changed its name from Dejour Enterprises Ltd. to Dejour Energy Inc.
  Intercorporate Relationships
  We have four 100% owned subsidiaries:
  ·
Dejour Energy (USA) Corp. (“Dejour USA”), a Nevada corporation, holds Dejour's United States oil and gas interests,
 ·
Dejour Energy (Alberta) Ltd. (“DEAL”), an Alberta corporation, holds its Canadian oil and gas interests
 ·
Wild Horse Energy Ltd. (“Wild Horse”), an inactive Alberta corporation, and
 ·
0855524 B.C. Ltd. (“0855524”), a British Columbia Corporation, which had disposed of its Montney (Buick Creek) property during 2010 and is currently inactive.
  27
  D.           Property, Plant and Equipment
  Our executive offices are located in rented premises of approximately 2,519 sq. ft. at 598 – 999 Canada Place, Vancouver, British Columbia, V6C 3E1.  We began occupying these facilities on July 1, 2009.  Current monthly base rent is $6,088.
 
 Resource Properties
 
 Our current focus is on oil and gas properties located in the United States and Canada. We formerly had direct interest in uranium exploration properties, which we sold to Titan Uranium Inc. in 2006 for Titan common shares. We sold all of our Titan common shares in 2009, but retained a 1% NSR on all the properties sold to Titan, and a 10% working interest in each claim, carried by Titan to a completed bankable feasibility study after which we may elect to participate as to its 10% interest or convert to an additional 1% NSR.
 
 We currently have oil and gas leases in northeastern British Columbia and Northwestern Alberta, and in the Piceance and Uinta Basins in Colorado and Utah. The Company’s resource property interests are described below:
 
 United States Oil and Gas Properties
  In July 2006, our U.S. subsidiary, Dejour USA, entered into a participation agreement (the “2006 Retamco Agreement”) with Retamco Operating, Inc. (“Retamco”), a U.S. privately owned oil and gas corporation, and Brownstone Ventures (US) Inc. (“Brownstone”), a subsidiary of Brownstone Ventures Inc., a Canadian company listed on the TSX-V.  Under the agreement, Dejour USA and Brownstone agreed to participate in the ownership of specified oil and gas leasehold interests and related exploration and development of those leases located in the Piceance, Uinta and Paradox Basins of western Colorado and eastern Utah.
  In June 2008, Dejour USA entered into a further purchase and sale agreement with Retamco resulting in Dejour USA acquiring an additional 64,000 net acres involving the same properties in which it purchased an interest in the 2006 Retamco Agreement.  Additionally, as a part of this latter agreement Dejour USA sold its 25% working interests in two wells in the North Barcus Creek Prospect (located in Piceance Basin, Colorado) and its lease interest in the Rio Blanco Deep Prospect (located in northern Colorado).
  During Fiscal 2010, certain leases expired. As of December 31, 2010, the Company had approximately 109,000 net acres in the Colorado/Utah Project.
  28
 
 
 
 Gibson Gulch Prospect Area
  The Gibson Gulch Prospect Area in Garfield County, Colorado, consists of 2,200 gross acres of sparsely drilled acreage, within the prospective conventional / continuous gas resource trend in the Uinta-Piceance Basin.
  We have moved forward aggressively to begin the process of bringing this development project into production. We have a 72% working interest in this 2,200 acre project which is ideally situated for exploitation of thick columns of both the Williams Fork and Mancos shale bodies.
 
 Dejour USA is working closely with important constituents including local citizenry and government, the Bureau of Land Management and the Colorado Division of Wildlife to develop a mutually acceptable development plan for this environmentally sensitive area.  After all permits are received, current plans call for drilling to commence in the fourth quarter of 2011 with production expected to begin later in that year or early 2012.  In 2010, we were granted approval to develop a 660 acre portion of the Gibson Gulch leases with 10-acre spacing. Approval of this spacing on the remainder of the lease acreage would enable us and our partner to drill up to 220 wells (158 wells net to us) from a few multi-well drilling pads to optimally exploit the gas reserves in the subsurface.
 
 Rangely Prospect Area
 
 The Rangely Prospect Area is just south of Rangely Field near the Utah border. In the Rangely prospect area, fractured Mancos Shale is producing gas. The Mancos also contains sandstone intervals, Mancos A and Mancos B, which can be productive. The eastern shoulder of the Douglas Creek Arch and the flanks of the Rangely Anticline as well as other areas of the basin are being explored for this Cretaceous age strata. The Mancos is also considered a source rock in the area.
  29
  Evaluation and subsequent exploitation of an oil prospect at South Rangely, was deferred from the fourth quarter of 2010 to the second quarter of 2011, as a result of minor delays in the permitting process that prevented drilling from occurring before the winter drilling prohibitions designed to protect big game habitat.  Despite a minor delay, we have not altered our plans to drill an evaluation well on the 7,000 acre lease located just south of Rangely field. Recent advances in horizontal drilling and fracture stimulation technology have moved this previously marginal development into robust economic status. Successful drilling and production by an operator on offsetting acreage makes this project relatively low risk with the degree of economic success to be a function of the quality of the completion design. Success at South Rangely may allow us to revisit plans to evaluate and potentially exploit a 22,000 acre tract at our North Rangely prospect. This acreage had previously been subject to farm-out with Laramie Energy II LLC. Due to market conditions, Laramie declined to follow through with the farm-out terms and the acreage has reverted to our control.
 
 In May 2011, we announced that we and our partners had executed a development alliance with a private Dallas based US E&P with adjacent properties and in June 2011, we announced that it has drilled and set casing on an initial vertical well to test the Mancos/Niobrara potential on its South Rangely. After a thorough review of the well data the well will be completed, fractured and flow tested to determine the commercial potential of the Lower Mancos “C” Sand in this area.
 
 West Grand Valley
 
 In West Grand Valley, we operate approximately 5,100 gross acres with a 72% working interest in an area of active drilling by EnCana, Laramie Partners II and Axia.  Here, success in developing the gas in the Lower Mancos (Niobrara) section has revitalized drilling interest in this area of the Piceance Basin.  Included in this acreage is the 1400+ acre Roan Creek evaluation project. While it is likely that the Williams Fork as Roan Creek will be somewhat thinner than is found to the east and west, Roan Creek has Mancos potential which can be tested via an exploratory tail to a Williams Fork appraisal well. During 2009, the various geologic and commercial studies conducted by us highlighted the potential at Roan Creek which provided the driving force for a single well drilling program.  Permits have been applied for and drilling at Roan Creek will follow the first increment of drilling at Gibson Gulch.
 
 Other Prospect Areas
 
 As of December 31, 2010, Dejour had approximately 87,000 net acres in the following prospect areas, which are considered as non-core projects of the Company:
 
 Area

Prospect

Net acres to DejourPiceance

Book Cliffs


11,811Plateau


2,666Gunnison


1,204Paradox

San Juan


169Green River


3,214Uinta

Bitter Creek


830Bonanza


272Cisco


5,250Displacement


4,285Gorge Spring


938Oil shale


899Seep Ridge


201Tri County


1,397Northern Colorado

Meeker


3,607Pinyon


4,637Waddle Creek


212Sub-Thrust

Dinosaur


45,186Ashley


480Sand Wash

Sand Wash


227Total




87,485
 
 30
 
 Future Exploration and Evaluation
 We retain a substantial amount of acreage prospective for oil and gas exploitation in other sections of the Piceance and Uinta basins. We have approximately 109,000 net acre position that was sculpted over the 2006-2008 period.  We are operator of approximately 130,000 acres and are a non-operator in another 110,000 acres where Retamco Operating Inc. and Fidelity Exploration and Production Company operate.
 
 As a result of a reasonably comprehensive geologic and commercial study in 2009, we have high graded three future development and appraisal projects including:
 
 ·
Plateau - This approximate 4,000 acre (gross) project located south of Roan Creek in the Piceance Basin has significant Williams Fork potential.
 ·
Rangely – This 22,000 acre (gross) project located north of the Rangely Field, is prospective for oil in the Lower Mancos (Niobrara) and Dakota formations.
 
 These potential developments will be deferred to at least 2012 as the slow recovery of natural gas prices has caused us to delay the start of investments in Colorado. Exploitation of these opportunities will in all likelihood proceed only after developments at Gibson Gulch, South Rangely and Roan Creek reach equilibrium stage.
 
 Canadian Oil and Gas Properties
 
 Our wholly-owned subsidiary, Dejour Energy (Alberta) Ltd. (“DEAL”), currently has interests in oil and gas properties in the Peace River Arch located principally in northeastern British Columbia.
 
 For fiscal 2010, production from DEAL operated wells averaged about 640 BOE/D (100% gross), comprising of 320 BOPD of oil and natural gas liquids and 1,920 MCFD of gas, an increase of 7% over 2009 production. This was accomplished by successfully drilling two additional oil wells and one gas well during the year.
 
 As at December 31, 2010, DEAL’s holdings approximately 13,000 net acres concentrated in the Peace River Arch.
 
 Drake/Woodrush
 
 2010
 
 After completing a 3-D seismic program over the field in January 2010, we finalized drilling plans and in March commenced drilling of two development wells.  The first found the target Halfway sand tight, but encountered a new Gething Gas pool that was subsequently put on production at more than 1,000 MCFD (100% gross).  The second development well encountered the Halfway sand as expected, was completed and flow tested at rates in excess of 500 BOPD (100% gross).  In October, the first water injection well was drilled to the southeast limit of the reservoir.  This well was produced briefly without the assistance of at 60 BOPD prior to conversion to injection.
 
 With the success of the drilling in March 2010, field production reached a record level in May 2010, averaging 970 BOED (100% gross), where 75% is oil.  In the fourth quarter of 2010, production from the field was reduced to approximately 560 BOED (100% gross) in response to increasing gas production resulting from the decreasing pressure in the Halfway oil sand.  In December 2010, a waterflood project application was expedited and approval was received.   The project was fully implemented in early 2011 with water injection commencing in March 2011.  Water injection will be gradually ramped up to a level of 1,500 to 2,000 BWPD with the resulting oil production expected to reach a peak of approximately 900 BOPD (100% gross) in the second half of 2012.
 
 While some additional development drilling is anticipated, the start-up of the waterflood marks the end of major capital investments in Woodrush.  In 2011 Dejour will concentrate on optimizing injection and production in the waterflood, controlling cost and increasing margins on gas production as the oil production is gradually ramped up to its maximum level in the second half of 2012.
  31
 
 2009
 
 DEAL was the successful bidder for 1,579 net acres of Crown land located adjacent to the northern boundary of the Woodrush lease which was offered for lease in November 2009. The price paid for this acquisition was approximately $340,000.
 
 Late in 2009, we began preparations for a 3-D seismic survey designed to investigate the northern portion of the Woodrush lease and the southern portion of the newly acquired acreage. The survey was shot, processed and interpreted in late 2009/early 2010 with several drilling locations identified. Rigs were contracted and two or three wells are anticipated to be drilled before activity is truncated at time of “break-up” in the water prone areas which overlay the prospective oil and gas deposits.
 
 In late 2009 and prior to the seismic survey, DEAL drilled, sidetracked and suspended an oil and gas well with hydrocarbon shows in several intervals. The well location was based upon previously acquired seismic data.
 
 During 2009, DEAL sold 25% of its interest in Woodrush/Drake for $4,500,000 in cash.  Proceeds from the sale of the interest were used to fund expanded Woodrush/Drake investments and to reduce our outstanding bank line of credit. DEAL’s working interest in Woodrush/Drake was 75% as at December 31, 2009.
 
 Buick Creek (Montney)
 
 In December 2010, we sold our entire 90% interest in this area for net proceeds of approximately $952,000.
 
 Reserve Data
 
 In 2010, GLJ Petroleum Consultants (“GLJ”), independent petroleum engineering consultants based in Calgary, Alberta were retained by to evaluate our Canadian properties. Their report, titled “Reserves Assessment and Evaluation of Canadian Oil and Gas Properties”, is dated March 22, 2011 and has an effective date of December 31, 2010.
 
 Gustavson Associates (“Gustavson”), independent petroleum engineering consultants based in Denver, Colorado were retained by to evaluate our US properties.  Their report, titled “Reserve Estimate and Financial Forecast as to Dejour’s Interests in the Gibson Gulch” is dated March 1, 2011.
 
 The reserves data set forth below (the "Reserves Data"), derived from GLJ and Gustavson’s reports, summarizes our oil, liquids and natural gas reserves.
 
 The GLJ and Gustavson reports are based on certain factual data supplied by us and GLJ and Gustavson's opinion of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to our petroleum properties and contracts (except for certain information residing in the public domain) were supplied by us to GLJ and Gustavson and accepted without any further investigation. GLJ and Gustavson accepted this data as presented and neither title searches nor field inspections were conducted. All statements relating to our activities for the year ended December 31, 2010 include a full year of operating data on our properties.
 
 The reserve estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.  Actual crude oil, natural gas liquids and natural gas reserves may be greater than or less than the estimates provided herein.
 
 Technologies used to determine Proved Reserve Estimate
 
 A variety of methodologies are used by GLJ and Gustavson to determine our proved reserve estimates. These methodologies are consistent with the requirements of the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).  These COGE requires that reserves be assigned only to known hydrocarbon accumulations that have been penetrated by a well bore.  Confirmation of a hydrocarbon accumulation is done by a production or formation test.  The process of reserve estimation falls into three broad methodologies: volumetric, material balance and decline analysis.  Volumetric methods involve the calculation of reservoir rock volume, the hydrocarbons in place in that rock volume, and the estimation of the portion of the hydrocarbons in place that ultimately will be recovered.   Material balance methods of reserves estimation involve the analysis of pressure behavior as reservoir fluids are withdrawn.  Production decline analysis methods of reserves estimation involve the analysis of production behavior as reservoir fluids are withdrawn.
  32
 
 The principal methodologies employed for estimation of our reserves are decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.
 
 Controls Over Reserve Report Preparation
 
 Our reserve report is prepared by our independent qualified reserve evaluators, GLJ and Gustavson. To ensure accuracy and completeness of the data prior to disclosure of reserve estimates to the public, our reserves committee does the following: (1) reviews our procedures for providing information to the independent qualified reserve evaluators, (2) meets with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the qualified reserves evaluators to report without reservation, (3) reviews the reserves data with management and the independent qualified reserves evaluator.  If the reserve committee is satisfied with results of its evaluation it will approve the content of our reserve disclosure.  If any concerns arise in the reserve committee’s evaluation, the reserve committee will work with our management and the independent qualified reserves evaluators to resolve the issues before disclosure of reserves is made public.
 
 As of December 31, 2010, the Company’s reserve committee was composed of: Harrison Blacker, Robert Holmes and Richard Patricio.  Please see “Item 6. Directors, Senior Management and Employees, A. Directors and Senior Management” for biographical information on the members of the reserve committee.
 
 Our reserve estimates are prepared by GLJ and Gustavson. Certificates of Qualification identifying the professional qualifications of the individuals at GLJ and Gustavson who were responsible for overseeing the preparation of our reserve estimates as of December 31, 2010 have been filed as Appendix I to GLJ’s reserve estimate, filed as Exhibit 15.1 to this report and as an addendum to Gustavson Associates reserve estimate, filed as Exhibit 15.2 to this report.
 
 Summary of Oil and Gas Reserves as of Fiscal-Year End Based on Average Fiscal-Year Prices
 
 ReservesReserves Category

Oil

(Mbbl)


Natural Gas

(Mmcf)


Natural Gas

Liquids

(Mbbl)PROVEDDevelopedCanada


74



955



4UndevelopedCanada


92



-19



0United States


326



45,308



0TOTAL PROVED


492



46,244



4
 
 Proved Undeveloped Reserves
 
 Total Proved Undeveloped ReservesOil

(Mbbl)

Natural Gas

(Mmcf)


Natural Gas

Liquids

(Mbbl)418


45,289



0
  33
 
 The significant majority of the undeveloped reserves are scheduled to be developed within the next five years.  Our proved undeveloped reserves decreased by 7 Mbbl of Oil and 14,918 Mmcf of Natural Gas during the fiscal year ended December 31, 2010.  The decrease being primarily reflective of technical revisions to the reserve estimates and not from the conversion of proven undeveloped reserves to developed reserves.
 
 In 2010, we worked closely with important constituents to develop a development plan for the Gibson Gulch area in Colorado, US. The outcome of the development plan confirmed the existence of proved undeveloped reserves in this area. As disclosed in the Gustavson Associates reserve estimate, this plan contemplates drilling would begin in October 2011 with 12 wells being drilled in the 4th quarter 2011, 12 wells drilled in the 3rd quarter 2012, 16 wells per year in 2013 and 2014, and 12 wells per year in 2015.
 
 In 2010, we incurred $228,444 in expenditures for development of undeveloped reserves to convert proved undeveloped reserves into developed reserves.
 
 Reserves Price Sensitivity
 
 Our management uses forward-looking market-based data in developing its drilling plans, assessing its capital expenditure needs and projecting future cash flows.  We believe that using the forecast price yields a better indication of the likely economics of proved reserves than the trailing average 12-month average prices required by the SEC’s reserve rules.
 
 Cautionary Note- The following table contains reserve sensitivity pricing.  Sensitivity pricing is intended to illustrate certain reserve sensitivities to the commodity prices and should not be confused with “SEC Pricing Proved Reserves” and does not comply with SEC pricing assumptions
 
 The table below compares our estimated proved reserves and associated present value (discounted at an annual rate of 10%) of the estimated future revenue before income tax.
 
 December 31, 2010Natural

Gas

(Mmcf)


Oil

(Mbbl)


Total

(Mmcfe)


PV-10(3)

(in thousands)Canada (Proved Developed and Undeveloped Reserves)2010 12-month average prices (SEC) (1)


936



166



1,932


$
2,931Forecast price – GLJ Price Deck (2)


975



179



2,049


$
4,914
 
 December 31, 2010NaturalGas


Oil


Total

PV-10 (3)(Mmcf)


(Mbbl)


(Mmcfe)

(in thousands)United States (Proved Undeveloped Reserves)2010 12-month average prices (SEC) (1)


45,308



326



47,264

US$
26,089Forecast price - NYMEX strip prices (2)


45,308



326



47,264

US$
61,186
 
 December 31, 2010Natural

Gas

(Mmcf)


Oil

(Mbbl)


Total

(Mmcfe)


PV-10 (4)

(in thousands)Total Proved Reserves2010 12-month average prices (SEC) (1)


46,244



492



49,196


$
28,879Forecast price – GLJ Price Deck and NYMEX strip prices (2)


46,283



505



49,313


$
65,770
 
 34
 
 Notes:
 
 (1) The 12-month average prices (SEC) are calculated based on the twelve month average prices during 2010 adjusted for wellhead differential and current costs prevailing at December 31, 2010 and using a 10 percent per annum discount rate as required by the SEC.  The 12-month average prices (SEC) used for Canadian properties were Cdn$69.43 per barrel of oil and Cdn$4.09 per Mcf of natural gas. The 12-month average prices (SEC) used for US properties were US$73.13 per barrel of oil and US$4.54 per Mcf of natural gas.
 
 (2) For Canadian properties, the forecast price is based on the December 31, 2010 price deck by GLJ, an independent reserve evaluator.  The forecast prices used for Canadian properties in 2011 were Cdn$77.42 per barrel of oil and Cdn$4.23 per Mcf of natural gas, escalated to Cdn$89.82 per barrel of oil and Cdn$6.87 per Mcf of natural gas for 2016. The forecast prices for US properties were based on NYMEX futures strips as at December 31, 2010 for WTI (adjusted by the average oil price differential for 2010) and Henry Hub, adjusted by the futures strip for the CIG differential and BTU content.  The forecast prices used for US properties in 2011 are US$87.37 per barrel of oil and US$5.36 per Mcf of natural gas, escalated to US$88.49 per barrel of oil and US$7.66 per Mcf of natural gas for 2022 and onward. Current costs were adjusted for inflations.
 
 (3) Present value of estimated future net cash flows before income taxes (PV-10) is considered a non-GAAP financial measure as defined by the SEC.  We believe that our PV-10 presentation is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account the related future income taxes, as such taxes may differ among various companies because of differences in the amounts and timing of deductible basis, net operating loss carryforwards and other factors.  We believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our proved reserves to the reserve estimates of other companies.  PV-10 is not a measure of financial or operating performance under GAAP and is not intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
 
 (4)  US dollars are converted into Canadian dollars using the closing exchange rate on December 31, 2010, which is US$1.00 = Cdn$0.9946.
 
 Oil and Gas Production, Production Prices and Production Costs
 
 The following is our total net oil and gas production for the fiscal years ended December 31, 2010, 2009 and 2008. All production came from our Canadian properties.  There was no production from our United States properties in the fiscal years ended December 31, 2010, 2009 or 2008.
 
 ProductionFiscal Year Ended

Oil

(bbls)


Natural Gas

(Mcf)


Natural Gas Liquids

(bbls)December 31, 2010


13,386



548,890



305December 31, 2009


72,254



566,158



2,028December 31, 2008


8,058



509,034



764
 
 The following table includes the average prices the Company received for its production for the fiscal years ended December 31, 2010, 2009 and 2008.
 
 Average Sales PricesFiscal Year Ended

Oil

($/bbls)


Natural Gas

($/Mcf)


Natural Gas Liquids

($/bbls)December 31, 2010


67.67



4.22



64.04December 31, 2009


54.67



4.35



52.91December 31, 2008


55.21



9.48



110.90
  35
 
 The following table includes the average production cost, not including ad valorem and serverence taxes, per unit of production for the fiscal years ended December 31, 2010, 2009 and 2008.
 
 Average Production CostsFiscal Year Ended

Oil

($/bbls)


Natural Gas

($/Mcf)


Natural Gas Liquids

($/bbls)December 31, 2010


13.01



2.77



13.01December 31, 2009


23.38



3.11



16.12December 31, 2008


62.09



5.09



43.08
 
 Drilling and Other Exploratory and Development Activities
 
 During the fiscal year ended December 31, 2010, we drilled the following wells:
 
 Net Exploratory Wells


Net Development WellsCanada

Productive


Dry


Productive


DryOil


-



-



1.50



-Natural Gas


0.75



-



-



-Dry Wells


-



-



-



-Service Wells


-



-



-



-Suspended


-



-



-



-Total  Wells


0.75



-



1.50



-
 
 During the fiscal year ended December 31, 2009, we drilled the following wells:
 
 Net Exploratory Wells


Net Development WellsCanada

Productive


Dry


Productive


DryOil


-



-



-



-Natural Gas


0.75



-



-



-Dry Wells


-



-



-



-Service Wells


-



-



-



-Suspended


-



-



-



-Total  Wells


0.75



-



-



-
 
 During the fiscal year ended December 31, 2008, the Company drilled the following wells:
 
 Net Exploratory Wells


Net Development WellsCanada

Productive


Dry


Productive


DryOil


2



-



-



-Natural Gas


1.65



-



2.84



-Dry Wells


-



0.7



-



-Service Wells


-



-



-



-Suspended


-



2



-



-Total  Wells


3.65



2.7



2.84



-
  36
  Present Activities
 
 The following table discloses the Company’s present drilling activities as of June 21, 2011.
 
 Wells Being Drilled as of June 21, 2011Gross


NetCanadaOil


-



-Natural Gas


-



-United StatesOil


1



0.5Natural Gas


-



-Total Wells


1



0.5
 
 Delivery Commitments
 
 We have no current delivery commitments for either oil or natural gas.
 
 Oil and Gas Properties, Wells, Operations and Acreage
 
 As of December 31, 2010, we had 9 gross (6.63 net) producing oil or natural gas wells.
 
 Oil


Natural GasCanada

Gross


Net


Gross


NetProducing


3



2.25



3



2.19Shut-In


-



-



3



2.19TOTAL


3



2.25



6



4.38
 
 Our landholdings as of December 31, 2010 were as follows:
 
 Undeveloped

(Acres)


Developed

(Acres)


Total

(Acres)Gross


Net


Gross


Net


Gross


NetColorado/Utah, US


225,549



109,439



-



-



225,549



109,439Canada


24,250



8,756



8,178



4,939



32,428



13,695
 
 Uranium Properties
 
 In 2009, we disposed of all of our 16,750,000 shares in Titan Uranium inc. for proceeds of $2,305,491. We have 10% carried interest and 1% Net Smelter Return on certain uranium exploration leases in Saskatchewan operated by Titan Uranium Inc. However, we no longer maintain the right of first refusal on future financings, is no longer required to provide geologists to Titan, and its representatives have since resigned from the Titan Board of Directors.
  37
  ITEM 4A.   UNRESOLVED STAFF COMMENTS
 
 Not Applicable.
 
 ITEM 5.  OPERATING AND FINANCIAL REVIEW AND PROSPECTS
 
 The following is a discussion of our consolidated operating results and financial position, including all our wholly-owned subsidiaries.  It should be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2010 and related notes included therein under the heading "Item 18. Financial Statements" below.
 
 All financial information in this Item 5 is expressed and prepared in accordance with the Canadian generally accepted accounting principles ("Canadian GAAP") and all references are in Canadian dollars unless otherwise noted. Some numbers in this Item 5 have been rounded to the nearest thousand for discussion purposes.  Reference is made to Note 21 of our  audited consolidated financial statements as at December 31, 2010 and for the years ended December 31, 2010, 2009 and 2008  included herein for a discussion of the material measurement differences between Canadian GAAP and United States Generally Accepted Accounting Principles (“U.S. GAAP”), and their effect on our financial statements.
 
 Certain forward-looking statements are discussed in this Item 5 with respect to our activities and future financial results. These are subject to risks and uncertainties that may cause projected results or events to differ materially from actual results or events.  Readers should also read the "Cautionary Note Regarding Forward-Looking Statements" above and “Item 3. Key Information - Risk Factors.”
 
 Critical Accounting Policies
 
 There are a number of critical estimates underlying the accounting policies we apply in preparing our financial statements.
 
 Reserves
 
 The estimates of reserves is used in forecasting what will ultimately be recoverable from the properties and their economic viability and in calculating the our depletion and potential impairment of asset carrying costs. The process of estimating reserves is complex and requires significant interpretation and judgment. It is affected by economic conditions, production, operating and development activities, and is performed using available geological, geophysical, engineering and economic data.
 
 Reserves at year end are evaluated by independent engineering firm and quarterly updates to those reserves, if any,
 are estimated by us.
 
 Amortization, Depletion and Accretion
 
 We estimate amortization, depletion and accretion that are based on estimates of oil and gas reserves that we expect to recover in the future.
 
 Revenue and Cost Estimates
 
 We estimates revenues, royalties and operating costs on production as at a specific reporting date, but for which actual revenues and costs have not yet been received.
 
 Asset Retirement Obligations
 
 The liability recorded for asset retirement obligations, an estimate of restoring assets and locations back to environmental and regulatory standards upon future retirement or abandonment, include estimates of restoration costs to be incurred in the future and an estimated future inflation rate. Costs estimated are based upon internal and third party calculations and historical experience and future inflation rates are estimated using historical experience and available economic data.
  38
 
 Income Taxes
 
 We record future tax liabilities to account for the expected future tax consequences of events that have been recorded in our financial statements. These amounts are estimates; the actual tax consequences may differ from the estimates due to changing tax rates and regimes, as well as changing estimates of cash flow and capital expenditures in current and future periods. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded.
 
 Recently Adopted Accounting Policies
 
 On January 1, 2010, we adopted the following Canadian Institute of Chartered Accountants (“CICA”) Handbook sections:
 
 ·
Business Combinations, Section 1582, which replaces the previous business combinations standard. The standard requires assets and liabilities acquired in a business combination, contingent consideration and certain acquired contingencies to be measured at their fair values as of the date of acquisition. In addition, acquisition related and restructuring costs are to be recognized separately from the business combination and included in the statement of earnings. The adoption of this standard will impact the accounting treatment of future business combinations entered into after January 1, 2010.
 
 ·
Consolidated Financial Statements, Section 1601, which, together with Section 1602 below, replace the former consolidated financial statements standard. Section 1601 establishes the requirements for the preparation of consolidated financial statements. The adoption of this standard had no material impact on our consolidated financial statements.
 
 ·
"Non-controlling Interests", Section 1602, which establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The standard requires a non-controlling interest in a subsidiary to be classified as a separate component of equity. In addition, net earnings and components of other comprehensive income are attributed to both the parent and non-controlling interest. The adoption of this standard has had no material impact on our consolidated financial statements.
 
 Future Accounting Pronouncements
 
 International Financial Reporting Standards (“IFRS”)
 
 In February 2008, the CICA Accounting Standards Board (“AcSB”) confirmed the use of IFRS for publicly accountable profit-oriented enterprises beginning on January 1, 2011 with appropriate comparative data from the prior year. IFRS will replace GAAP for those enterprises, including listed companies and other profit-oriented enterprises that are responsible to large or diverse groups of stakeholders.
 
 We commenced our IFRS project in 2009. This project consists of four phases: diagnostic; design and planning; solution development; and integration. We have completed the diagnostic phase, which involved a high-level review of the major differences between current GAAP and IFRS. We have determined that the areas of accounting differences with the highest potential impact to us are accounting for the exploration and evaluation of oil and gas resources, property, plant and equipment, and asset impairment testing, as well as accounting for stock-based compensation, derivative financial instruments, foreign currency translation and income taxes.
 
 In 2010, we completed the design and planning phase of the project, which involves documenting the high impact areas identified and evaluating the different accounting policy options available under IFRS. During this phase, we also assessed the impact the changeover will have on current policies and procedures, information technology and accounting systems, as well as internal controls.
  39
 
 During the last quarter of 2010, we addressed the solution development phase, which involves the selection and documentation of IFRS accounting policies and procedures, as well as the development of accounting systems to enable us to track and report the financial information required to prepare financial statements under IFRS.
 
 Our interim consolidated financial statements for the three months ended March 31, 2011 have been prepared in accordance with IAS 34 “Interim Financial Reporting”, and as they are part of the Company’s first IFRS annual reporting period, IFRS 1 “First-time Adoption of International Financial Reporting Standards” has been applied.
 
 Expected Accounting Policy Impacts
 
 Our significant areas of impact continue to include property, plant and equipment (“PP&E”), impairment testing. These areas of impact have the greatest impact to our financial statements. The following discussion provides an overview of these areas, as well as the exemptions available under IFRS 1, First-time Adoption of International Financial Reporting Standards. In general, IFRS 1 requires first time adopters to retrospectively apply IFRS, although it does provide optional and mandatory exemptions to these requirements.
 
 Property, Plant and Equipment
 
 Under Canadian GAAP, we follow the CICA’s guideline on full cost accounting in which all costs directly associated with the acquisition of, the exploration for, and the development of natural gas and crude oil reserves are capitalized on a country-by-country cost centre basis. Costs accumulated within each country cost centre are depleted using the unit-of-production method based on proved reserves determined using estimated future prices and costs. Upon transition to IFRS, we are required to adopt new accounting policies for upstream activities, including pre-exploration costs, exploration and evaluation costs and development costs. Pre-exploration costs are those expenditures incurred prior to obtaining the legal right to explore and must be expensed under IFRS. In 2009 and 2010, we capitalized and depleted pre-exploration costs within the country cost centre. These costs were not material to us.
 
 Exploration and evaluation costs are those expenditures for an area or project for which technical feasibility and commercial viability have not yet been determined. Under IFRS, we initially capitalize these costs as Exploration and Evaluation assets on the balance sheet. When the area or project is determined to be technically feasible and commercially viable, the costs will be transferred to PP&E. Unrecoverable exploration and evaluation costs associated with an area or project will be expensed.
 
 Development costs include those expenditures for areas or projects where technical feasibility and commercial viability have been determined. Under IFRS, we continue to capitalize these costs within PP&E on the balance sheet. However, the costs were depleted on a unit-of-production basis over an area level (unit of account) instead of the country cost centre level utilized under Canadian GAAP.
 Under IFRS, upstream divestures generally result in a gain or loss recognized in net earnings. Under Canadian GAAP, proceeds of divestitures were normally deducted from the full cost pool without recognition of a gain or loss unless the deduction would result in a change to the depletion rate of 20 percent or greater, in which case a gain or loss was recorded.
 
 We have adopted the IFRS 1 exemption, which allows the Company to deem its January 1, 2010 IFRS upstream asset costs to be equal to its Canadian GAAP historical upstream net book value. On January 1, 2010, the IFRS exploration and evaluation costs are equal to the Canadian GAAP unproved properties balance and the IFRS development costs are equal to the full cost pool balance. We have allocated this upstream full cost pool over reserves to establish the area level depletion units.
  40
 
 Impairment
 
 Under Canadian GAAP, we were required to recognize an upstream impairment loss if the carrying amount exceeds the undiscounted cash flows from proved reserves for the country cost centre. If an impairment loss is to be recognized, it was then measured at the amount the carrying value exceeds the sum of the fair value of the proved and probable reserves and the costs of unproved properties.
 
 Under IFRS, we are required to recognize and measure an upstream impairment loss if the carrying value exceeds the recoverable amount for a cash-generating unit. Under IFRS, the recoverable amount is the higher of fair value less cost to sell and value in use. Impairment losses, other than goodwill, are reversed under IFRS when there is an increase in the recoverable amount. We have grouped our upstream assets into cash-generating units based on the independence of cash inflows from other assets or other groups of assets.
 
 Stock-Based Compensation
 
 Under IFRS, stock-based compensation is recognized based on a graded vesting schedule rather than the straightline method utilized by us under Canadian GAAP. The difference calculated using the two methods for options that were not fully vested on the transition date must be recorded in retained earnings.
 
 IFRS requires that each tranche of options is required to be treated as a separate award with a separate life. We have recognized an increase in the stock-based compensation expense in the vesting periods immediately following new grants. In addition, under IFRS, a forfeiture rate must be included in the initial expense calculation and adjusted prospectively if required, rather than accounting for forfeitures as they occur.
 
 Derivative Financial Instruments
 
 Under IFRS, derivative financial instruments are classified as equity or financial liabilities in accordance with their contractual substance. A financial instrument should be classified as either a financial liability or an equity instrument according to the substance of the contract, not its legal form, and the definitions of financial liability and equity instrument. We must decide at the time the instrument is initially recognized. The classification is not subsequently changed based on changed circumstances. An instrument is an equity instrument if, and only if, it satisfies the fixed-for-fixed test. If the instrument passes the test, it is accounted for as equity. If the instrument fails
 the test, it is a financial liability and is accounted for at fair value through profit or loss.
 
 Under Canadian GAAP, common share purchase warrants were classified as equity. It defines an equity instrument as any contract that evidences a residual interest in the assets of an entity after deducting all of its liabilities. There was no requirement under Canadian GAAP for the warrants to satisfy the fixed-for-fixed test.
 
 Based on the analysis of IFRS requirements, we determined that the warrants denominated in foreign currency outstanding at the date of transition must be treated as derivative liabilities in our statement of financial position. Any issuance costs related to the warrants denominated in foreign currency are expensed upon initial issuance. Prospectively, these warrants were re-measured at each balance sheet date based on estimated fair value, and resultant changes in far value have been recorded as non-cash valuation adjustments as income or expense in the respective period.
 
 Foreign Currency Translation
 
 IFRS 1 allows companies to reset their existing cumulative translation account (“CTA”) balances to zero at the date of transition. At present, we do not have any CTA balance. In addition, IFRS uses a hierarchy of indicators unlike Canadian GAAP to determine the functional currency. The functional currency of entities within the consolidated group could potentially be determined to be one other than the reporting currency which would result in the need for changes in the configuration of the consolidation systems. Under IFRS, a reporting currency other than the functional currency can be used in the reported financial statements. We have reviewed the functional currency assessment using the IFRS hierarchy and determined that the functional currency of its US subsidiary is not the same as our reporting currency. Therefore, we are required to translate the US subsidiary in line with the IFRS requirements retrospectively.
  41
 
 Income Taxes
 
 Canadian GAAP and IFRS follow the liability method of accounting for income taxes, where tax assets and liabilities are recognized on temporary differences. However, there are certain exceptions to the treatment of temporary differences under IFRS that may result in an adjustment to our future tax liability under IFRS. In addition, our future tax liability will be affected by the tax effects of any changes noted in the above areas. Currently, there are no specific impacts of these differences on our financial statements.
 
 A.           Operating Results
 
 Fiscal Year Ended December 31, 2010 Compared to Fiscal Year Ended December 31, 2009
 
 Revenues
 
 For the year ended December 31,2010


2009RevenueNatural gas

$
2,265,000


$
2,413,000Oil and natural gas liquids


5,821,000



4,058,000Total oil and gas revenue


8,086,000



6,471,000Realized financial instrument gain


68,000



315,000Total revenue

$
8,154,000


$
6,786,000
  For the year ended December 31, 2010 (“fiscal 2010”), the Company recorded $5,821,000 in crude oil and natural gas liquids sales and $2,265,000 in natural gas sales as compared to $4,058,000 in crude oil and natural gas liquids sales and $2,413,000 in natural gas sales for the year ended December 31, 2009 (“fiscal 2009”). The increase in revenues was due to the three new wells came on production in the current year. However, this was partly offset by the result of disposition of 100% interest in the Carson Creek and 25% interest in the Drake/Woodrush properties in
 2009.
 
 The following table summarizes the commodity prices realized by the Company and the crude oil and natural gas benchmark prices for the years ended December 31, 2010 and 2009:
 
 For the year ended December 31,2010


2009Dejour Average PricesNatural gas ($/mcf)

$
4.13


$
4.35Oil and natural gas liquids ($/bbl)


67.46



54.63Total average price ($/boe)

$
45.53


$
38.92Average Benchmark PricesWestern Canadian Select (WCS) ($/bbl)

$
67.25


$
58.69Natural gas - AECO-C Spot ($ per mcf)

$
4.13


$
4.14
 
 Both the average natural gas sales prices and AECO-C daily spot prices for fiscal 2010 were comparable to the prices received for the comparative year. Oil prices received for fiscal 2010 increased to $67.46 per barrel (“bbl”), compared to $54.63 per bbl for fiscal 2009. The increase was due to the gradual recovery of the global economic market, leading to higher commodity prices.
  42
 
 Operating and Transportation Expenses
 
 Operating and transportation expenses include all costs associated with the production of oil and natural gas and the transportation of oil and natural gas to the processing facility. The major components of operating expenses include labour, equipment maintenance, workovers, fuel and power. Operating and transportation expenses for fiscal 2010 decreased to $2,605,000 or $14.67 per BOE from $2,915,000 or $17.55 per BOE for fiscal 2009 despite higher revenues.
 
 Operating costs on a per unit basis decreased compared to fiscal 2009, reflecting the addition of production from three new wells in Woodrush and the positive impact to the Company’s operations as a result of the installation of the rental compressor, which lowered the ongoing compression costs and operating costs. The Company incurred approximately $220,000 for the installation in January 2010.
 
 General and Administrative Expenses
 
 General and administrative expenses decreased to $3,424,000 for fiscal 2010 from $4,038,000 for fiscal 2009. The decrease was primarily due to lower salaries and benefits, consulting and professional fees, and other general overhead for fiscal 2010 compared to fiscal 2009.
 
 Interest Expense and Finance Fee
 
 For fiscal 2010, the Company recorded interest expense and finance fee of $1,075,000, compared to $818,000 for fiscal 2009. The increase was due to the interest expense and finance fee associated with the utilization of the credit facility from a bridge loan lender since March 2010.
 
 Stock Based Compensation
 
 For fiscal 2010, the Company recorded non-cash stock based compensation expense of $620,000 compared to $697,000 for fiscal 2009. The decrease in stock based compensation expense was because many of the stock options previously granted had been fully vested.
 
 Foreign Exchange Gain (Loss)
 
 Foreign exchange gain for fiscal 2010 decreased by $285,000 compared to fiscal 2009. At the end of 2008, the Company had a US dollar denominated loan of $3.8 million from a related party and recorded a foreign exchange gain of $257,000 for fiscal 2009 as a result of the lower US-Canadian exchange rate and the positive impact it had on the loan. In June 2009, the loan was converted into a Canadian dollar denominated loan and no foreign currency revaluation was necessary for the current year.
 
 Impairment of Oil & Gas Properties
 
 The impairment loss of oil and gas properties for fiscal 2010 is $Nil, compared to $5,360,000 for fiscal 2009. The Company recorded an impairment loss of $3,956,000 for the excess of the carrying value of Canadian oil and gas properties over its fair value as at December 31, 2009 based on an independent reserve evaluation report. In addition, during fiscal 2009, the Company wrote off certain non-core acreages in the US that expired before determining proved reserves effective December 31, 2009 in March 2010 and recorded an impairment loss of $1,404,000.
 
 Amortization, Depletion and Accretion
 
 For fiscal 2010, amortization and depletion of property and equipment and accretion of asset retirement obligations was $5,250,000 compared to $6,437,000 for fiscal 2009. The decrease was due to the positive drilling results during the current year, which increased reserves in the Drake/Woodrush area at the end of December 31, 2010. This was partly offset by the increase in production.
  43
 
 Income Taxes
 
 Future income tax recovery for fiscal 2010 was $968,000, as compared to future income tax recovery of $1,133,000 for fiscal 2009. The future income tax recovery for fiscal 2010 was a result of the Company’s renunciation of $3,394,000 of Canadian Exploration Expenditures (“CEE”) to investors in 2010. Under Canadian GAAP, the renunciation of CEEs results in future income tax liabilities and share issuance costs. The Company’s previously unrecognized future income tax assets relating to loss carry forwards were offset against future income tax liabilities from the renunciation of CEEs, resulting in future income tax recoveries.
 
 As at December 31, 2009, the Company had unrecognized future income tax assets relating to loss carry forwards and the excess of the value of the tax pools for the oil and gas properties over the accounting net book value, as compared to having a future income tax liability balance as at December 31, 2008, which resulted in future income tax recovery for fiscal 2009.
 
 Net Loss
 
 The Company’s net loss for fiscal 2010 was $5,165,000 or $0.05 per share, compared to a net loss of $12,807,000, or $0.16 per share for fiscal 2009. The decrease in net loss was due to higher revenues and lower depletion expenses and general and administrative expenses. In addition, the decrease in net loss was attributable to no impairment of oil and gas properties recorded for the current year.
 
 Fiscal Year Ended December 31, 2009 Compared to Fiscal Year Ended December 31, 2008
 
 Revenues
 December 31,


December 31,2009


2008RevenueNatural gas

$
2,413,026


$
4,962,614Oil


3,964,512



703,167Natural gas liquids


93,187



99,774Total oil and gas revenue


6,470,725



5,765,555Realized financial instrument gain


315,270



-Total revenue

$
6,785,995


$
5,765,555
 
 For the year ended December 31, 2009 (“fiscal 2009”), the Company recorded $4,058,000 in crude oil and natural gas liquids sales and $2,413,000 in natural gas sales as compared to $803,000 in crude oil and natural gas liquids sales and $4,963,000 in natural gas sales for the year ended December 31, 2008 (“fiscal 2008”).  In 2008, the Company only had nine months of production, as the Company commenced production in April 2008.
 
 Operating and Transportation Expenses
 
 Operating and transportation expenses include all costs associated with the production of oil and natural gas and the transportation of oil and natural gas to the processing plants.  The major components of operating expenses include labour, equipment maintenance, workovers, fuel and power.  Operating and transportation expenses for fiscal 2009 were $2,915,000 as compared to $1,973,000 for fiscal 2008.  The increase in total expenses was primarily due to higher production volume.
 
 General and Administrative Expenses
 
 General and administrative expenses decreased to $4,038,000 for fiscal 2009 from $4,215,000 for fiscal 2008.  The decrease was primarily due to the reduction of $570,000 and $186,000 in investor relation expenses and travel expenses respectively.  During the year, the Company restructured the Calgary office and reduced overhead.  Offsetting the costs reduction in 2009 was an increase in legal fees to settle a termination claim litigation cost from a former officer and director and some restructuring charges.
  44
 
 Interest and Finance Fees
 
 For fiscal 2009, the Company recorded interest and finance fees of $818,000, compared to $481,000 for fiscal 2008.  The increase is due to higher loan fee and interest paid to bank on its revolving operating loan facility obtained in August 2008 and loan interest paid to Brownstone Ventures Inc.  The loan was obtained from Brownstone in June 2008 to acquire additional acreage in the US property.
 
 Amortization, Depletion and Accretion
 
 For fiscal 2009, amortization and depletion of property and equipment and accretion of asset retirement obligations was $6,437,000 compared to $3,691,000 for fiscal 2008. The increase was due to the commencement of oil and gas production in April 2008.
 
 Stock Based Compensation
 
 For fiscal 2009, the Company recorded non-cash stock based compensation expense of $697,000 compared to $2,720,000 for fiscal 2008.  The decrease in stock based compensation expense was because many of the stock options previously granted had been fully vested.
 
 Income Taxes, Foreign Exchange Gain (Loss) and Other Items
 
 Future income tax recovery for fiscal 2009 was $1,133,000, as compared to future income tax expenses of $596,000 for fiscal 2008.  As at December 31, 2009, the Company had unrecognized future income tax assets relating to loss carry forwards and the excess of the value of the tax pools for the oil and gas properties over the accounting net book value, as compared to having a future income tax liability balance as at December 31, 2008, which resulted in future income tax recovery for the current fiscal year.
 
 At the end of 2008, the Company had a US$3,800,000 loan from a related party.  Due to the decline in the value of US$, foreign exchange gain in 2009 was $257,000 compared to a foreign exchange loss of $676,000 in 2008.
 
 Impairment of Oil & Gas Properties
 
 The impairment loss of oil and gas properties for fiscal 2009 totaled $5,360,000, compared to $2,030,000 in 2008.  During 2009 and 2008, the Company wrote off certain non-core acreages in the US that expired and recorded an impairment loss of $1,404,000 and $2,030,000 respectively.
 
 In addition, the Company recorded an impairment loss of $3,956,000 related to the excess of the carrying value of Canadian oil and gas properties over its fair value as at December 31, 2009 based on an independent reserve evaluation report.  Most of the impairment of carrying relates to non-core assets that were abandoned or sold.
 
 Subsequent to the 2009 year-end, the Company drilled two successful wells, which were not included in the December 31, 2009 reserve evaluation report for determining the fair value of Canadian oil & gas properties.
 
 Net Loss
 
 The Company’s net loss for fiscal 2009 was $12,807,000 or $0.16 per share, compared to a net loss of $20,891,000, or $0.29 per share for fiscal 2008.  In 2008, the Company had a non-cash impairment loss of $12,990,000 on investment in Titan, offset by an equity income from Titan of $3,637,000.  In 2009, the Company disposed of all its investment in Titan and equity loss was only $142,000.  The equity loss from Titan relates to the Company’s proportionate share of Titan’s loss in the year.
  45
  Foreign Currency Fluctuations
  Foreign currency exchange rate risk is the risk that the fair value of financial instruments or future cash flows will fluctuate as a result of changes in foreign exchange rates.  Although substantially all of our oil and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for oil and natural gas are impacted by changes in the exchange rate between the Canadian and United States dollars.  Given that changes in exchange rate have an indirect influence, the impact of changing exchange rates cannot be accurately quantified.  We had no forward exchange rate contracts in place as at or during the year ended December 31, 2010.
 
 We were exposed to the following foreign currency risk at December 31, 2010:
 
 Expressed in foreign currencies - 2010

USDCash and cash equivalents

$
604,785Accounts receivable


169,687Accounts payable and accrued liabilities


(228,767
)Balance sheet exposure

$
545,705
 
 The following foreign exchange rates applied for the year ended and as at December 31, 2010:
 
 YTD average USD to CAD


0.9946December 31, reporting date rate


1.0305
 
 We have performed a sensitivity analysis on its foreign currency denominated financial instruments. Based on our reign currency exposure noted above and assuming that all other variables remain constant, a 10% appreciation of the following currencies against the Canadian dollar would result in the decrease of net loss of $54,276 at December 31, 2010. For a 10% depreciation of the above foreign currencies against the Canadian dollar, assuming all other variables remain constant, there would be an equal and opposite impact on net loss.
 
 B.           Liquidity and Capital Resources
 
 Cash Balance and Cash Flow
 
 The Company had cash and cash equivalents of $4,758,000 as at December 31, 2010. In addition to the cash balance, the Company also had accounts receivable of $689,000, most of which related to December 2010 oil and gas sales and had been received subsequent to December 31, 2010.
 
 Our investing activities during the year ended December 31, 2010 were financed primarily by the proceeds raised from the issuance of flow-through shares and draw down of bridge loan during the year.
 
 Bank Line of Credit and Bridge Loan Financing
 
 During the year ended December 31, 2010, the bank line of credit of $850,000 was paid off in full in cash. In March 2010, the Company negotiated a credit facility for a bridge loan of up to $5,000,000. This facility is secured by a first floating charge over all assets of DEAL, bears interest at 12% per annum and was due September 22, 2010 but was extended to March 31, 2011. By agreement, certain terms of the facility were amended such that the credit limit is reduced by $100,000 per month and the Company is required to make monthly principal payments of $100,000 commencing November 30, 2010 with the borrowing subject to the drawdown fee adjusted to 2% from 1% on any amounts drawn and the deferred fee lowered to 1% from 2% on any repayments with no change in interest rate. Additionally, the due date of bridge loan is extended to March 31, 2011 and can be further extended for a maximum of 3 months subject to a 1% extension fee per month on the outstanding loan balance. In March 2011, the lender approved to extend the due date of the loan to April 30, 2011 and in April 2011, the Company extended the credit facility to October 31, 2011 and can be further extended for a maximum of 3 months subject to a 1% extension fee per month on the outstanding loan balance and lender’s approval. Monthly repayment of $100,000 is required beginning May 31, 2011. This facility is used to support the development of its oil and gas properties in the Drake/Woodrush area. As at May 31, 2011, the outstanding balance of this credit facility was $4,400,000.
 During the year ended December 31, 2010, the Company made monthly principal payment of $100,000 and reduced the outstanding balance to $4,800,000. This facility is used to support the development of its oil and gas properties in the Drake/Woodrush area.
  46
 
 According to the terms of the facility, the Company is required to maintain (a) a working capital ratio of not less than 1:1; (b) a debt to equity ratio within 0.5:1; and (c) a debt to trailing cash flow ratio within 2.5:1. The working capital ratio is defined as the ratio of (i) current assets (including any undrawn and authorized availability under the facility as cash) to (ii) current liabilities (excluding outstanding balances of the facility unless past due). The debt to equity ratio is defined as the ratio of (i) debt (secured debt plus working capital deficit or minus working capital surplus) to (ii) equity (shareholder equity plus retained earnings or minus deficit plus formally postponed shareholder and related party advances). The debt to trailing cash flow ratio is defined as the ratio of (i) debt (secured debt plus working capital deficit or minus working capital surplus) to (ii) cash flow (net income plus all non-cash charges). As at December 31, 2010, the Company is in compliance with all covenants.
 
 Working Capital Position
 
 As at December 31, 2010, the Company had a working capital deficit of to $1,984,000. The working capital deficit mainly consisted of loans from related parties and bridge loan drawn during the year ended December 31, 2010. The Company plans to remedy the deficiency through the following:
 
 ·
Subsequent to December 31, 2010, the Company completed an equity financing of 11,010,000 units and raised net proceeds of approximately US$3.1 million.
 
 ·
In December 2010, the Company obtained the approval for the implementation of a waterflood program at the Drake/Woodrush properties. In March 2011, the Company completed waterflood construction and commenced water injection. This waterflood is expected to increase the oil production and revenue gradually during the remainder of 2011.
 
 ·
The Company intends to obtain a new credit facility to refinance or extend the existing bridge loan, using a new reserve evaluation on its Woodrush property.
 
 ·
If necessary and at the right market conditions, the Company may fund its working capital through additional debt, equity or disposal of non-core asset or a combination of both.
 
 Capital Resources
 
 Subsequent to December 31, 2010, the Company completed an equity financing of 11,010,000 units at US$0.30 per unit. Each unit consists of one common share and one-half of one common share purchase warrant. Each whole warrant entitles the holder to acquire one additional common share of the Company. Net proceeds raised were US$3.1 million.
 
 During the remainder of 2011, the Company plans to optimize the waterflood at Drake/Woodrush in Canada. A significant portion of the waterflood capital expenditures were spent prior to Q1 2011. The Company’s share of waterflood capital expenditures for the remaining of 2011 is approximately $1.2 million. Also, the Company plans to drill wells at Gibson Gulch and South Rangely in the US.
 
 The Company plans to fund the development programs through a combination of debt, equity or joint ventures.
 
 C.           Research and Development, Patents and Licenses, Etc.
 
 None.
  47
 
 D.           Trend Information
  During 2009, commodity prices stabilized from the historic volatility experienced during 2008. With oil currently near $80 per barrel, drilling activity in certain areas, including near our operating areas, has increased over the low activity we experienced in early 2009. Currently, qualified employees are available; however the Company still must compete for employees within our industry. Some or all of these situations are likely to have a material effect upon our net sales or revenues, income from continuing operations, profitability, liquidity or capital resources, or cause reported financial information not necessarily to be indicative of future operating results or financial condition.
  E.           Off-Balance Sheet Arrangements
 
 As of June 21, 2011, The Company does not have any material off balance sheet arrangements that have or are reasonably likely to have a current or future effect on the Company’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
 
 F.           Tabular Disclosure of Contractual Obligations
 
 As of December 31, 2010, and in the normal course of business the Company has obligations to make future payments, representing contracts and other commitments that are known and committed.
 
 Contractual Obligations(in thousands of dollars)

2011


2012


2013


2014


2015

Thereafter

Total$


$


$


$


$

$

$Operating Lease Obligations


216



152



73



49



-

Nil


490Bridge LoanPrincipal


4,800



-



-



-



-

Nil


4,800Estimated Interests


576



-



-



-



-

Nil


576Loan From Related PartyPrincipal


250



-



-



-



-

Nil


250Interests


2



-



-



-



-

Nil


2Total


5,844



152



73



49



-

Nil


6,118
 
 G.           Safe Harbor
 
 The Company seeks safe harbor for our forward-looking statements contained in Items 5.E and F.  See the heading “Cautionary Note Regarding Forward-Looking Statements” above.
 
 ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
 
 A.           Directors and Senior Management
 
 The following table sets forth all current directors and executive officers of Dejour as of the date of this annual report on Form 20-F, with each position and office held by them in the Company and the period of service as such.
 
 Name, Jurisdiction of

Residence and

Position(1)

Principal occupation or

employment during the past 5

years

Number of Dejour

Common Shares

beneficially owned,

directly or indirectly,

or controlled or

directed(2)


Percentage of

Dejour Common

Shares beneficially

owned, directly or

indirectly, or

controlled or

directed(2)


Director

SinceRobert L. Hodgkinson

British Columbia, Canada

Director, Chairman and Chief Executive Officer

(Age: 61)

President of a private company, Hodgkinson Equities Corporation, which provides consulting services to emerging businesses in the petroleum resource industry. Currently a Director of Royce Resources (TSX-V:ROY-H), and a former director of Titan Uranium (TSX-V:TUE).


7,187,840



5.9
%

May 18/04
  48
 
 Name, Jurisdiction of

Residence and

Position(1)

Principal occupation or

employment during the past 5

years

Number of Dejour

Common Shares

beneficially owned,

directly or indirectly,

or controlled or

directed(2)


Percentage of

Dejour Common

Shares beneficially

owned, directly or

indirectly, or

controlled or

directed(2)


Director

SinceStephen Mut

Colorado, USA

Director and Co-Chairman

(Age: 60)

Mr. Mut has served as CEO of Nycon Energy Consulting since his retirement from Shell in mid 2009. At Shell, Mr. Mut is served as chief executive officer of a unit of Shell Exploration and Production Company from 2000 until his retirement in 2009. Prior to that, Mr. Mut served in various executive roles at ARCO (Atlantic Richfield Company).


1,611,001



1.3
%

Dec 17/09Harrison Blacker(4)

Colorado, U.S.A. Director, President and Chief Operating Officer of Dejour Energy (USA) Inc.

(Age: 60)

President of Dejour Energy (USA) Inc. since April 2008. Over 30 years of expertise managing oil and gas operations. Held the positions of Chief Executive Officer with China Oman Energy Company and Portfolio Manager, Latin American Business Unit and General Manager/ President of Venezuela Energy with Atlantic Richfield Corporation (ARCO) prior to joining Dejour USA.


525,678



0.4
%

Apr 2/08Richard Patricio(4)

Ontario, Canada

Director

(Age: 37)

Vice President of Corporate & Legal Affairs and Secretary of Pinetree Capital Ltd. (investment and merchant banking firm). Prior to joining Pinetree Capital, practiced law at a top tier law firm in Toronto and worked as in-house General Counsel for a senior TSX listed company. Mr. Patricio is a lawyer qualified to practice in the Province of Ontario.


10,300,946



8.5
%

Oct 17/08RobertHolmes(3) , (4)

California, U.S.A

Director

(Age: 67)

Began career as an Investment Executive with Merrill, Lynch, Pierce, Fenner & Smith, and held various senior executive positions with the firm Blyth, Eastman, Dillon & Company.  In 1980, co-founded Gilford Securities, Inc., a member of the NYSE, and in 1992 founded a hedge fund, Gilford Partners.  Has served on several boards including the North Central College Trustees in Naperville, IL; Board of Trustees Sacred Heart Schools Chicago; Crested Butte Academy in Crested Butte, CO; and Mary Wood Country Day School in Rancho Mirage, CA.


1,663,000



1.4
%

Oct 17/08
  49
 
 Name, Jurisdiction of

Residence and

Position(1)

Principal occupation or

employment during the past 5

years

Number of Dejour

Common Shares

beneficially owned,

directly or indirectly,

or controlled or

directed(2)


Percentage of

Dejour Common

Shares beneficially

owned, directly or

indirectly, or

controlled or

directed(2)


Director

SinceCraig Sturrock (3)

British Columbia, Canada

Director

(Age: 67)

Tax lawyer since 1971.  Currently, he is a partner at Thorsteinssons LLP, and his practice focuses primarily on civil and criminal tax litigation.


650,000



0.5
%

Aug 22/05Darren Devine(3)

British Columbia, Canada

Director

(Age: 43)

Since 2003, Mr. Devine has been the principal of Chelmer Consulting Corp., a corporate finance consultancy. Prior to founding Chelmer Consulting, Mr. Devine practiced law with the firm of Du Moulin Black LLP, in Vancouver, British Columbia. Mr. Devine is a qualified Barrister and Solicitor in British Columbia, and a qualified solicitor in England and Wales.


-



-


Dec 17/09Mathew Wong

British Columbia, Canada

Chief Financial Officer

(Age: 36)

Chartered Accountant worked at Ernst & Young LLP from 1995 to 2000.  Since then, he worked as the Corporate Accounting Manager for Mitsubishi Canada Limited and CFO for Dejour Enterprise Ltd.  Mr. Wong is a Chartered Accountant (CA) in British Columbia of Canada, a Certified Public Accountant (CPA) of Washington State, USA and a Chartered Financial Analyst (CFA).


122



-


N/A
 
  50
 
 Name, Jurisdiction of

Residence and

Position(1)

Principal occupation or

employment during the past 5

years

Number of Dejour

Common Shares

beneficially owned,

directly or indirectly,

or controlled or

directed(2)

Percentage of

Dejour Common

Shares beneficially

owned, directly or

indirectly, or

controlled or

directed(2)


Director

SincePhil Bretzloff, BA, LLB

British Columbia, Canada

Vice President and General Counsel

(Age: 62)

Mr. Bretzloff has acted for oil, gas and energy companies, including extensive work for Canadian and offshore private and public corporations. Between 1980 and 1995, he was Senior Counsel for Petro-Canada. Subsequently, he was a Partner for 8 years with Cumming Blackett Bretzloff Todesco, Gowlings, and Baker & McKenzie, where his clients included PetroChina, Shell, Exxon Mobil, GazProm and Veba Oil and Gas.


59,500


0.1
%


N/ANeyeska Mut

EVP Operations, Dejour Energy (USA) Corp.

(Age: 53)

Engineer. Since 2000, she has been President of Nycon Energy Consulting working as an advisor to two major oil companies. Prior to forming Nycon Energy Consulting Mrs. Mut pursued international opportunities with Atlantic Richfield, ARCO. Has been with Dejour since 2008.


50,001


0.1
%


N/A
 (1)
Each director will serve until the next annual general meeting of the Company or until a successor is duly elected or appointed in accordance with the Notice of Articles and Articles of the Company and the Business Corporations Act(British Columbia).
 (2)
The number of common shares beneficially owned, directly or indirectly, or over which control or direction is exercised is based upon information furnished to the Company by individual directors and executive officers.
 (3)
Member of audit committee.
 (4)
Member of reserve committee.
 
 Board of Directors
 
 Brief biographies for each member of Dejour's board of directors are set forth below:
  Robert L. Hodgkinson:Mr. Hodgkinson was the founder and Chairman of Optima Petroleum, which drilled wells in Alberta and the Gulf of Mexico before merging to form Petroquest Energy, a NASDAQ traded company. Subsequently, he founded and was CEO of Australian Oil Fields, which would later merge to become Resolute Energy/Cardero Energy Inc.  Mr. Hodgkinson was also a Vice-President and partner of Canaccord Capital Corporation, and an early stage investor and original lease financier in Synenco Energy's Northern Lights Project in the Alberta oil sands.
   Stephen Mut: Mr. Mut most recently served as chief executive officer of a unit of Shell Exploration and Production Company. Prior to joining Shell in 2000, Mr. Mut dedicated much of his career to operational and new business venture activities in the oil and gas, refining and marketing, and chemical and mining sectors at ARCO (Atlantic Richfield Company), where he served in various internationally based executive roles in both upstream and downstream businesses. His global expertise has contributed to industry successes in Europe, South America, the Asia Pacific and the United States.
  51
  HarrisonBlacker:Mr. Blacker is an accomplished senior executive with over 30 years of expertise managing oil and gas operations with major corporations in the United States, South America, China and the Middle East. Prior to joining Dejour, Mr. Blacker was CEO of China Oman Energy Company, a joint venture between Oman Oil Company, IPIC and China Gas Holdings, importing and distributing LNG and LPG from the Middle East into China. Mr. Blacker held positions as VP of Business Development and Senior Investor Advisor with Oman Oil Company and Portfolio Manager, Latin American Business Unit and General Manager/ President of Venezuela Energy with Atlantic Richfield Corporation. Mr. Blacker began his career with Amoco Production Company working in offshore construction and field operations in the Gulf of Mexico.
  RichardPatricio:Mr. Patricio is Vice President Corporate & Legal Affairs and Secretary of Pinetree Capital Ltd. and Brownstone Ventures Inc. (one of Dejour's major shareholders). Mr. Patricio previously practiced law at a top tier law firm in Toronto and worked as in-house General Counsel for a senior TSX listed company. Mr. Patricio is a lawyer qualified to practice in the Province of Ontario.
  RobertHolmes:Mr. Holmes began his career as an Investment Executive with Merrill, Lynch, Pierce, Fenner & Smith, and subsequently held various senior executive positions with the firm Blyth, Eastman, Dillon & Company (purchased by Paine Webber & Co.). In 1980, Mr. Holmes co-founded Gilford Securities, Inc., a member of the NYSE, and in 1992 founded a hedge fund, Gilford Partners. He has served on several boards including the North Central College Trustees in Naperville, IL; Board of Trustees Sacred Heart Schools Chicago; Crested Butte Academy in Crested Butte, CO; and Mary Wood Country Day School in Rancho Mirage, CA. He graduated with a BA from North Central College in 1965.
  Craig Sturrock:Mr. Sturrock has served as a director and founding member of various public and private companies. Admitted to the British Columbia Bar in 1969, he joined Thorsteinssons LLP, tax lawyers in 1971. He served for 15 years as a tax lawyer and partner at Birnie, Sturrock & Company returning to Thorsteinssons as a partner in 1989.  He is an author and speaker for the Canadian and British Columbia Bar Associations, the Continuing Legal Education Society of British Columbia and the Canadian Tax Foundation. He is also a former member of the Board of Governors of the Canadian Tax Foundation.
  Darren Devine: Mr. Devine is the principal of Chelmer Consulting Corp., which provides corporate finance advisory services to private and public companies. Mr. Devine is a qualified Barrister and Solicitor in British Columbia, and a qualified solicitor in England and Wales.  Prior to forming Chelmer Consulting, Mr. Devine practiced exclusively in the areas of corporate finance and securities law with a focus on cross-border finance, stock exchange listings and mergers and acquisitions with the firm DuMoulin Black LLP in Vancouver, British Columbia.
  Family Relationships
 
 There are no family relationships between any directors or executive officers of the Company.
 
 Arrangements
 
 There are no known arrangements or understandings with any major shareholders, customers, suppliers or others, pursuant to which any of the Company’s officers or directors was selected as an officer or director of the Company, other than indicated immediately above and at “Item 7.  Major Shareholders and Related Party Transactions - Related Party Transactions.”
  52
  Cease Trade Orders, Bankruptcies, Penalties or Sanctions
 
 To the knowledge of the Company, no director or executive officer of the Company is, or has been in the last ten years, a director, chief executive officer or chief financial officer of an issuer that, while that person was acting in that capacity, (a) was the subject of a cease trade order or similar order or an order that denied the issuer access to any exemptions under Canadian securities legislation, for a period of more than 30 consecutive days, or (b) was subject to an event that resulted, after that person ceased to be a director, chief executive officer or chief financial officer, in the issuer being the subject of a cease trade or similar order or an order that denied the issuer access to any exemption under Canadian securities legislation, for a period of more than 30 consecutive days.  To the knowledge of the Company, no director or executive officer of the Company, or a shareholder holding a sufficient number of securities in the Company to affect materially the control of the Company, is or has been in the last ten years, a director or executive officer of an issuer that, while or acting in that capacity within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets. To the knowledge of the Company, in the past ten years, no such person has become bankrupt, made a proposal under any legislation related to bankruptcy or insolvency, or was subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold their assets.
 
 Conflicts of Interest
 
 Certain of the Company's directors and officers serve or may agree to serve as directors or officers of other reporting companies or have significant shareholdings in other reporting companies and, to the extent that such other companies may participate in ventures in which the Company may participate, the directors of the Company may have a conflict of interest in negotiating and concluding terms respecting the extent of such participation. In the event that such a conflict of interest arises at a meeting of the Company's directors, a director who has such a conflict will abstain from voting for or against the approval of such participation or such terms and such director will not participate in negotiating and concluding terms of any proposed transaction. From time to time, several companies may participate in the acquisition, exploration and development of natural resource properties thereby allowing for their participation in larger programs, permitting involvement in a greater number of programs and reducing financial exposure in respect of any one program. It may also occur that a particular company will assign all or a portion of its interest in a particular program to another of these companies due to the financial position of the company making the assignment. Under the laws of the Province of British Columbia, the directors of the Company are required to act honestly, in good faith and in the best interests of the Company. In determining whether or not the Company will participate in a particular program and the interest therein to be acquired by it, the directors will primarily consider the degree of risk to which the Company may be exposed and its financial position at that time. See also "Description of the Business – Risk Factors".
 
 B.           Compensation
 
 Basis of Compensation for Executive Officers
 
 The Company compensates its executive officers through a combination of base compensation, bonuses and Common Stock options. The base compensation provides an immediate cash incentive for the executive officers. Bonuses encourage and reward exceptional performance over the financial year. Common Stock options ensure that the executive officers are motivated to achieve long term growth of the Company and continuing increases in shareholder value. In terms of relative emphasis, the Company places more importance on Common Stock options as long term incentives. Bonuses are related to performance and may form a greater or lesser part of the entire compensation package in any given year. Each of these means of compensation is briefly reviewed in the following sections.
 
 Base Compensation
 
 Base compensation, including that of the Chief Executive Officer, are set by the Compensation Committee and approved by the Board of Directors on the basis of the applicable executive officer’s responsibilities, experience and past performance. The compensation program is intended to provide a base compensation competitive among companies of a comparable size and character in the oil and gas industry. In making such an assessment, the Board considers the objectives set forth in the Company’s business plan and the performance of executive officers and employees in executing the plan in combination with the overall result of the activities undertaken.
  53
  Bonuses
 
 An annual bonus may be paid for each fiscal year based on the Board’s assessment of the Company's general performance and the relative contribution of each of the executive officers, including the Chief Executive Officer, to that performance. During the year ended December 31, 2010, US $72,414 (2009: US $98,553) cash bonuses were awarded to the executive officers.
 
 Common Stock Options
 
 The Company provides long term incentive compensation to its executive officers through the Common Stock Option Plan, which is considered an integral part of the Company’s compensation program.  Upon the recommendation of management and approval by the Board of Directors, stock options are granted under the Company’s Option Plan to new directors, officers and key employees, usually upon their commencement of employment with the Company. The Board approves the granting of additional stock options from time to time based on its assessment of the appropriateness of doing so in light of the long term strategic objectives of the Company, its current stage of development, the need to retain or attract key technical and managerial personnel in a competitive industry environment, the number of stock options already outstanding, overall market conditions, and the individual’s level of responsibility and performance within the Company.
 
 The Board views the granting of stock options as a means of promoting the success of the Company and creating and enhancing returns to its shareholders. As such, the Board does not grant stock options in excessively dilutive numbers. Total options outstanding are presently limited to 10% of the total number of shares outstanding under the rules of the TSX. Grant sizes are, therefore, determined by various factors including the number of eligible individuals currently under the Option Plan and future hiring plans of the Company.
 
 The Board granted a total of 2,223 stock options to the executive officers in 2010.
 
 Annual Compensation

Long Term CompensationAwards

PayoutsName and

Principal Position

Year

Annual

Salary

Consulting

Fees

($)

Bonus

($)

Securities

Under

Option/

SAR's

Granted

(#)

Shares/

Units

Subject to

Resale

Restrictions

($)

LTIP

Pay-

outs ($)

All Other

Compensation

($)Robert L. Hodgkinson,

2010

$
78,000

$
177,000

Nil


369,000

Nil

Nil

NilChief Executive

2009

$
78,000

$
177,000

Nil


275,000

Nil

Nil

NilOfficer

2008

$
46,725

$
209,500

Nil


475,000
(1)
Nil

Nil

NilMathew Wong,

2010

$
78,000

$
151,000


12,000


217,000

Nil

Nil

NilChief Financial

2009

$
78,000

$
140,000

Nil


125,000
(3)
Nil

Nil

NilOfficer

2008

$
46,725

$
173,200

Nil


275,000
(4)
Nil

Nil

NilHarrison Blacker,

2010

US$
250,000

Nil

US$
60,000


433,000

Nil

Nil

NilDirector and

2009

US$
203,646

Nil

US$
98,553


300,000

Nil

Nil

NilPresident

2008

US$
187,500

Nil

Nil


800,000

Nil

Nil

Nilof Dejour Energy (USA)Craig Sturrock,

2010

Nil

Nil

Nil


150,000

Nil

Nil

$
5,500
(5)Director

2009

Nil

Nil

Nil


50,000

Nil

Nil

$
10,000
(5)2008

Nil

Nil

Nil


200,000

Nil

Nil

$
11,500
(5)Robert Holmes,

2010

Nil

Nil

Nil


150,000

Nil

Nil

$
6,500
(5)Director

2009

Nil

Nil

Nil


50,000

Nil

Nil

$
10,000
(5)2008

Nil

Nil

Nil


100,000

Nil

Nil

NilRichard Patricio,

2010

Nil

Nil

Nil


150,000

Nil

Nil

$
5,500
(5)Director

2009

Nil

Nil

Nil


50,000

Nil

Nil

$
10,000
(5)2008

Nil

Nil

Nil


100,000

Nil

Nil

NilStephen Mut,

2010

Nil

US$
120,000

Nil


250,000

Nil

Nil

NilDirector & Co-

2009

Nil

US$
14,286

Nil


100,000

Nil

Nil

NilChairmanDarren Devine,

2010

Nil

Nil

Nil


200,000

Nil

Nil


5,500Director

2009

Nil

Nil

Nil

Nil

Nil

Nil

NilNeyeska Mut,

2010

US$
200,470

Nil

Nil


194,000

Nil

Nil

NilEVP Operations

2009

US$
163,300

Nil

US$
30,763


80,000

Nil

Nil

NilOf Dejour Energy

2008

Nil

US$
109,000

Nil


120,000

Nil

Nil

Nil(USA)Phil Bretzloff

2010

Nil

$
77,401

Nil


110,000

Nil

Nil

NilVice President &

2009

Nil

$
74,635

$
7,200


75,000

Nil

Nil

NilGeneral Counsel

2008

Nil

$
76,054

Nil


75,000

Nil

Nil

Nil
 
 54
  Stock Option Grants
 Name

Number of

Options Granted


Exercise Price

per Share

Grant Date

Expiration DateRobert Hodgkinson


350,000


$
0.35

February 4, 2010

February 3, 2015Robert Hodgkinson


19,000


$
0.35

February 16, 2010

February 15, 2015Mathew Wong


200,000


$
0.35

February 4, 2010

February 3, 2015Mathew Wong


17,000


$
0.35

February 16, 2010

February 15, 2015Harrison Blacker


400,000


$
0.35

February 4, 2010

February 3, 2015Harrison Blacker


33,000


$
0.35

February 16, 2010

February 15, 2015Craig Sturrock


150,000


$
0.35

February 4, 2010

February 3, 2015Robert Holmes


150,000


$
0.35

February 4, 2010

February 3, 2015Richard Patricio


150,000


$
0.35

February 4, 2010

February 3, 2015Darren Devine


200,000


$
0.35

February 4, 2010

February 3, 2015Stephen Mut


250,000


$
0.35

February 4, 2010

February 3, 2015Neyeska Mut


175,000


$
0.35

February 4, 2010

February 3, 2015Neyeska Mut


19,000


$
0.35

February 16, 2010

February 15, 2015Phil Bretzloff


110,000


$
0.35

February 4, 2010

February 3, 2015Employees and Consultants


100,000


$
0.35

January 22, 2010

December 31, 2010715,000


$
0.35

February 4, 2010

February 3, 201515,000


$
0.35

February 16, 2010

February 15, 2015270,000


$
0.35

June 1, 2010

May 31, 201550,000


$
0.35

July 26, 2010

July 25, 2015
 
 Director Compensation
 
 The Company has compensation agreements for its Directors who are not executive officers. Under the agreements, Directors receive $2,500 per meeting for the first 4 meetings each year, and $1,500 for each meeting thereafter. The Board of Directors may award special remuneration to any Director undertaking any special services on behalf of the Company other than services ordinarily required of a Director. Per an amendment to the agreements approved by the Board of Directors, effective January 1, 2010, the Directors received $1,000 per quarter plus $500 for each meeting.
 
 55
 
 Long Term Incentive Plan Awards
 
 Long term incentive plan awards ("LTIP") means any plan providing compensation intended to serve as an incentive for performance to occur over a period longer than one financial year, whether the performance is measured by reference to financial performance of the Company or an affiliate of the Company, the price of the Company's shares, or any other measure, but does not include option or stock appreciation rights plans or plans for compensation through restricted shares or units. The Company did not award any LTIPs to any executive officer during the most recently completed financial year ended December 31, 2010. There are no pension plan benefits in place for the executive officer.
 
 Stock Appreciation Rights
 
 Stock appreciation rights ("SARs") means a right, granted by the Company or any of its subsidiaries as compensation for services rendered or in connection with office or employment, to receive a payment of cash or an issue or transfer of securities based wholly or in part on changes in the trading price of the Company's shares. No SARs were granted to, or exercised by, any executive officer of the Company during the most recently completed financial year ended December 31, 2010.
 
 Change of Control Remuneration
 
 The Company has management contracts with the following executive officers or the companies controlled by the executive officers:
 Named Executive

Officer

Annual Base

Salary and / or

Consulting

Fees

Compensation Package on

Termination of Contract,

other than for termination

with cause

Compensation Package

on Termination of Contract, in

the event of a change in controlRobert Hodgkinson

$
255,000

1 times annual base salary and consulting fee

2 times annual base salary and consulting feeMathew Wong

$
229,000

1 times annual base salary and consulting fee

2 times annual base salary and consulting feeHarrison Blacker

US$
250,000

1 times annual base salary

2 times annual base salary
 
 Bonus/Profit Sharing/Non-Cash Compensation
 
 Per the consulting agreements, the CEO and CFO are entitled for an annual value-added bonus based on the excess shareholder return of the Company’s shares over the index return of the TSX Energy index ETF (“XEG”). The bonus payout is subject to the approval and discretion of the Board of Directors. Per the employment agreement, the President is entitled for a minimum annual bonus of US$60,000 for the years of 2009 and 2010.
 
 Pension/Retirement Benefits
 
 No funds were set aside or accrued by the Company during Fiscal 2009 to provide pension, retirement or similar benefits for Directors or Senior Management.
 
 C.           Board Practices
 
 Compensation Committee
  56
  The Company has a Compensation Committee composed of three Directors, Robert Holmes, Craig Sturrock and Richard Patricio.
 
 Role of the Compensation Committee
 
 The Compensation Committee exercises general responsibility regarding overall executive compensation. The Board of Directors sets the annual compensation, bonus and other benefits of the Chief Executive Officer and approves compensation for all other executive officers of the Company after considering the recommendations of the Compensation Committee.
 
 Audit Committee
  The Company’s Board of Directors has a separately-designated standing Audit Committee established for the purpose of overseeing the accounting and financial reporting processes of the Company and audits of the Company’s annual financial statements in accordance with Section 3(a)(58)(A) of the Exchange Act.  As of the date of this annual report on Form 20-F, the Company’s Audit Committee is comprised of Craig Sturrock, Robert Holmes and Darren Devine.
 
 In the opinion of the Company’s Board of Directors, all the members of the Audit Committee are independent (as determined under Rule 10A-3 of the Exchange Act and Section 803A of the NYSE Amex Company Guide).  The Audit Committee meets the composition requirements set forth by Section 803B(2) of the NYSE Amex Company Guide.  All three members of the Audit Committee are financially literate, meaning they are able to read and understand the Company’s financial statements and to understand the breadth and level of complexity of the issues that can reasonably be expected to be raised by the Company’s financial statements.
 
 The members of the Audit Committee do not have fixed terms and are appointed and replaced from time to time by resolution of the Board of Directors.
 
 Terms of Reference for the Audit Committee
 
 Audit Committee Mandate
 
 The primary function of the audit committee is to assist the Board in fulfilling its financial oversight responsibilities by reviewing the financial reports and other financial information provided by the Company to regulatory authorities and Shareholders, the Company’s systems of internal controls regarding finance and accounting and the Company’s auditing, accounting and financial reporting processes.  Consistent with this function, the audit committee will encourage continuous improvement of, and should foster adherence to, the Company’s policies, procedures and practices at all levels.  The audit committee’s primary duties and responsibilities are to:
 Serve as an independent and objective party to monitor the Company’s financial reporting and internal control system and review the Company’s financial statements.
 
 Review and appraise the performance of the Company’s external auditors.
 
 Provide an open avenue of communication among the Company’s auditors, financial and senior management and the Board.
 
 Composition
 
 The audit committee shall be comprised of three Directors as determined by the Board, the majority of whom shall be free from any relationship that, in the opinion of the Board, would interfere with the exercise of his or her independent judgment as a member of the audit committee.
 
 At least one member of the audit committee shall have accounting or related financial management expertise.  All members of the audit committee that are not financially literate will work towards becoming financially literate to obtain a working familiarity with basic finance and accounting practices.  For the purposes of the Company's Charter, the definition of “financially literate” is the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can presumably be expected to be raised by the Company's financial statements.
  57
  The members of the audit committee shall be elected by the Board at its first meeting following the annual Shareholders’ meeting.  Unless a Chair is elected by the full Board, the members of the audit committee may designate a Chair by a majority vote of the full audit committee membership.
 
 Meetings
 
 The audit committee shall meet a least twice annually, or more frequently as circumstances dictate.  As part of its job to foster open communication, the audit committee will meet at least annually with the Chief Financial Officer and the external auditors in separate sessions.
 
 Responsibilities and Duties
 
 To fulfill its responsibilities and duties, the audit committee shall:
 
 Documents/Reports Review
 
 (a)
Review and update this Charter annually.
 (b)
Review the Company's financial statements, MD&A and any annual and interim earnings, press releases before the Company publicly discloses this information and any reports or other financial information (including quarterly financial statements), which are submitted to any governmental body, or to the public, including any certification, report, opinion, or review rendered by the external auditors.
 (c)
Approve, on behalf of the Board, the Corporation’s interim financial statements to be filed pursuant to section 4.3 of NI 51-102, before the Corporation publicly discloses such information.
 
 External Auditors
 
 (a)
Review annually, the performance of the external auditors who shall be ultimately accountable to the Board and the audit committee as representatives of the Shareholders of the Company.
 (b)
Obtain annually, a formal written statement of external auditors setting forth all relationships between the external auditors and the Company, consistent with Independence Standards Board Standard 1.
 (c)
Review and discuss with the external auditors any disclosed relationships or services that may impact the objectivity and independence of the external auditors.
 (d)
Take, or recommend that the full Board take, appropriate action to oversee the independence of the external auditors.
 (e)
Recommend to the Board the selection and, where applicable, the replacement of the external auditors nominated annually for Shareholder approval.
 (f)
At each meeting, consult with the external auditors, without the presence of management, about the quality of the Company’s accounting principles, internal controls and the completeness and accuracy of the Company's financial statements.
 (g)
Review and approve the Company's hiring policies regarding partners, employees and former partners and employees of the present and former external auditors of the Company.
 (h)
Review with management and the external auditors the audit plan for the year-end financial statements and intended template for such statements.
 (i)
Review and pre-approve all audit and audit-related services and the fees and other compensation related thereto, and any non-audit services, provided by the Company’s external auditors.  The pre-approval requirement is waived with respect to the provision of non-audit services if:
 
 i.
the aggregate amount of all such non-audit services provided to the Company constitutes not more than five percent of the total amount of revenues paid by the Company to its external auditors during the fiscal year in which the non-audit services are provided;
 ii.
such services were not recognized by the Company at the time of the engagement to be non-audit services; and
  58
  iii.
such services are promptly brought to the attention of the audit committee by the Company and approved prior to the completion of the audit by the audit committee or by one or more members of the audit committee who are members of the Board to whom authority to grant such approvals has been delegated by the audit committee.
 
 Provided the pre-approval of the non-audit services is presented to the audit committee's first scheduled meeting following such approval such authority may be delegated by the audit committee to one or more independent members of the audit committee.
 
 Financial Reporting Processes
 
 (a)
In consultation with the external auditors, review with management the integrity of the Company's financial reporting process, both internal and external.
 (b)
Consider the external auditors’ judgments about the quality and appropriateness of the Company’s accounting principles as applied in its financial reporting.
 (c)
Consider and approve, if appropriate, changes to the Company’s auditing and accounting principles and practices as suggested by the external auditors and management.
 (d)
Review significant judgments made by management in the preparation of the financial statements and the view of the external auditors as to appropriateness of such judgments.
 (e)
Following completion of the annual audit, review separately with management and the external auditors any significant difficulties encountered during the course of the audit, including any restrictions on the scope of work or access to required information.
 (f)
Review any significant disagreement among management and the external auditors in connection with the preparation of the financial statements.
 (g)
Review with the external auditors and management the extent to which changes and improvements in financial or accounting practices have been implemented.
 (h)
Review any complaints or concerns about any questionable accounting, internal accounting controls or auditing matters.
 (i)
Review certification process.
 (j)
Establish a procedure for the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters.
 
 Other
 
 Review any related-party transactions
 
 Audit Committee Oversight
 
 At no time since the commencement of the Company’s most recently completed financial year was a recommendation of the audit committee to nominate or compensate an external auditor not adopted by the Board of Directors.
 
 D.           Employees
 
 The Company had an average of 15 full-time equivalent of employees and consultants during 2010.
 
 E.           Share Ownership
 
 Directors and Officer Beneficial Ownership
 
 The following table discloses as of June 8, 2011, Directors and Senior Management who beneficially own the Company's voting securities, consisting solely of common shares, and the amount of the Company's voting securities owned by the Directors and Senior Management as a group.
  59
  Shareholdings of Directors and Senior Management as of June 8, 2011
 
 Title of

Class

Name of Beneficial Owner



Amount and Nature

of Beneficial

Ownership


Percent of

ClassCommon

Robert L. Hodgkinson

(1)


8,685,283



7.15
%Common

Harrison Blacker

(2)


1,253,803



1.03
%Common

Mathew H. Wong

(3)


493,247



0.41
%Common

Craig Sturrock

(4)


976,250



0.80
%Common

Robert Holmes

(5)


2,591,750



2.14
%Common

Richard Patricio

(6)


178,750



0.15
%Common

Stephen Mut

(7)


2,504,751



2.06
%Common

Darren Devine

(8)


137,500



0.11
%Common

Neyeska Mut

(9)


305,501



0.25
%Common

Phil Bretzloff

(10)


205,750



0.17
%Total Directors/Management




17,332,585



14.28
%
 (1)
Of these shares, 7,187,840 are represented by common shares, 565,625 are represented by vested stock options and 931,818 are represented by currently exercisable share purchase warrants. 1,500,000 of these shares are owned by 7804 Yukon Inc., a private company owned by Robert Hodgkinson; 3,600,499 are common shares owned by Hodgkinson Equities Corp., a private company owned by Robert Hodgkinson. A further 753,375 stock options have been granted but not yet vested.
 (2)
Of these shares, 525,678 are represented by common shares, 578,125 are represented by vested stock options and 150,000 are represented by currently exercisable share purchase warrants. A further 754,875 stock options have been granted but not yet vested.
 (3)
Of these shares, 122 are represented by common shares, 436,875 are represented by vested stock options and 56,250 are represented by currently exercisable share purchase warrants. 98 of these common shares are held by 390855 BC Ltd., a private company owned by Mathew Wong; 24 common shares are owned by Pui Ngor Lee, Mr. Wong’s mother. A further 506,375 stock options have been granted but not yet vested.
 (4)
Of these shares, 650,000 are represented by common shares, 176,250 are represented by vested stock options and 150,000 are represented by currently exercisable share purchase warrants. A further 223,750 stock options have been granted but not yet vested.
 (5)
Of these shares, 1,663,000 are represented by common shares, 178,750 are represented by vested stock options and 750,000 are represented by currently exercisable share purchase warrants. A further 221,250 stock options have been granted but not yet vested.
 (6)
Of these shares, 178,750 are represented by vested stock options. A further 221,250 stock options have been granted but not yet vested.
 (7)
Of these shares, 1,611,001 are represented by common shares, 268,750 are represented by vested stock options and 625,000 are represented by currently exercisable share purchase warrants. A further 381,250 stock options have been granted but not yet vested.
 (8)
Of these shares, 137,500 are represented by vested stock options. A further 162,500 stock options have been granted but not yet vested.
 (9)
Of these shares, 50,001 are represented by common shares and 255,500 are represented by vested stock options. A further 444,500 stock options have been granted but not yet vested.
 (10)
Of these shares, 59,500 are represented by common shares and 146,250 are represented by vested stock options. A further 253,750 stock options have been granted but not yet vested.
 
 All percentages based on 121,390,545 shares outstanding as of June 8, 2011, and stock options and share purchase warrants exercisable within 60 days for each holder.
 
 Stock Options
 
 The terms of incentive options grantable by the Company are prepared in accordance with the rules and policies of the TSX Exchange and the British Columbia Securities Commission, including the number of common shares under option, the exercise price and expiry date of such options, and any amendments thereto.  The Company adopted a formal written stock option plan (the "Plan") on June 2, 2006. At the Company’s Annual General Meeting held on October 17, 2008, shareholders approved a resolution modifying the Plan as described below.
 
 The principal purposes of the Company’s stock option program are to (a) assist the company in attracting, retaining, and motivating directors, officers and employees of the Company and, (b) to closely align the personal interests of such directors, officers and employees with the interests of the Company and its shareholders.
  60
  The Plan provides that stock options may be granted to service providers for the Company.  The term “service providers” means (a) any full or part-time employee or Officer, or insider of the Company or any of its subsidiaries; (b) any other person employed by a company or individual providing management services to the Company; (c) any other person or company engaged to provide ongoing consulting services for the Company or any entity controlled by the Company or (d) any individual engaged to provide services that promote the purchase or sale of the issued securities (any person in (a), (b), (c) or (d) hereinafter referred to as an “Eligible Person”); and (e) any registered retirement savings plan established by such Eligible Person, or any corporation controlled by such Eligible Person, the issued and outstanding voting shares of which are, and will continue to be, beneficially owned, directly or indirectly, by such Eligible Person and/or spouse, children and/or grandchildren of such Eligible Person.  For stock options to Employees, Consultants or Management Company Employees, the Company must represent that the optionee is a bona fide Employee, Consultant or Management Company Employee as the case may be.  The terms “insider” “Controlled” and “subsidiary” shall have the meanings ascribed thereto in the Securities Act (Ontario) from time to time.  Subject to the foregoing, the board of directors or Committee, as applicable, shall have full and final authority to determine the persons who are to be granted options under the Plan and the number of shares subject to each option.
 
 The Plan shall be administered by the board of directors of the Company or a committee established by the board of directors for that purpose.  Subject to approval of the granting of options by the board of directors or Committee, as applicable, the Company shall grant options under the Plan.
 
 The Plan provides that the aggregate number of shares of the Company, which may be issued and sold under the Plan, will not exceed 10% of the issued shares of the Company.  The Company shall not, upon the exercise of any option, be required to issue or deliver any shares prior to (a) the admission of such shares to listing on any stock exchange on which the Company’s shares may them be listed, and (b) the completion of such registration or other qualification of such shares under any law, rules or regulation as the Company shall determine to be necessary or advisable.  If any shares cannot be issued to any optionee for whatever reason, the obligation of the Company to issue such shares shall terminate and any option exercise price paid to the Company shall be returned to the optionee.
 
 If a stock option expires or otherwise terminates for any reason without having been exercised in full, the number of common shares reserved for issuance under that expired or terminated stock option shall again be available for the purposes of the Plan.  Any stock option outstanding when the Plan is terminated will remain in effect until it is exercised or it expires.  The Plan provides that it is solely within the discretion of the Board to determine who should receive stock options and in what amounts, subject to the following conditions:
 
 (a)
options will be non-assignable and non-transferable except that they will be exercisable by the personal representative of the option holder in the event of the option holder’s death;
 (b)
options may be exercisable for a maximum of five years from grant date;
 (c)
options to acquire no more than 5% of the issued shares of the Company may be granted to any one individual in any 12-month period;
 (d)
options to acquire no more than 2% of the issued shares of the Company may be granted to any one consultant in any 12-month period;
 (e)
options to acquire no more than an aggregate of 2% of the issued shares of the Company may be granted to an employee conducting investor relations activities (as defined in TSX Venture Exchange Policy 1.1), in any 12 month period;
 (f)
options to acquire no more than 10% of the issued shares of the Company may be granted to any insiders in any 12-month period;
 (g)
options held by an option holder who is a director, employee, consultant or management company employee must expire within 90 days after the option holder ceases to be a director, employee, consultant or management company employee;
 (h)
options held by an option holder who is engaged in investor relations activities must expire within 30 days after the option holder ceases to be employed by the Company to provide investor relations activities; and
 61
  (i)
in the event of an option holder’s death, the option holder’s personal representative may exercise any portion of the option holder’s vested outstanding options for a period of one year following the option holder’s death.
 
 The Plan provides that other terms and conditions may be attached to a particular stock option, such terms and conditions to be referred to in a schedule attached to the option certificate.  Stock options granted to directors, senior officers, employees or consultants will vest when granted unless otherwise determined by the Board on a case by case basis, other than stock options granted to consultants performing investor relations activities, which will vest in stages over 12 months with no more than one-fourth of the options vesting in any three month period.
 
 The price at which an option holder may purchase a common share upon the exercise of a stock option will be as set forth in the option certificate issued in respect of such option and in any event will not be less than the discounted market price of the Company’s common shares as of the date of the grant of the stock option (the “Award Date”).  The market price of the Company’s common shares for a particular Award Date will typically be the closing trading price of the Company’s common shares on the day immediately preceding the Award Date, or otherwise in accordance with the terms of the Plan.  Where there is no such closing price or trade on the prior trading day “market price” shall mean the average of the most recent bid and ask of the shares of the Company on any stock exchange on which the shares are listed or dealing network on which the shares of the Company trade.
 
 In no case will a stock option be exercisable at a price less than the minimum prescribed by each of the organized trading facilities or the applicable regulatory authorities that would apply to the award of the stock option in question.
 
 Common shares will not be issued pursuant to stock options granted under the Plan until they have been fully paid for by the option holder.  The Company will not provide financial assistance to option holders to assist them in exercising their stock options.
 
 At the Company’s Annual General Meeting of Shareholders held on October 17, 2008, shareholders approved a resolution which ratified a revised Plan. Under the resolution, options will be exercisable over periods of up to five years as determined by the Board and are required to have an exercise price no less than the closing market price of the Company’s shares prevailing on the day the option is granted, less a discount of up to 25%, the amount of the discount varying with market price in accordance with the policies of the Exchange. The Plan contains no vesting requirements, but permits the Board to specify a vesting schedule in its discretion. The Plan provides that if a change in control occurs, all shares subject to option shall immediately become vested and may thereupon be exercised in whole or in part by the option holder.
 
 Stock Options Outstanding
 
 The names and titles of the Directors/Executive Officers of the Company to whom outstanding stock options have been granted and the number of common shares subject to such options is set forth in the following table as of June 23, 2011.
  62
 
 Stock Options Outstanding as of June 23, 2011
 
 Name

Number of

Options Held


Number of

Options

Vested


Exercise Price per

Share

Grant Date

Expiration DateRobert Hodgkinson


375,000



187,500


$
0.45

10/28/2008

10/28/2013275,000



110,000


$
0.45

5/5/2009

5/4/2014350,000



218,750


$
0.35

2/4/2010

2/3/201519,000



11,875


$
0.35

2/16/2010

2/15/2015300,000



37,500


$
0.35

3/16/2011

3/15/2014Harrison Blacker


300,000



150,000


$
0.45

10/28/2008

10/28/2013300,000



120,000


$
0.45

5/5/2009

5/4/2014400,000



250,000


$
0.35

2/4/2010

2/3/201533,000



20,625


$
0.35

2/16/2010

2/15/2015300,000



37,500


$
0.35

3/16/2011

3/15/2014Mathew Wong (1)


175,000



87,500


$
0.45

10/28/2008

10/28/2013125,000



50,000


$
0.45

5/5/2009

5/4/2014200,000



125,000


$
0.35

2/4/2010

2/3/201517,000



10,625


$
0.35

2/16/2010

2/15/2015300,000



37,500


$
0.35

3/16/2011

3/15/2014Craig Sturrock


100,000



50,000


$
0.45

10/28/2008

10/28/201350,000



20,000


$
0.45

5/5/2009

5/4/2014150,000



93,750


$
0.35

2/4/2010

2/3/2015100,000



12,500


$
0.35

3/16/2011

3/15/2014Robert Holmes


100,000



50,000


$
0.45

10/28/2008

10/28/201350,000



22,500


$
0.45

02/12/2009

02/12/2014150,000



93,750


$
0.35

2/4/2010

2/3/2015100,000



12,500


$
0.35

3/16/2011

3/15/2014Richard Patricio


100,000



50,000


$
0.45

10/28/2008

10/28/201350,000



22,500


$
0.45

02/12/2009

02/12/2014150,000



93,750


$
0.35

2/4/2010

2/3/2015100,000



12,500


$
0.35

3/16/2011

3/15/2014Stephen Mut


100,000



100,000


$
0.45

6/29/2009

6/29/2014250,000



156,250


$
0.35

2/4/2010

2/3/2015300,000



12,500


$
0.35

3/16/2011

3/15/2014Darren Devine


200,000



125,000


$
0.35

2/4/2010

2/3/2015100,000



12,500


$
0.35

3/16/2011

3/15/2014Neyeska Mut


120,000



60,000


$
0.45

10/28/2008

10/28/201380,000



36,000


$
0.45

2/12/2009

2/12/2014175,000



109,375


$
0.35

2/4/2010

2/3/201519,000



11,875


$
0.35

2/16/2010

2/15/2015306,000



38,250


$
0.35

3/16/2011

3/15/2014Phil Bretzloff


75,000



37,500


$
0.45

10/28/2008

10/28/201375,000



33,750


$
0.45

2/12/2009

2/12/2014110,000



68,750


$
0.35

2/4/2010

2/3/2015140,000



17,500


$
0.35

3/16/2011

3/15/2014Total Officers/Directors


6,719,000



2,807,375
 
 (1)
125,000 options granted on May 5, 2009 were issued to 390855 B.C. Ltd., a private company owned by Mathew Wong.
 (2)
200,000 options granted on February 4, 2010 were issued to Chelmer Investments Corp., a private company owned by Darren Devine. On October 25, 2010, these options were re-issued to the name of Darren Devine with the same exercise price, vesting term and expiration date.
  63
  ITEM 7.  MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS.
 
 A.           Major Shareholders
 
 Shareholders
 
 The Company is aware of two persons/companies who each beneficially own 5% or more of the Registrant's voting securities. The following table lists as of June 8, 2011 persons and/or companies holding 5% or more beneficial interest in the Company’s outstanding common stock.
 
 5% or Greater Shareholders as of June 8, 2011
 
 Title of Class

Name of Owner

Amount and Nature of

Beneficial Ownership


Percent of ClassCommon

Brownstone Ventures Inc.


15,634,278



12.87
%Common

Robert L. Hodgkinson (1)


8,685,283



7. 15
%
 
 (1)
Of these shares, 7,187,840  are represented by common shares, 565,625 are represented by vested stock options and 931,818 are represented by currently exercisable share purchase warrants. 1,500,000 of these shares are owned by 7804 Yukon Inc., a private company owned by Robert Hodgkinson; 3,600,499 are common shares owned by Hodgkinson Equities Corp., a private company owned by Robert Hodgkinson. A further 753,375 stock options have been granted but not yet vested.
 
 All percentages based on 121,390,545 shares outstanding as of June 8, 2011, and stock options and share purchase warrants exercisable within 60 days for each holder.
 
 Changes in ownership by major shareholders
 
 To the best of the Company’s knowledge there have been no changes in the ownership of the Company’s shares other than disclosed herein.
 
 Voting Rights
 
 The Company’s major shareholders do not have different voting rights.
 
 Shares Held in the United States
 
 As of April 25, 2011, there were approximately 5,513 registered holders of the Company’s shares in the United States, with combined holdings of 66,272,474 common shares.
 
 Change of Control
 
 As of June 8, 2011, there were no arrangements known to the Company which may, at a subsequent date, result in a change of control of the Company.
 
 Control by Others
 
 To the best of the Company’s knowledge, the Company is not directly or indirectly owned or controlled by another corporation, any foreign government, or any other natural or legal person, severally or jointly.
 
 B.           Related Party Transactions
 
 Other than as disclosed below, from January 1, 2008 through December 31, 2010, the Company did not enter into any transactions or loans between the Company and any (a) enterprises that directly or indirectly through one or more intermediaries, control or are controlled by, or are under common control with the Company; (b) associates; (c) individuals owning, directly or indirectly, an interest in the voting power of the Company that gives them significant influence over the Company, and close members of any such individual’s family; (d) key management personnel and close members of such individuals' families; or (e) enterprises in which a substantial interest in the voting power is owned, directly or indirectly by any person described in (c) or (d) or over which such a person is able to exercise significant influence.
  64
  (a)
Loan from Hodgkinson Equity Corporation (“HEC”)
 
 HEC loan to DEAL
 
 On May 15, 2008, DEAL issued a promissory note for up to $2,000,000 to HEC, a private company controlled by the CEO of the Company. The promissory note is secured by the assets, equipment, fixtures, inventory and accounts receivable of DEAL, bears interest at the Royal Bank of Canada Prime Rate per annum, and has a loan fee of 1% of the outstanding amount per month. The principal, interest and loan fee were payable on demand after August 15, 2008.  Upon securing the bank line of credit in August 2008, HEC signed a subordination and postponement agreement which restricted the principal repayment of the promissory note subject to the bank’s prior approval and DEAL meeting certain loan covenants. As at December 31, 2008, $1,950,000 had been advanced on the promissory note. Repayments of $90,642 and $59,358 were made on March 5, 2009 and on April 3, 2009 respectively. As at June 22, 2009, the Company assumed from DEAL the remaining outstanding balance of $1,800,000.
 
 HEC loan to the Company
 
 On August 11, 2008, the Company borrowed $600,000 from HEC.  The loan was secured by all assets of the Company, repayable on demand, bore interest at the Canadian prime rate per annum, and had a loan fee of 1% of the outstanding amount per month.  At December 31, 2008 $600,000 had been advanced to the Company.  On March 19, 2009, a repayment of $600,000 was made and as at December 31, 2009, no balance remained outstanding.
 
 On September 12, 2008, as consideration for HEC agreeing to postpone the $2,000,000 promissory note and providing the additional loan of $600,000, HEC was granted an option to become a working interest partner with DEAL.  Upon electing to become a working interest partner, HEC must pay DEAL an amount equal to 10% of the actual price paid for the acquisition of the Montney (Buick Creek) property in northeastern British Columbia.  HEC is also required to pay its pro-rata share of the operating costs. On February 26, 2009, HEC exercised its option and elected to become a 10% working interest partner in DEAL’s Montney (Buick Creek) property.  The option price was $90,642.
 
 On June 22, 2009, as amended on September 30, 2009 and December 31, 2009, the Company entered into an agreement with HEC in regard to the outstanding debt of $1,800,000 assumed from DEAL by the Company.  Pursuant to the agreements, $450,000 of the debt was converted into 1,363,636 units consisting of 1,363,636 common shares and 681,818 common share purchase warrants exercisable at a price of $0.55 for a period of 5 years.  The fair value of the units was estimated to be $450,000. The remaining $1,350,000 was converted into a 12% note due on January 1, 2011 and the Company was required to pay 3% fee on the outstanding balance of the loan as at December 31, 2009.  As a result of the sale of 5% working interest in the Drake/Woodrush area to HEC in December 2009 (effective June 1, 2009), both parties agreed to reduce the loan balance by the purchase price of $911,722 including taxes and adjustments. In addition, the loan balance was further reduced by a payment of $50,351.  As at December 31, 2009, a balance of $387,927 remained outstanding.  As at December 31, 2010, a balance of $250,000 remained outstanding. Subsequent to December 31, 2010, the loan was repaid in full in cash.
 
 (b)
Loan from Brownstone Ventures Inc. (“Brownstone”)
 
 On June 18, 2008, a promissory note with a face value of $4,078,800 (US $4,000,000) was issued to Brownstone. Brownstone owns more than 10% of outstanding common shares of the Company and one of Brownstone’s directors also serves on the board of directors of the Company. The promissory note was secured by a general security agreement issued by the Company in favour of Brownstone, and bore interest at 5% per annum.   The principal and interest were repayable by the earlier of the completion of an equity and/or debt financing, and July 1, 2009.  During the year ended December 31, 2008, a repayment of $222,948 (US$220,000) was made and at December 31, 2008 a balance of $4,604,040 (US$3,780,000) owed.
  65
 On June 22, 2009, as amended on September 30, 2009 and December 31, 2009, the Company entered into an agreement with Brownstone in regard to the outstanding debt of $4,604,040 (US$3,780,000). Pursuant to the agreement, $2,200,000 (US$2,000,000) of the debt was converted into 6,666,667 units consisting of 6,666,667 common shares and 3,333,333 common share purchase warrants exercisable at a price of $0.55 for a period of 5 years.  The fair value of the units was estimated to be US$2,000,000.  The remaining $2,070,140 (US$1,780,000) of the debt was converted into a Canadian dollar denominated 12% note due on January 1, 2011.
 
 On June 22, 2009, the Company also issued Brownstone 2,000,000 common share purchase warrants exercisable at $0.50 for a period of 2 years, with an option to force the exercise of the warrants if the Company’s common shares trade at a price of $0.80 or greater for 30 consecutive calendar days.
 
 As at December 31, 2009, a balance of $1,957,474 remained outstanding comprised of the loan balance of $2,070,140 minus unamortized portion of finance fees of $112,666. In December 2010, the loan was paid off in full in cash.
  (c)
During 2008, the Company accrued $19,562 (2007 - US$34,195; 2006 - US$17,282) of interest at 8% per annum related to US$400,000 of convertible debentures as discussed in Note 9 to the financial statements, and paid $Nil (2007 - $63,000; 2006 - $63,000) bonus to HEC.  In June 2008, US $400,000 of convertible debentures was converted to 296,296 units. Each unit consists of one common share and one warrant, exercisable at US $1.50 per share, expiring on July 15, 2008. The Company also issued 50,806 Units to settle US $68,587 of accrued interest.  In October 2006, the Company assigned 25% of its interest in the Noel Area, to HEC, which agreed to assume 25% of the related obligations.  In November 2006, the Company had received $234,251 from HEC, being the estimated 25% share of the exploration expenditures for the Noel Area.
 
 (d)
During 2008, the Company accrued $4,904 (2007 - US$21,320; 2006 - US$14,830) of interest at 8% per annum related to US$400,000 of convertible debentures as discussed in Note 9 to the financial statements, and paid $Nil (2007 - $63,000; 2006 - $63,000) bonus payments to the President of a private company controlled by the former President of the Company, Douglas Cannaday. In June 2008, US$200,000 of convertible debentures was converted to 148,148 Units. Each Unit consists of one common share and one warrant, exercisable at US $1.50 per share, expiring on July 15, 2008. The Company also issued 12,700 Units to settle US $17,145 of accrued interest.  In April 2007, US$200,000 of convertible debentures was converted to 148,148 Units. Each Unit consists of one common share and one warrant, exercisable at US $1.50 per share, expiring on July 15, 2008. The Company also issued 9,254 Units to settle US $12,493 of accrued interest.
 
 (e)
During 2008, the Company accrued $12,948 (2007 - US$32,222; 2006 - US$14,830) of interest at 8% per annum related to US$400,000 of convertible debentures, as discussed in Note 9 in the financial statements, to an individual related to the CFO. In June 2008, US$250,150 of convertible debentures was converted to 185,296 Units. Each Unit consists of one common share and one warrant, exercisable at US $1.50 per share, expiring on July 15, 2008. The Company also issued 44,444 Units to settle US $59,999 of accrued interest.  In November 2007, US $149,850 of convertible debentures was converted to 111,000 units. Each unit consists of one common share and one warrant, exercisable at US $1.50 per share, expiring on July 15, 2008.
 
 (f)
During 2009, the Company incurred a total of $682,618 (2008 - $737,112) in consulting and professional fees and a total of $90,714 (2008 - $111,291) in rent expenses to the companies controlled by officers of the Company. Included in the total consulting and professional fees incurred was a payment of $107,000 made to a former officer of the Company to terminate the consulting agreement with this officer. In addition, the Company received total rental income of $30,000 (2008 - $28,700) from the companies controlled by officers of the Company.
  66
 (g)
During 2009, the Company incurred a total of $382,748 (2008 - $300,434) in interest expense and finance fee to the related parties.
 
 (h)
During 2009, the Company received total consulting fee income of $114,200 (2008: Nil) from a related party.
 
 (i)
During 2010, the Company incurred a total of $520,152 (2009 - $682,618) in consulting and professional fees and a total of $Nil (2009 - $90,714) in rent expenses to the companies controlled by officers of the Company. The consulting and professional fees are included in general and administrative expenses. Included in accounts payable and accrued liabilities at December 31, 2010 is $12,000 (December 31, 2009 - $Nil) owing to a company controlled by an officer of the Company. Included in the total consulting and professional fees incurred during 2009 was $107,000 paid to a former officer of the Company to terminate the consulting agreement.
 
 (j)
During 2010, the Company incurred a total of $268,440 (2009 - $382,748) in interest expense and finance fee to the company controlled by an officer of the Company and Brownstone. Included in accounts payable and accrued liabilities at December 31, 2010 is $Nil (December 31, 2009 - $47,523) owing to the company controlled by an officer of the Company.
 
 C. Interests of Experts and Counsel
 
 Not Applicable.
 67
  ITEM 8.  FINANCIAL INFORMATION.
 
 A.           Consolidated Statements and Other Financial Information
 
 Financial Statements
 
 Description

PageConsolidated Financial Statements for the Years Ended December 31, 2010, 2009 and 2008.


F-1 - F42
 
 Legal Proceedings
 
 The Directors and the management of the Company do not know of any material, active or pending, legal proceedings against them; nor is the Company involved as a plaintiff in any material proceeding or pending litigation.
 
 The Directors and the management of the Company know of no active or pending proceedings against anyone that might materially adversely affect an interest of the Company.
 
 Dividend Policy
 
 The Company has not paid any dividends on its common shares.  The Company may pay dividends on its common shares in the future if it generates profits.  Any decision to pay dividends on common shares in the future will be made by the board of directors on the basis of the earnings, financial requirements and other conditions existing at such time.
 
 B.           Significant Changes
 
 None.
 
 ITEM 9.   THE OFFER AND LISTING
 
 A.           Offering and Listing Details
 
 The Company’s common shares are traded on the Toronto Stock Exchange and on the NYSE Amex, in both cases under the symbol “DEJ.”  The following tables set forth for the periods indicated, the high and low closing prices in Canadian dollars of our common shares traded on the Toronto Stock Exchange and the TSX Venture Exchange and in United States dollars on the NYSE Amex.  The Company traded on the Toronto Stock Exchange Venture Exchange in Vancouver, British Columbia, Canada, until November 20, 2008 when it began trading on the TSX. The Company changed its symbol to “DEJ” after a one for three share consolidation effective October 1, 2003. The Company changed its Toronto Stock Exchange trading symbol on May 23, 2007 to “DEJ” to coincide with its listing on the American Stock Exchange (now NYSE Amex) on the same day under the symbol “DEJ”.
 
 The following table contains the annual high and low market prices for the five most recent fiscal years:
 
 Toronto Stock Exchange (Cdn$)
 
 High


Low2010

$
0.475


$
0.2852009

$
0.76


$
0.232008(1)

$
2.17


$
0.232007

$
3.28


$
1.022006

$
2.97


$
0.992005

$
1.07


$
0.41
  68
  (1) Common shares listed on Toronto Stock Exchange on November 20, 2008.
 
 NYSE Amex (US$)
 
 High


Low2010

$
0.497


$
0.26012009

$
0.67


$
0.122008

$
2.17


$
0.252007(1)

$
2.95


$
1.29
 
 (1) Shares listed for trading on NYSE Amex on May 7, 2007
 
 The following table contains the high and low market prices for our common shares on the Toronto Stock Exchange and the NYSE Amex for each fiscal quarter for the two most recent fiscal years and any subsequent period:
  Toronto Stock Exchange (Cdn$)
 
 High


Low2011Q2 through June 8, 2011

$
0.44


$
0.30Q1

$
0.51


$
0.302010Q4

$
0.38


$
0.29Q3

$
0.41


$
0.30Q2

$
0.45


$
0.29Q1

$
0.48


$
0.292009Q4

$
0.65


$
0.30Q3

$
0.57


$
0.24Q2

$
0.50


$
0.23Q1

$
0.76


$
0.23
 
 (1) Common shares listed on Toronto Stock Exchange on November 20, 2008.
 
 NYSE Amex (US$)
 
 High


Low2011Q2 through June 8, 2011

$
0.4489


$
0.3125Q1

$
0.53


$
0.29522010Q4

$
0.3825


$
0.29Q3

$
0.44


$
0.28Q2

$
0.50


$
0.28Q1

$
0.47


$
0.262009Q4

$
0.64


$
0.2761Q3

$
0.525


$
0.21Q2

$
0.45


$
0.184Q1

$
0.67


$
0.12
 (1) Shares listed for trading on NYSE Amex on May 7, 2007
 
 The following table contains the high and low market prices for our common shares on the Toronto Stock Exchange and the NYSE Amex for each of the most recent six months:
  69
  Toronto Stock Exchange (Cdn$)
 
 High


LowNovember, 2010

$
0.38


$
0.31December, 2010

$
0.34


$
0.29January, 2011

$
0.37


$
0.30February, 2011

$
0.33


$
0.30March, 2011

$
0.51


$
0.31April, 2011

$
0.44


$
0.36
 
 NYSE Amex (US$)
 
 High


LowNovember, 2010

$
0.3825


$
0.31December, 2010

$
0.34


$
0.29January, 2011

$
0.37


$
0.2952February, 2011

$
0.3474


$
0.299March, 2011

$
0.53


$
0.32April, 2011

$
0.4489


$
0.35
  On June 8, 2011, the closing price of our common shares on the TSX was Cdn $0.335 per common share and on the NYSE Amex was US $0.3554 per common share.
 
 B.           Plan of Distribution
 
 Not Applicable.
 
 C.           Markets
 
 Our common shares, no par value, are traded on the TSX under the symbol “DEJ” and are traded on the NYSE Amex under the symbol "DEJ".
 
 D.           Selling Shareholders
 
 Not Applicable.
 
 E.           Dilution
 
 Not Applicable.
 
 F.           Expenses of the Issue
 
 Not Applicable.
  70
 
 ITEM 10.  ADDITIONAL INFORMATION
 
 A.           Share Capital
 
 Not Applicable.
 
 B.           Memorandum and Articles of Association
 
 Dejour Enterprises Ltd. (“Dejour” or the “Company””) was incorporated as “Dejour Mines Limited” on March 29, 1968 under the laws of the Province of Ontario. By articles of amendment dated October 30, 2001, the Company changed its name to “Dejour Enterprises Ltd.”. At the Company’s Annual General held on June 3, 2005, shareholders approved the continuance of the Company from the Province of Ontario to the Province of British Columbia and adopted new Articles under the Business Corporations Act (British Columbia) (the “New Act”).
 
 There are no restrictions on what business the Company may carry on in the Articles of Incorporation.
 
 Under Article 17 of the Company’s Articles and Division 3 of the New Act, a director must declare its interest in any existing or proposed contract or transaction with the Company and is not allowed to vote on any transaction or contract with the Company in which has a disclosable interest, unless all directors have a disclosable interest in that contract or transaction, in which case any or all of those directors may vote on such resolution. A director may hold any office or place of profit with the Company in conjunction with the office of director, and no director shall be disqualified by his office from contracting with the Company. A director or his firm may act in a professional capacity for the Company and he or his firm shall be entitled to remuneration for professional services. A director may become a director or other officer or employee of, or otherwise interested in, any corporation or firm in whom the Company may be interested as a shareholder or otherwise. The director shall not be accountable to the Company for any remuneration or other benefits received by him from such other corporation or firm subject to the provisions of the New Act.
 
 Article 16 of the Company’s articles addresses the duties of the directors. Directors must manage or supervise the management of the business and affairs of the Company and have the authority to exercise all such powers which are not required to be exercised by the shareholders as governed by the New Act. Article 19 addresses Committees of the Board of Directors. Directors may, by resolution, create and appoint an executive committee consisting of the director or directors that they deem appropriate. This executive committee has, during the intervals between meetings of the Board, all of the directors’ powers, except the power to fill vacancies in the Board, the power to remove a Director, the power to change the membership of, or fill vacancies in, any committee of the Board and any such other powers as may be set out in the resolution or any subsequent directors’ resolution. Directors may also by resolution appoint one or more committees other than the executive committee.
 
 These committees may be delegated any of the directors’ powers except the power to fill vacancies on the board of directors, the power to remove a director, the power to change the membership or fill vacancies on any committee of the directors, and the power to appoint or remove officers appointed by the directors. Article 18 details the proceedings of directors. A director may, and the Secretary or Assistant Secretary, if any, on the request of a director must call a meeting of the directors at any time. The quorum necessary for the transaction of the business of the directors may be fixed by the directors and if not so fixed shall be deemed to a majority of the directors. If the number of directors is set at one, it quorum is deemed to be one director.
 
 Article 8 details the borrowing powers of the Directors. They may, on behalf of the Company:
 
 ·
Borrow money in a manner and amount, on any security, from any source and upon any terms and conditions as they deem appropriate;
 
 ·
Issue bonds, debentures, and other debt obligations either outright or as security for any liability or obligation of the Company or any other person at such discounts or premiums and on such other terms as they consider appropriate;
  71
  ·
Guarantee the repayment of money by any other person or the performance of any obligation of any other person; and
 
 ·
Mortgage, charge, or grant a security in or give other security on, the whole or any part of the present or future assets and undertaking of the Company.
 
 A director need not be a shareholder of the Company, and there are no age limit requirements pertaining to the retirement or non-retirement of directors. The directors are entitled to the remuneration for acting as directors, if any, as the directors may from time to time determine. If the directors so decide, the remuneration of directors, if any, will be determined by the shareholders. The remuneration may be in addition to any salary or other remuneration paid to any officer or employee of the Company as such who is also a director. The Company must reimburse each director for the reasonable expenses that he or she may incur in and about the business of the Company. If any director performs any professional or other services for the Company that in the opinion of the directors are outside the ordinary duties of a director, or if any director is otherwise specially occupied in or about the Company’s business, he or she may be paid remuneration fixed by the directors, or, at the option of that director, fixed by ordinary resolution and such remuneration may be either in addition to, or in substitution for, any other remuneration that he or she may be entitled to receive. Unless other determined by ordinary resolution, the directors on behalf of the Company may pay a gratuity or pension or allowance on retirement to any director who has held any salaried office or place of profit with the Company or to his or her spouse or dependents and may make contributions to any fund and pay premiums for the purchase or provision of any such gratuity, pension or allowance.
 
 Article 21 provides for the mandatory indemnification of directors, former directors, and alternate directors, as well as his or hers heirs and legal personal representatives, or any other person, to the greatest extent permitted by the New Act. The indemnification includes the mandatory payment of expenses actually and reasonably incurred by such person in respect of that proceeding. The failure of a director, alternate director, or officer of the Company to comply with the Business Corporations Act or the Company’s Articles does not invalidate any indemnity to which he or she is entitled. The directors may cause the Company to purchase and maintain insurance for the benefit of eligible parties who:
 
 (a)
is or was a director, alternate director, officer, employee or agent of the Company;
 
 (b)
is or was a director, alternate director, officer employee or agent of a corporation at a time when the corporation is or was an affiliate of the Company;
 
 (c)
at the request of the Company, is or was a director, alternate director, officer, employee or agent of a corporation or of a partnership, trust, joint venture or other unincorporated entity;
 
 (d)
at the request of the Company, holds or held a position equivalent to that of a director, alternate director or officer of a partnership, trust, joint venture or other unincorporated entity;
 
 against any liability incurred by him or her as such director, alternate director, officer, employee or agent or person who holds or held such equivalent position
 
 The rights, preferences and restrictions attaching to each class of the Company’s shares are as follows:
 Common Shares
 
 The authorized share structure consists of an unlimited number of common shares without par value. All the shares of common stock of the Company are of the same class and, once issued, rank equally as to dividends, voting powers, and participation in assets.  Holders of common stock are entitled to one vote for each share held of record on all matters to be acted upon by the shareholders.  Holders of common stock are entitled to receive such dividends as may be declared from time to time by the Board of Directors, in its discretion, out of funds legally available therefore.
  72
  Upon liquidation, dissolution or winding up of the Company, holders of common stock are entitled to receive pro rata the assets of Company, if any, remaining after payments of all debts and liabilities.  No shares have been issued subject to call or assessment.  There are no pre-emptive or conversion rights and no provisions for redemption or purchase for cancellation, surrender, or sinking or purchase funds.
 
 Under Article 9 and subject to the New Act, the Company may alter its authorized share structure by directors’ resolution or ordinary resolution, in each case determined by the directors, to:
 
 (a)
create one or more classes or series of shares or, if none of the shares of a series of a class or series of shares are allotted or issued, eliminate that class or series of shares;
 
 (b)
increase, reduce or eliminate the maximum number of shares that the Company is authorized to issue out of any class or series of shares or establish a maximum number of shares that the company is authorized to issue out of any class or series of shares for which no maximum is established;
 
 (c)
subdivide or consolidate all or any of its unissued, or fully paid issued, shares;
 
 (d)
if the Company is authorized to issue shares of a class or shares with par value;
 
 (i)
decrease the par value of those shares; or
 
 (ii)
if none of the shares of that class of shares are allotted or issued, increase the par value of those shares;
 
 (e)
change all or any of its unissued, or fully paid issued, shares with par value into shares without par value or any of its unissued shares without par value into shares with par value;
 
 (f)
alter the identifying name of any of its shares; or
 
 by ordinary resolution otherwise alter its share or authorized share structure.
 
 Subject to Article 9.2 and the New Act, the Company may:
 
 (1)
by directors’ resolution or ordinary resolution, in each case determined by the directors, create special rights or restrictions for, and attach those special rights or restrictions to, the shares of any class or series of shares, if none of those shares have been issued, or vary or delete any special rights or restrictions attached to the shares of any class or series of shares, if none of those shares have been issued; and
 
 (2)
by special resolution of the shareholders of the class or series affected, do any of the acts in 91) above if any of the shares of the class or series of shares has been issued.
 
 The Company may by resolution of its directors or by ordinary resolution, in each case as determined by the directors, authorize an alteration of its Notice of Articles in order to change its name.
 
 The directors may, whenever they think fit, call a meeting of shareholders. An annual general meeting shall be held once every calendar year at such time (not being more than 15 months after holding the last preceding annual meeting) and place as may be determined by the Directors.
 
 There are no limitations upon the rights to own securities.
 
 73
 
 There are no provisions that would have the effect of delaying, deferring, or preventing a change in control of the Company.
 
 There is no special ownership threshold above which an ownership position must be disclosed. However, any ownership level above 10% must be disclosed to the TSX Venture Exchange and the British Columbia Securities Commission.
 
 Description of Share Capital
 
 The Company authorized to issue an unlimited number of common shares of which, as of June 8, 2010, 121,390,545 are issued and outstanding. The Company’s common shares are entitled to one vote per share on all matters submitted to a vote of the shareholders, including the election of directors. Except as otherwise required by law the holders of the Company’s common shares will possess all voting power. Generally, all matters to be voted on by shareholders must be approved by a majority (or, in the case of election of directors, by a plurality) of the votes entitled to be cast by all common shares that are present in person or represented by proxy. One holder of common shares issued, outstanding and entitled to vote, represented in person or by proxy, is necessary to constitute a quorum at any meeting of our shareholders.
 
 The holders of the Company’s common shares will be entitled to such cash dividends as may be declared from time to time by our board of directors from funds available therefor.
 
 Upon liquidation, dissolution or winding up of the Company, holders of common shares are entitled to receive pro rata our assets, if any, remaining after payments of all debts and liabilities.  No common shares have been issued subject to call or assessment.  There are no pre-emptive or conversion rights and no provisions for redemption or purchase for cancellation, surrender, or sinking or purchase funds attaching to our common shares.
 
 In the event of any merger or consolidation with or into another company in connection with which the Company’s common shares are converted into or exchangeable for shares, other securities or property (including cash), all holders of the Company’s common shares will be entitled to receive the same kind and amount of shares and other securities and property (including cash).
 
 There are no indentures or agreements limiting the payment of dividends on the Company’s common shares and there are no special liquidation rights or subscription rights attaching to the Company’s common shares.
 
 Dividend Record
 
 The Company has not paid any dividends on its common shares and has no policy with respect to the payment of dividends.
 
 Ownership of Securities and Change of Control
 
 There are no limitations on the rights to own securities, including the rights of non-resident or foreign shareholders to hold or exercise voting rights on the securities imposed by foreign law or by the constituent documents of the Company.
 
 Any person who beneficially owns or controls, directly or indirectly, more than 10% of the Company’s voting shares is considered an insider, and must file an insider report with the Canadian regulatory commissions within ten days of becoming an insider, disclosing any direct or indirect beneficial ownership of, or control over direction over securities of the Company.  In addition, if the Company itself holds any of its own securities, the Company must disclose such ownership.
 
 There are no provisions in the Company’s Memorandum and Articles of Association or Bylaws that would have an effect of delaying, deferring or preventing a change in control of the Company operating only with respect to a merger, acquisition or corporate restructuring involving the Company or its subsidiaries.
  74
  Differences from Requirements in the United States
 
 Except for the Company’s quorum requirements, certain requirements related to related party transactions and the requirement for notice of shareholder meetings, discussed above, there are no significant differences in the law applicable to the Company, in the areas outlined above, in Canada versus the United States.  In most states in the United States, a quorum must consist of a majority of the shares entitled to vote.  Some states allow for a reduction of the quorum requirements to less than a majority of the shares entitled to vote.  Having a lower quorum threshold may allow a minority of the shareholders to make decisions about the Company, its management and operations.  In addition, most states in the United States require that a notice of meeting be mailed to shareholders prior to the meeting date.  Additionally, in the United States, a director may not be able to vote on the approval of any transaction in which the director has an interest.
 
 C.           Material Contracts
 
 The following are material contracts to which the Company is a party:
 
 HEC loan to DEAL
 
 On May 15, 2008, DEAL issued a promissory note for up to $2,000,000 to HEC, a private company controlled by the CEO of the Company. The promissory note is secured by the assets, equipment, fixtures, inventory and accounts receivable of DEAL, bears interest at the Royal Bank of Canada Prime Rate per annum, and has a loan fee of 1% of the outstanding amount per month. The principal, interest and loan fee were payable on demand after August 15, 2008.  Upon securing the bank line of credit in August 2008, HEC signed a subordination and postponement agreement which restricted the principal repayment of the promissory note subject to the bank’s prior approval and DEAL meeting certain loan covenants. As at December 31, 2008, $1,950,000 had been advanced on the promissory note. Repayments of $90,642 and $59,358 were made on March 5, 2009 and on April 3, 2009 respectively. As at June 22, 2009, the Company assumed from DEAL the remaining outstanding balance of $1,800,000.
 
 HEC loan to the Company
 
 On August 11, 2008, the Company borrowed $600,000 from HEC.  The loan was secured by all assets of the Company, repayable on demand, bore interest at the Canadian prime rate per annum, and had a loan fee of 1% of the outstanding amount per month.  At December 31, 2008 $600,000 had been advanced to the Company.  On March 19, 2009, a repayment of $600,000 was made and as at December 31, 2009, no balance remained outstanding.
 
 On September 12, 2008, as consideration for HEC agreeing to postpone the $2,000,000 promissory note and providing the additional loan of $600,000, HEC was granted an option to become a working interest partner with DEAL.  Upon electing to become a working interest partner, HEC must pay DEAL an amount equal to 10% of the actual price paid for the acquisition of the Montney (Buick Creek) property in northeastern British Columbia.  HEC is also required to pay its pro-rata share of the operating costs. On February 26, 2009, HEC exercised its option and elected to become a 10% working interest partner in DEAL’s Montney (Buick Creek) property.  The option price was $90,642.
 
 On June 22, 2009, as amended on September 30, 2009 and December 31, 2009, the Company entered into an agreement with HEC in regard to the outstanding debt of $1,800,000 assumed from DEAL by the Company.  Pursuant to the agreements, $450,000 of the debt was converted into 1,363,636 units consisting of 1,363,636 common shares and 681,818 common share purchase warrants exercisable at a price of $0.55 for a period of 5 years.  The fair value of the units was estimated to be $450,000. The remaining $1,350,000 was converted into a 12% note due on January 1, 2011 and the Company was required to pay 3% fee on the outstanding balance of the loan as at December 31, 2009.  As a result of the sale of 5% working interest in the Drake/Woodrush area to HEC in December 2009 (effective June 1, 2009), both parties agreed to reduce the loan balance by the purchase price of $911,722 including taxes and adjustments. In addition, the loan balance was further reduced by a payment of $50,351.  As at December 31, 2009, a balance of $387,927 remained outstanding. In December 2010, a repayment of $137,927 was made to HEC by the Company. As at December 31, 2010, a balance of $250,000 remained outstanding. Subsequent to December 31, 2010, the loan was repaid in full in cash.
  75
   Brownstone loan to the Company
 
 On June 18, 2008, a promissory note with a face value of $4,078,800 (US $4,000,000) was issued to Brownstone. Brownstone owns more than 10% of outstanding common shares of the Company and one of Brownstone’s directors also serves on the board of directors of the Company. The promissory note was secured by a general security agreement issued by the Company in favour of Brownstone, and bore interest at 5% per annum.   The principal and interest were repayable by the earlier of the completion of an equity and/or debt financing, and July 1, 2009.  During the year ended December 31, 2008, a repayment of $222,948 (US$220,000) was made and at December 31, 2008 a balance of $4,604,040 (US$3,780,000) owed.
 
 On June 22, 2009, as amended on September 30, 2009 and December 31, 2009, the Company entered into an agreement with Brownstone in regard to the outstanding debt of $4,604,040 (US$3,780,000). Pursuant to the agreement, $2,200,000 (US$2,000,000) of the debt was converted into 6,666,667 units consisting of 6,666,667 common shares and 3,333,333 common share purchase warrants exercisable at a price of $0.55 for a period of 5 years.  The fair value of the units was estimated to be US$2,000,000.  The remaining $2,070,140 (US$1,780,000) of the debt was converted into a Canadian dollar denominated 12% note due on January 1, 2011.  As at December 31, 2009, a balance of $1,957,474 remained outstanding comprised of the loan balance of $2,070,140 minus unamortized portion of finance fees of $112,666. In December 2010, the loan was paid off in full in cash.
 
 On June 22, 2009, the Company also issued Brownstone 2,000,000 common share purchase warrants exercisable at $0.50 for a period of 2 years, with an option to force the exercise of the warrants if the Company’s common shares trade at a price of $0.80 or greater for 30 consecutive calendar days.
 
 Purchase and Sale Agreement between the Registrant and Pengrowth Corporation dated April 17, 2009
 
 In April 2009, the Company’s Canadian subsidiary, DEAL, entered into a purchase and sale agreement with Pengrowth Corporation. Under the agreement, DEAL agreed to sell 100% of its working interest in the Carson Creek area to Pengrowth for gross proceeds of $2,100,000.
 
 In 2009, the Company’s Canadian subsidiary, DEAL, entered into the following purchase and sale Agreements in regard to the disposition of a total 25% working interest in the Drake/Woodrush area for total gross proceeds of $4,500,000:
 
 Date of agreement

Transferee

Working interest %


Gross ProceedsJune 10, 2009

John James Robinson


3
%

$
540,000June 15, 2009

C.U. YourOilRig Corp.


10
%

$
1,800,000July 8, 2009

Woodrush Energy Partners LLC


6
%

$
1,080,000July 31, 2009

RockBridge Energy Inc.


1
%

$
180,000December 31, 2009

HEC


5
%

$
900,000
  Property Purchase Agreement between the Registrant and Titan Uranium Inc. dated December 13, 2006
 
 In December 2006, the Company sold a 90% interest in its uranium properties, consisting of 68 claims and 4 permits totaling 966,969 acres located in the Athabasca Basin, Saskatchewan, Canada, and all related exploration data to Titan Uranium Inc. (“Titan”), a public company traded on the TSX-V, under the following terms:
 
 (a)
Titan issued the Company 17,500,000 fully paid and assessable common shares in the capital of Titan (representing a 36.47% of Titan’s issued and outstanding shares at closing).  Titan issued the Company 3,000,000 transferable common share purchase warrants, entitling the holder to acquire up to 3,000,000 common shares in the capital of Titan at an exercise price of $2.00 per common share for a period of 24 months. These warrants expired unexercised on December 15, 2008;
 
 (b)
The Company retained a 1% Net Smelter Return on all properties and a 10% working interest in each claim, carried by Titan to completed bankable feasibility study after which the Company may elect to participate as to its 10% interest or convert to an additional 1% Net Smelter Return.
  76
  The Company accounted for its investment in Titan using the equity method until February 28, 2009, at which point the Company disposed of the majority of its shares in Titan and therefore is no longer qualified for the use of the equity method of accounting.  The Company’s share of losses in Titan under the equity method for the year ended December 31, 2009 was $142,196 (2008 share of income: $3,636,710).   During the year ended December 31, 2009, the Company sold all of its investment in Titan, resulting in a loss of $274,187 (2008: $8,846).
 
 During the year ended December 31, 2008, the Company recognized an impairment loss of $12,990,343 and wrote down its investment in Titan to $2,721,875, the fair value as at December 31, 2008.
 
 Participation Agreement between the Registrant, Retamco Operating, Inc. and Brownstone Ventures (US) dated July 14, 2006
 
 In July 2006, the Company’s U.S. subsidiary, Dejour USA, entered into a participation agreement (the "2006 Retamco Agreement") with Retamco Operating, Inc. (“Retamco”), a U.S. privately owned oil and gas corporation, and Brownstone Ventures (US) Inc. (“Brownstone”), a subsidiary of Brownstone Ventures Inc., a Canadian company listed on the TSX-V.  Under the agreement, Dejour USA and Brownstone agreed to participate in the ownership of specified oil and gas leasehold interests and related exploration and development of those leases located in the Piceance, Uinta and Paradox Basins of western Colorado and eastern Utah.
 
 Purchase and Sale Agreement between the Registrant, Retamco Operating, Inc., and Brownstone Ventures (US) Inc.
 
 In June 2008, Dejour USA entered into a further purchase and sale agreement with Retamco resulting in Dejour USA acquiring an additional 64,000 net acres involving the same properties in which it purchased an interest in the 2006 Retamco Agreement.  Additionally, as a part of this latter agreement Dejour USA sold its 25% working interests in two wells in the North Barcus Creek Prospect (located in Piceance Basin, Colorado) and roughly 3,682 net acres in the Rio Blanco Deep Prospect (located in northern Colorado).
 
 D.
Exchange Controls
 
 There are no governmental laws, decrees, or regulations in Canada relating to restrictions on the export or import of capital, or affecting the remittance of interest, dividends, or other payments to non-resident holders of the Company’s Common Stock.  Any remittances of dividends to United States residents are, however, subject to a 15% withholding tax (10% if the shareholder is a corporation owning at least 10% of the outstanding Common Stock of the Company) pursuant to Article X of the reciprocal tax treaty between Canada and the United States.
 
 Except as provided in the Investment Canada Act (the “Act”), there are no limitations specific to the rights of non-Canadians to hold or vote the Common Stock of the Company under the laws of Canada or the Province of British Columbia or in the charter documents of the Company.
 
 Management of the Company considers that the following general summary is materially complete and fairly describes those provisions of the Act pertinent to an investment by an American investor in the Company.
 
 The Act requires a non-Canadian making an investment which would result in the acquisition of control of a Canadian business, the gross value of the assets of which exceed certain threshold levels or the business activity of which is related to Canada’s cultural heritage or national identity, to either notify, or file an application for review with, Investment Canada, the federal agency created by the Investment Canada Act.
 
 The notification procedure involves a brief statement of information about the investment of a prescribed form which is required to be filed with Investment Canada by the investor at any time up to 30 days following implementation of the investment.  It is intended that investments requiring only notification will proceed without government intervention unless the investment is in a specific type of business activity related to Canada’s cultural heritage and national identity.
  77
  If an investment is reviewable under the Act, an application for review in the form prescribed is normally required to be filed with Investment Canada prior to the investment taking place and the investment may not be implemented until the review has been completed and the Minister responsible for Investment Canada is satisfied that the investment is likely to be of net benefit to Canada.  If the Minister is not satisfied that the investment is likely to be of net benefit to Canada, the non-Canadian must not implement the investment or, if the investment has been implemented, may be required to divest himself of control of the business that is the subject of the investment.
 
 The following investments by non-Canadians are subject to notification under the Act:
 
 (a)
an investment to establish a new Canadian business; and
 
 (b)
an investment to acquire control of a Canadian business that is not reviewable pursuant to the Act.
 
 An investment is reviewable under the Act if there is an acquisition by a non-Canadian of a Canadian business and the asset value of the Canadian business being acquired equals or exceeds the following thresholds:
 
 (a)
for non-WTO Investors, the threshold is $5,000,000 for a direct acquisition and over $50,000,000 for an indirect acquisition.  The $5,000,000 threshold will apply however for an indirect acquisition of the asset value of the Canadian business being acquired exceeds 50% of the asset value of the global transaction;
 
 (b)
except as specified in paragraph (c) below, a threshold is calculated for reviewable direct acquisitions by or from WTO Investors.  The threshold for 2005 is $250,000,000.  Pursuant to Canada’s international commitments, indirect acquisitions by or from WTO Investors are not reviewable; and
 
 (c)
the limits set out in paragraph (a) apply to all investors for acquisitions of a Canadian business that:
 
 (i)
engages in the production of uranium and owns an interest in a producing uranium property in Canada;
 (ii)
provides any financial services;
 (iii)
provides any transportation service; or
 (iv)
is a cultural business.
 
 WTO Investor as defined in the Act means:
 
 (a)
an individual, other than a Canadian, who is a national of a WTO Member or who has the right of permanent residence in relation to that WTO Member;
 
 (b)
a government of a WTO Member, whether federal, state or local, or an agency thereof;
 
 an entity that is not a Canadian-controlled entity, and that is a WTO investor-controlled entity, as determined in accordance with the Act;
 
 (c)
a corporation or limited partnership:
 
 (i)
that is not a Canadian-controlled entity, as determined pursuant to the Act;
 (ii)
that is not a WTO investor within the meaning of the Act;
 (iii)
of which less than a majority of its voting interests are owned by WTO investors;
 (iv)
that is not controlled in fact through the ownership of its voting interests; and
 (v)
of which two thirds of the members of its board of directors, or of which two thirds of its general partners, as the case may be, are any combination of Canadians and WTO investors;
 
 (d)
a trust:
 
 (i)
that is not a Canadian-controlled entity, as determined pursuant to the Act;
 (ii)
that is not a WTO investor within the meaning of the Act;
 (iii)
that is not controlled in fact through the ownership of its voting interests, and
 (iv)
of which two thirds of its trustees are any combination of Canadians and WTO investors, or
  78
  (e)
any other form of business organization specified by the regulations that is controlled by a WTO investor.
 
 WTO Member as defined in the Act means a member of the World Trade Organization.
 
 Generally speaking, an acquisition is direct if it involves the acquisition of control of the Canadian business or of its Canadian parent or grandparent and an acquisition is indirect if it involves the acquisition of control of a non-Canadian parent or grandparent of an entity carrying on the Canadian business.  Control may be acquired through the acquisition of actual or de jure voting control of a Canadian corporation or through the acquisition of substantially all of the assets of the Canadian business.  No change of voting control will be deemed to have occurred if less than one-third of the voting control of a Canadian corporation is acquired by an investor.
 
 The Act specifically exempts certain transactions from either notification or review.  Included among the category of transactions is the acquisition of voting shares or other voting interests by any person in the ordinary course of that person’s business as a trader or dealer in securities.
 
 E.
Taxation
 
 Canadian Federal Income Tax Considerations
 
 The following is a brief summary of some of the principal Canadian federal income tax consequences to a holder of common shares of the Company (a “U.S. Holder”) who deals at arm’s length with the Company, holds the shares as capital property and who, for the purposes of the Income Tax Act (Canada) (the “Act”) and the Canada – United States Income Tax Convention (the “Treaty”), is at all relevant times resident in the United States, is not and is not deemed to be resident in Canada and does not use or hold and is not deemed to use or hold the shares in carrying on a business in Canada.  Special rules, which are not discussed below, may apply to a U.S. Holder that is an insurer that carries on business in Canada and elsewhere.
 
 Under the Act and the Treaty, a U.S. Holder of common shares will generally be subject to a 15% withholding tax on dividends paid or credited or deemed by the Act to have been paid or credited on such shares.  The withholding tax rate is 5% where the U.S. Holder is a corporation that beneficially owns at least 10% of the voting shares of the Company and the dividends may be exempt from such withholding in the case of some U.S. Holders such as qualifying pension funds and charities.
 
 In general, a U.S. Holder will not be subject to Canadian income tax on capital gains arising on the disposition of shares of the Company unless (i) at any time in the five-year period immediately preceding the disposition, 25% or more of the shares of any class or series of the capital stock of the Company was owned by (or was under option of or subject to an interest of) the U.S. holder or persons with whom the U.S. holder did not deal at arm’s length, and (ii) the value of the common shares of the Company at the time of the disposition derives principally from real property (as defined in the Treaty) situated in Canada. For this purpose, the Treaty defines real property situated in Canada to include rights to explore for or exploit mineral deposits and other natural resources situated in Canada, rights to amounts computed by reference to the amount or value of production from such resources, certain other rights in respect of natural resources situated in Canada and shares of a corporation the value of whose shares is derived principally from real property situated in Canada.
 
 The US Internal Revenue Code provides special anti-deferral rules regarding certain distributions received by US persons with respect to, and sales and other dispositions (including pledges) of stock of, a passive foreign investment company. A foreign corporation, such as the Company, will be treated as a passive foreign investment company if 75% or more of its gross income is passive income for a taxable year or if the average percentage of its assets (by value) that produce, or are held for the production of, passive income is at least 50% for a taxable year. The Company believes that it was not a passive foreign investment company for the taxable year ended 12/31/2003 and, furthermore, expects to conduct its affairs in such a manner so that it will not meet the criteria to be considered passive foreign investment company in the foreseeable future.
  79
  Dividends
 
 A Holder will be subject to Canadian withholding tax (“Part XIII Tax”) equal to 25%, or such lower rate as may be available under an applicable tax treaty, of the gross amount of any dividend paid or deemed to be paid on common shares.  Under the Canada-U.S. Income Tax Convention (1980) as amended by the Protocols signed on 6/14/1983, 3/28/1984, 3/17/1995, and 7/29/1997 (the “Treaty”), the rate of Part XIII Tax applicable to a dividend on common shares paid to a Holder who is a resident of the United States and who is the beneficial owner of the dividend, is 5%.  If the Holder is a company that owns at least 10% of the voting stock of the Company paying the dividend, and, in all other cases, the tax rate is 15% of the gross amount of the dividend.  The Company will be required to withhold the applicable amount of Part XIII Tax from each dividend so paid and remit the withheld amount directly to the Receiver General for Canada for the account of the Holder.
 
 Disposition of Common Shares
 
 A Holder who disposes of a common share, including by deemed disposition on death, will not normally be subject to Canadian tax on any capital gain (or capital loss) thereby realized unless the common share constituted “taxable Canadian property” as defined by the Tax Act.  Generally, a common share of a public corporation will not constitute taxable Canadian property of a Holder if the share is listed on a prescribed stock exchange unless the Holder or persons with whom the Holder did not deal at arm’s length alone or together held or held options to acquire, at any time within the five years preceding the disposition, 25% or more of the shares of any class of the capital stock of the Company.  The Canadian Venture Exchange is a prescribed stock exchange under the Tax Act.  A Holder who is a resident of the United States and realizes a capital gain on a disposition of a common share that was taxable Canadian property will nevertheless, by virtue of the Treaty, generally be exempt from Canadian tax thereon unless (a) more than 50% of the value of the common shares is derived from, or from an interest in, Canadian real estate, including Canadian mineral resource properties, (b) the common share formed part of the business property of a permanent establishment that the Holder has or had in Canada within the 12 month period preceding the disposition, or (c) the Holder is an individual who (i) was a resident of Canada at any time during the 10 years immediately preceding the disposition, and for a total of 120 months during any period of 20 consecutive years, preceding the disposition, and (ii) owned the common share when he ceased to be resident in Canada.
 
 A Holder who is subject to Canadian tax in respect of a capital gain realized on a disposition of a common share must include three quarters of the capital gain (taxable capital gain) in computing the Holder’s taxable income earned in Canada.  The Holder may, subject to certain limitations, deduct three-quarters of any capital loss (allowable capital loss) arising on a disposition of taxable Canadian property from taxable capital gains realized in the year of disposition in respect to taxable Canadian property and, to the extent not so deductible, from such taxable capital gains realized in any of the three preceding years or any subsequent year.
 
 CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
 
 The following is a general summary of certain material U.S. federal income tax considerations applicable to a U.S. Holder (as defined below) arising from and relating to the acquisition, ownership, and disposition of common shares of the Company.
 
 This summary is for general information purposes only and does not purport to be a complete analysis or listing of all potential U.S. federal income tax considerations that may apply to a U.S. Holder arising from and relating to the acquisition, ownership, and disposition of common shares.  In addition, this summary does not take into account the individual facts and circumstances of any particular U.S. Holder that may affect the U.S. federal income tax consequences to such U.S. Holder, including specific tax consequences to a U.S. Holder under an applicable tax treaty.  Accordingly, this summary is not intended to be, and should not be construed as, legal or U.S. federal income tax advice with respect to any U.S. Holder.  Each U.S. Holder should consult its own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences relating to the acquisition, ownership and disposition of common shares.
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  No legal opinion from U.S. legal counsel or ruling from the Internal Revenue Service (the “IRS”) has been requested, or will be obtained, regarding the U.S. federal income tax consequences of the acquisition, ownership, and disposition of common shares.  This summary is not binding on the IRS, and the IRS is not precluded from taking a position that is different from, and contrary to, the positions taken in this summary.  In addition, because the authorities on which this summary is based are subject to various interpretations, the IRS and the U.S. courts could disagree with one or more of the positions taken in this summary.
 
 Scope of this Summary
 
 Authorities
 
 This summary is based on the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations (whether final, temporary, or proposed), published rulings of the IRS, published administrative positions of the IRS, U.S. court decisions, the Convention Between Canada and the United States of America with Respect to Taxes on Income and on Capital, signed September 26, 1980, as amended (the “Treaty”), and U.S. court decisions that are applicable and, in each case, as in effect and available, as of the date of this document.  Any of the authorities on which this summary is based could be changed in a material and adverse manner at any time, and any such change could be applied on a retroactive or prospective basis which could affect the U.S. federal income tax considerations described in this summary.  This summary does not discuss the potential effects, whether adverse or beneficial, of any proposed legislation that, if enacted, could be applied on a retroactive or prospective basis.
 
 U.S. Holders
 
 For purposes of this summary, the term "U.S. Holder" means a beneficial owner of common shares that is for U.S. federal income tax purposes:
 
 ·
an individual who is a citizen or resident of the U.S.;
  ·
a corporation (or other entity taxable as a corporation for U.S. federal income tax purposes) organized under the laws of the U.S., any state thereof or the District of Columbia;
  ·
an estate whose income is subject to U.S. federal income taxation regardless of its source; or
  ·
a trust that (a) is subject to the primary supervision of a court within the U.S. and the control of one or more U.S. persons for all substantial decisions or (b) has a valid election in effect under applicable Treasury regulations to be treated as a U.S. person.
  Non-U.S. Holders
 
 For purposes of this summary, a “non-U.S. Holder” is a beneficial owner of common shares that is not a U.S. Holder.  This summary does not address the U.S. federal income tax consequences to non-U.S. Holders arising from and relating to the acquisition, ownership, and disposition of common shares.  Accordingly, a non-U.S. Holder should consult its own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences (including the potential application of and operation of any income tax treaties) relating to the acquisition, ownership, and disposition of common shares.
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  U.S. Holders Subject to Special U.S. Federal Income Tax Rules Not Addressed
 
 This summary does not address the U.S. federal income tax considerations applicable to U.S. Holders that are subject to special provisions under the Code, including the following U.S. Holders:  (a) U.S. Holders that are tax-exempt organizations, qualified retirement plans, individual retirement accounts, or other tax-deferred accounts; (b) U.S. Holders that are financial institutions, underwriters, insurance companies, real estate investment trusts, or regulated investment companies; (c) U.S. Holders that are dealers in securities or currencies or U.S. Holders that are traders in securities that elect to apply a mark-to-market accounting method; (d) U.S. Holders that have a “functional currency” other than the U.S. dollar; (e) U.S. Holders that own common shares as part of a straddle, hedging transaction, conversion transaction, constructive sale, or other arrangement involving more than one position; (f) U.S. Holders that acquired common shares in connection with the exercise of employee stock options or otherwise as compensation for services; (g) U.S. Holders that hold common shares other than as a capital asset within the meaning of Section 1221 of the Code (generally, property held for investment purposes); (h) partnerships and other pass-through entities (and investors in such partnerships and entities); or (i) U.S. Holders that own or have owned  (directly, indirectly, or by attribution) 10% or more of the total combined voting power of the outstanding shares of the Company.  This summary also does not address the U.S. federal income tax considerations applicable to U.S. Holders who are: (a) U.S. expatriates or former long-term residents of the U.S. subject to Section 877 of the Code; (b) persons that have been, are, or will be a resident or deemed to be a resident in Canada for purposes of the Act; (c) persons that use or hold, will use or hold, or that are or will be deemed to use or hold common shares in connection with carrying on a business in Canada; (d) persons whose common shares constitute “taxable Canadian property” under the Act; or (e) persons that have a permanent establishment in Canada for the purposes of the Treaty.  U.S. Holders that are subject to special provisions under the Code, including U.S. Holders described immediately above, should consult their own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences relating to the acquisition, ownership and disposition of common shares.
 
 If an entity that is classified as a partnership (or pass-through entity) for U.S. federal income tax purposes holds common shares, the U.S. federal income tax consequences to such partnership and the partners of such partnership generally will depend on the activities of the partnership and the status of such partners.  Partners of entities that are classified as partnerships for U.S. federal income tax purposes should consult their own tax advisor regarding the U.S. federal income tax consequences arising from and relating to the acquisition, ownership, and disposition of common shares.
 
 Tax Consequences Not Addressed
 
 This summary does not address the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences to U.S. Holders of the acquisition, ownership, and disposition of common shares.  Each U.S. Holder should consult its own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences of the acquisition, ownership, and disposition of common shares.
 
 U.S. Federal Income Tax Consequences of the Acquisition, Ownership, and Disposition of Common Shares
  If the Company is not considered a “passive foreign investment company” (a “PFIC”, as defined below) at any time during a U.S. Holder’s holding period, the following sections will generally describe the U.S. federal income tax consequences to U.S. Holders of the acquisition, ownership, and disposition of the Company’s common shares.
  Distributions on Common Shares
  A U.S. Holder that receives a distribution, including a constructive distribution, with respect to a common share will be required to include the amount of such distribution in gross income as a dividend (without reduction for any Canadian income tax withheld from such distribution) to the extent of the current or accumulated “earnings and profits” of the Company, as computed for U.S. federal income tax purposes.  A dividend generally will be taxed to a U.S. Holder at ordinary income tax rates.  To the extent that a distribution exceeds the current and accumulated “earnings and profits” of the Company, such distribution will be treated first as a tax-free return of capital to the extent of a U.S. Holder’s tax basis in the common shares and thereafter as gain from the sale or exchange of such common shares (see “Sale or Other Taxable Disposition of Common Shares” below).  However, the Company does not intend to maintain the calculations of earnings and profits in accordance with U.S. federal income tax principles, and each U.S. Holder should therefore assume that any distribution by the Company with respect to the common shares will constitute ordinary dividend income.  Dividends received on common shares generally will not be eligible for the “dividends received deduction.”
  For taxable years beginning before January 1, 2011, a dividend paid by the Company generally will be taxed at the preferential tax rates applicable to long-term capital gains if (a) the Company is a “qualified foreign corporation” (as defined below), (b) the U.S. Holder receiving such dividend is an individual, estate, or trust, and (c) certain holding period requirements are met.  The Company generally will be a “qualified foreign corporation” under Section 1(h)(11) of the Code (a “QFC”) if (a) the Company is eligible for the benefits of the Treaty, or (b) common shares of the Company are readily tradable on an established securities market in the U.S.  However, even if the Company satisfies one or more of such requirements, the Company will not be treated as a QFC if the Company is a PFIC for the taxable year during which the Company pays a dividend or for the preceding taxable year.  (See the section below under the heading "Passive Foreign Investment Company Rules").
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  If the Company is a QFC, but a U.S. Holder otherwise fails to qualify for the preferential tax rate applicable to dividends discussed above, a dividend paid by the Company to a U.S. Holder, including a U.S. Holder that is an individual, estate, or trust, generally will be taxed at ordinary income tax rates (and not at the preferential tax rates applicable to long-term capital gains).  The dividend rules are complex, and each U.S. Holder should consult its own tax advisor regarding the dividend rules.
  Sale or Other Taxable Disposition of Common Shares
  A U.S. Holder will recognize gain or loss on the sale or other taxable disposition of common shares in an amount equal to the difference, if any, between (a) the amount of cash plus the fair market value of any property received and (b) such U.S. Holder’s tax basis in such common shares sold or otherwise disposed of.  Subject to the PFIC rules discussed below, any such gain or loss generally will be capital gain or loss, which will be long-term capital gain or loss if, at the time of the sale or other disposition, such common shares are held for more than one year.
  Gain or loss recognized by a U.S. Holder on the sale or other taxable disposition of common shares generally will be treated as “U.S. source” for purposes of applying the U.S. foreign tax credit rules unless the gain is subject to tax in Canada and is sourced as “foreign source” under the Treaty and such U.S. Holder elects to treat such gain or loss as “foreign source.”
  Preferential tax rates apply to long-term capital gains of a U.S. Holder that is an individual, estate, or trust.  There are currently no preferential tax rates for long-term capital gains of a U.S. Holder that is a corporation.  Deductions for capital losses are subject to significant limitations under the Code.
  Recent Legislative Developments
 
 Newly enacted legislation requires certain U.S. Holders who are individuals, estates or trusts to pay up to an additional 3.8% tax on, among other things, dividends and capital gains for taxable years beginning after December 31, 2012.  In addition, for taxable years beginning after March 18, 2010, new legislation requires certain U.S. Holders who are individuals that hold certain foreign financial assets (which may include the common shares) to report information relating to such assets, subject to certain exceptions.  U.S. Holders should consult their tax advisors regarding the effect, if any, of this legislation on their ownership and disposition of common shares.
 
 Receipt of Foreign Currency
  The amount of any distribution paid in foreign currency to a U.S. Holder in connection with the ownership of common shares, or on the sale, exchange or other taxable disposition of common shares, generally will be equal to the U.S. dollar value of such foreign currency based on the exchange rate applicable on the date of receipt (regardless of whether such foreign currency is converted into U.S. dollars at that time).  A U.S. Holder that receives foreign currency and converts such foreign currency into U.S. dollars at a conversion rate other than the rate in effect on the date of receipt may have a foreign currency exchange gain or loss, which generally would be treated as U.S. source ordinary income or loss.  If the foreign currency received is not converted into U.S. dollars on the date of receipt, a U.S. Holder will have a basis in the foreign currency equal to its U.S. dollar value on the date of receipt.  Any U.S. Holder who receives payment in foreign currency and engages in a subsequent conversion or other disposition of the foreign currency may have a foreign currency exchange gain or loss that would be treated as ordinary income or loss, and generally will be U.S. source income or loss for foreign tax credit purposes.  Each U.S. Holder should consult its own U.S. tax advisor regarding the U.S. federal income tax consequences of receiving, owning, and disposing of foreign currency.
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  Foreign Tax Credit
  A U.S. Holder who pays (whether directly or through withholding) Canadian income tax with respect to dividends paid on common shares generally will be entitled, at the election of such U.S. Holder, to receive either a deduction or a credit for such Canadian income tax paid.  Generally, a credit will reduce a U.S. Holder’s U.S. federal income tax liability on a dollar-for-dollar basis, whereas a deduction will reduce a U.S. Holder’s income subject to U.S. federal income tax.  This election is made on a year-by-year basis and applies to all foreign taxes paid (whether directly or through withholding) by a U.S. Holder during a year.
  Complex limitations apply to the foreign tax credit, including the general limitation that the credit cannot exceed the proportionate share of a U.S. Holder’s U.S. federal income tax liability that such U.S. Holder’s “foreign source” taxable income bears to such U.S. Holder’s worldwide taxable income.  In applying this limitation, a U.S. Holder’s various items of income and deduction must be classified, under complex rules, as either “foreign source” or “U.S. source.”  Generally, dividends paid by a foreign corporation should be treated as foreign source for this purpose, and gains recognized on the sale of stock of a foreign corporation by a U.S. Holder should be treated as U.S. source for this purpose, except as otherwise provided in an applicable income tax treaty, and if an election is properly made under the Code.  However, the amount of a distribution with respect to the common shares that is treated as a “dividend” may be lower for U.S. federal income tax purposes than it is for Canadian federal income tax purposes, resulting in a reduced foreign tax credit allowance to a U.S. Holder.  In addition, this limitation is calculated separately with respect to specific categories of income.  Dividends paid by the Company generally will constitute “foreign source” income and generally will be categorized as “passive income.”
  The foreign tax credit rules are complex, and each U.S. Holder should consult its own tax advisor regarding the foreign tax credit rules.
  Information Reporting; Backup Withholding Tax For Certain Payments
  Under U.S. federal income tax law and regulations, certain categories of U.S. Holders must file information returns with respect to their investment in, or involvement in, a foreign corporation.  For example, recently enacted legislation generally imposes new U.S. return disclosure obligations (and related penalties) on U.S. Holders that hold certain specified foreign financial assets in excess of $50,000.  The definition of specified foreign financial assets includes not only financial accounts maintained in foreign financial institutions, but also, unless held in accounts maintained by a financial institution, any stock or security issued by a non-U.S. person, any financial instrument or contract held for investment that has an issuer or counterparty other than a U.S. person and any interest in a foreign entity.  U. S. Holders may be subject to these reporting requirements unless their common shares are held in an account at a domestic financial institution.  Penalties for failure to file certain of these information returns are substantial.  U.S. Holders of common shares should consult with their own tax advisors regarding the requirements of filing information returns, and if applicable, any “mark-to-market election” or “QEF election” (each as defined below).
  Payments made within the U.S., or by a U.S. payor or U.S. middleman, of dividends on, and proceeds arising from the sale or other taxable disposition of, common shares generally will be subject to information reporting and backup withholding tax, at the rate of 28% (and increasing to 31% for payments made after December 31, 2010), if a U.S. Holder (a) fails to furnish such U.S. Holder’s correct U.S. taxpayer identification number (generally on Form W-9), (b) furnishes an incorrect U.S. taxpayer identification number, (c) is notified by the IRS that such U.S. Holder has previously failed to properly report items subject to backup withholding tax, or (d) fails to certify, under penalty of perjury, that such U.S. Holder has furnished its correct U.S. taxpayer identification number and that the IRS has not notified such U.S. Holder that it is subject to backup withholding tax.  However, certain exempt persons, such as corporations, generally are excluded from these information reporting and backup withholding tax rules.  Any amounts withheld under the U.S. backup withholding tax rules will be allowed as a credit against a U.S. Holder’s U.S. federal income tax liability, if any, or will be refunded, if such U.S. Holder furnishes required information to the IRS in a timely manner.  Each U.S. Holder should consult its own tax advisor regarding the information reporting and backup withholding rules.
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  Passive Foreign Investment Company Rules
  If the Company were to constitute a PFIC (as defined below) for any year during a U.S. Holder’s holding period, then certain different and potentially adverse tax consequences would apply to such U.S. Holder’s acquisition, ownership and disposition of common shares.
 
 The Company generally will be a PFIC under Section 1297 of the Code if, for a tax year, (a) 75% or more of the gross income of the Company for such tax year is passive income (the “income test”) or (b) 50% or more of the value of its average quarterly assets held by the Company either produce passive income or are held for the production of passive income, based on the fair market value of such assets (the “asset test”).  “Gross income” generally means all revenues less the cost of goods sold, and “passive income” includes, for example, dividends, interest, certain rents and royalties, certain gains from the sale of stock and securities, and certain gains from commodities transactions.  Active business gains arising from the sale of commodities generally are excluded from passive income if substantially all of a foreign corporation’s commodities are (a) stock in trade of such foreign corporation or other property of a kind which would properly be included in inventory of such foreign corporation, or property held by such foreign corporation primarily for sale to customers in the ordinary course of business, (b) property used in the trade or business of such foreign corporation that would be subject to the allowance for depreciation under Section 167 of the Code, or (c) supplies of a type regularly used or consumed by such foreign corporation in the ordinary course of its trade or business.
 
 In addition, for purposes of the PFIC income test and asset test described above, if the Company owns, directly or indirectly, 25% or more of the total value of the outstanding shares of another foreign corporation, the Company will be treated as if it (a) held a proportionate share of the assets of such other foreign corporation and (b) received directly a proportionate share of the income of such other foreign corporation.  In addition, for purposes of the PFIC income test and asset test described above, “passive income” does not include any interest, dividends, rents, or royalties that are received or accrued by the Company from a “related person” (as defined in Section 954(d)(3) of the Code), to the extent such items are properly allocable to the income of such related person that is not passive income.
 
 Under certain attribution rules, if the Company is a PFIC, U.S. Holders will be deemed to own their proportionate share of any subsidiary of the Company which is also a PFIC (a ‘‘Subsidiary PFIC’’), and will be subject to U.S. federal income tax on (i) a distribution on the shares of a Subsidiary PFIC or (ii) a disposition of shares of a Subsidiary PFIC, both as if the holder directly held the shares of such Subsidiary PFIC.
 
 The Company does not believe that it was a PFIC during the tax year ending December 31, 2009 and December 31, 2010, and based on current business plans and financial expectations, the Company does not believe that it will be a PFIC for the current tax year.  However, PFIC classification is fundamentally factual in nature, generally cannot be determined until the close of the tax year in question, and is determined annually.  Additionally, the analysis depends, in part, on the application of complex U.S. federal income tax rules, which are subject to differing interpretations.  Consequently, there can be no assurance that the Company has never been and will not become a PFIC for any tax year during which U.S. Holders hold common shares.
 
 If the Company were a PFIC in any tax year and a U.S. Holder held common shares, such holder generally would be subject to special rules with respect to “excess distributions” made by the Company on the common shares and with respect to gain from the disposition of common shares. An “excess distribution” generally is defined as the excess of distributions with respect to the common shares received by a U.S Holder in any tax year over 125% of the average annual distributions such U.S. Holder has received from the Company during the shorter of the three preceding tax years, or such U.S. Holder’s holding period for the common shares. Generally, a U.S. Holder would be required to allocate any excess distribution or gain from the disposition of the common shares ratably over its holding period for the common shares. Such amounts allocated to the year of the disposition or excess distribution would be taxed as ordinary income, and amounts allocated to prior tax years would be taxed as ordinary income at the highest tax rate in effect for each such year and an interest charge at a rate applicable to underpayments of tax would apply.
  While there are U.S. federal income tax elections that sometimes can be made to mitigate these adverse tax consequences (including, without limitation, the “QEF Election” and the “Mark-to-Market Election”), such elections are available in limited circumstances and must be made in a timely manner.  U.S. Holders should be aware that, for each tax year, if any, that the Company is a PFIC, the Company can provide no assurances that it will satisfy the record keeping requirements of a PFIC, or that it will make available to U.S. Holders the information such U.S. Holders require to make a QEF Election under Section 1295 of the Code with respect of the Company or any Subsidiary PFIC.  U.S. Holders are urged to consult their own tax advisers regarding the potential application of the PFIC rules to the ownership and disposition of common shares, and the availability of certain U.S. tax elections under the PFIC rules.
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  F.
Dividends and Paying Agents
 
 Not Applicable.
 
 G.
Statements by Experts
 
 Not Applicable.
 
 H.
Documents on Display
 
 We are subject to the informational requirements of the Exchange Act and file reports and other information with the SEC. You may read and copy any of our reports and other information at, and obtain copies upon payment of prescribed fees from, the Public Reference Room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. In addition, the SEC maintains a Website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.
 
 We are required to file reports and other information with the securities commissions in Canada. You are invited to read and copy any reports, statements or other information, other than confidential filings, that we file with the provincial securities commissions. These filings are also electronically available from the Canadian System for Electronic Document Analysis and Retrieval (“SEDAR”) (http://www.sedar.com), the Canadian equivalent of the SEC’s electronic document gathering and retrieval system.
 
 We “incorporate by reference” information that we file with the SEC, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is an important part of this Form 20-F and more recent information automatically updates and supersedes more dated information contained or incorporated by reference in this Form 20-F.
 
 As a foreign private issuer, we are exempt from the rules under the Exchange Act prescribing the furnishing and content of proxy statements to shareholders.
 
 We will provide without charge to each person, including any beneficial owner, to whom a copy of this annual report has been delivered, on the written or oral request of such person, a copy of any or all documents referred to above which have been or may be incorporated by reference in this annual report (not including exhibits to such incorporated information that are not specifically incorporated by reference into such information). Requests for such copies should be directed to us at the following address: 598 – 999 Canada Place, Vancouver, British Columbia, Canada V6C 3E1, Telephone: (604) 638-5050, Facsimile: (604) 638-5051.
 
 I.
Subsidiary Information
 
 Not applicable.
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  ITEM 11.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
 The Company is engaged primarily in mineral and oil and gas exploration and production and manages related industry risk issues directly.  The Company may be at risk for environmental issues and fluctuations in commodity pricing.  Management is not aware of and does not anticipate any significant environmental remediation costs or liabilities in respect of its current operations.
 
 The Company’s functional currency is the Canadian dollar. The Company operates in foreign jurisdictions, giving rise to significant exposure to market risks from changes in foreign currency rates.  The financial risk is the risk to the Company’s operations that arises from fluctuations in foreign exchange rates and the degree of volatility of these rates.  Currently, the Company does not use derivative instruments to reduce its exposure to foreign currency risk.
 
 The Company also has exposure to a number of risks from its use of financial instruments including: credit risk, liquidity risk, and market risk.  This note presents information about the Company’s exposure to each of these risks and the Company’s objectives, policies and processes for measuring and managing risk, and the Company’s management of capital.
 
 The Board of Directors has overall responsibility for the establishment and oversight of the Company’s risk management framework.  The Board has implemented and monitors compliance with risk management policies.  The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities.
 
 Credit Risk
 
 Credit risk arises from credit exposure to joint venture partners and marketers included in accounts receivable. The maximum exposure to credit risk is equal to the carrying value of the financial assets. The Company is exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company’s business, financial condition, and results of operations. The objective of managing the third party credit risk is to minimize losses in financial assets. The Company assesses the credit quality of the partners, taking into account their financial position, past experience, and other factors. The Company mitigates the risk of collection by obtaining the partners’ share of capital expenditures in advance of a project and by monitoring accounts receivable on a regular basis. As at December 31, 2010 and 2009, no accounts receivable has been deemed uncollectible or written off during the year.
 
 Liquidity Risk
 
 Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company’s approach to managing liquidity is to ensure, as far as possible, that it will have sufficient liquidity to  meet its liabilities when due, under both normal and stressed conditions without incurring unacceptable losses or risking harm to the Company’s reputation.
 
 As the industry in which the Company operates is very capital intensive, the majority of the Company’s spending is related to its capital programs. The Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. Further, the Company utilizes authorizations for expenditures on both operated and nonoperated projects to further manage capital expenditures. To facilitate the capital expenditure program, the Company has a bridge loan credit facility. The Company also attempts to match its payment cycle with collection of oil and natural gas revenues on the 25th of each month. Accounts payable are considered due to suppliers in one year or less while the bank line of credit was repaid in full during the year ended December 31, 2010. The bridge loan, which is in discussion with the lender for further extension, is due in April 2011.
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  Market Risk
 
 Market risk is the risk that changes in market prices, such as foreign exchange rates, commodity prices, and interest rates will affect the Company’s net earnings or the value of financial instruments. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns. The Company utilizes financial derivatives to manage certain market risks. All such transactions are conducted in accordance with the risk management policy that has been approved by the Board of Directors.
 
 Foreign Currency Exchange Risk
 
 See “Item 5. Operating and Financial Review and Prospects – A. Operating Results – Foreign Currency Risks” for  disclosure on the Company’s foreign currency exchange risk.
 
 Interest Rate Risk
 
 Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. During the year ended December 31, 2010, interest rate fluctuations on the Company’s credit facility have no significant impact on its net loss because the floating rate debt was repaid in full in early 2010 and the Company had no floating rate debt at December 31, 2010. In the prior year, the Company was exposed to interest rate fluctuations on its credit facility which bore a floating rate of interest. The Company had no interest rate swaps or financial contracts in place at or during the year ended December 31, 2010 and 2009.
 
 Commodity Price Risk
 
 Commodity price risk is the risk that the fair value of financial instruments or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted by world economic events that dictate the levels of supply and demand. The Company has attempted to mitigate commodity price risk through the use of financial derivative sales contracts. The Company had no risk management contracts in place at December 31, 2010. As at December 31, 2009, the Company had a natural gas derivatives contract for 600 gigajoules (“GJ”) per day for the period from November 1, 2009 to April 30, 2010. This contract consisted of a CAD$4.47 per GJ forward sale agreement. As at December 31, 2009, the Company also had a crude oil derivatives contract for 100 barrels (“bbl”) per day for the period from September 1, 2009 to April 30, 2010. This contract consisted of a CAD$81.60 per bbl forward sale agreement. For the year ended December 31, 2010, the Company recognized in income a realized gain of $67,923 on the risk management contracts in place during the year (2009 - $315,270).
 
 Capital Management Strategy
 
 The Company’s policy on capital management is to maintain a prudent capital structure so as to maintain financial flexibility, preserve access to capital markets, maintain investor, creditor and market confidence, and to allow the Company to fund future development. The Company considers its capital structure to include share capital, cash and cash equivalents, bridge loan, loans from related parties, and working capital. In order to maintain or adjust capital structure, the Company may from time to time issue shares or enter into debt agreements and adjust its capital spending to manage current and projected operating cash flows and debt levels.
 
 The Company’s current borrowing capacity is based on the lender’s review of the Company’s oil and gas reserves. The Company is also subject to various covenants. Compliance with these covenants is monitored on a regular basis and at December 31, 2010, the Company is in compliance with all covenants.
 
 The Company’s share capital is not subject to any external restrictions. The Company has not paid or declared any dividends, nor are any contemplated in the foreseeable future. There have been no changes to the Company’s capital management strategy during the year ended December 31, 2010.
  88
  ITEM 12.  DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
 
 A.-C.
 
 Not applicable.
 
 D.   American Depositary Receipts
 
 The Company does not have securities registered as American Depositary Receipts.
  89
  PART II
 
 ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
 
 None.
 
 ITEM 14.  MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS
 
 A. – D.
 
 None.
 
 E.
Use of Proceeds
 
 Not Applicable.
 
 ITEM 15.   CONTROLS AND PROCEDURES
 
 A.
Disclosure Controls and Procedures
 
 An evaluation was performed under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and the Company’s Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15(b) and 15d-15(b) of the Securities Exchange Act of 1934 (the “Exchange Act”) as of December 31, 2010.  Based on their evaluation, the Company’s CEO and CFO have concluded that the disclosure controls and procedures were not effective, as described below under Internal Control over Financial Reporting, to give reasonable assurance that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
 
 B.
Management’s Report on Internal Control over Financial Reporting
 
 The Company’s management, including the Company’s Chief Executive Officer and the Company’s Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over the Company’s internal control over financial reporting, as such term is defined in Rule 13a-15(f) under the Exchange Act. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation and fair presentation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
 The Company’s management, (with the participation of the Company’s Chief Executive Officer and the Company’s Chief Financial Officer), conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2010.  This evaluation was based on the criteria set forth in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  Based on its assessment, management has concluded that, as of December 31, 2010, the Company’s internal control over financial reporting was not effective and management’s assessment did identify material weaknesses.
 
 The Company’s management had identified that such controls did not operate effectively during the period with the result that misstatements of certain non-cash items were not prevented or detected in the interim financial statements for the six months ended June 30, 2010 and in the Note 21 to the consolidated financial statements for the year ended December 31, 2009 regarding reconciliation between Canadian and US GAAP. Specifically, period end review of the financial statements by management did not identify the misstatement of certain non-cash items.  Such financial statements and US GAAP reconciliation were subsequently restated and refilled.  These restatements have no impact on the cashflow or cash position of the Company.
  90
  C.
Attestation Report of the Registered Public Accounting Firm
 
 This Annual Report does not include an attestation report of the Company’s independent auditors regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s independent auditors pursuant to Section 404(c) of the Sarbanes-Oxley Act of 2002, as amended, which permits companies that are not “accelerated filers” or “large accelerated filers” to provide only management’s report in this Annual Report.
 
 D.
Changes in Internal Control over Financial Reporting
 
 During the fiscal year ended December 31, 2010, there were changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
 
 To remedy the above described material weakness, during the second half of the fiscal year ended December 31, 2010, the Company improved staff training and period end review process.  If necessary, the Company will engage external consultants to review complex accounting and financial reporting matters. With the change in operation of these controls, the Company believes that this type of situation will not occur again.
 
 ITEM 16.  [RESERVED]
 
 ITEM 16A.  AUDIT COMMITTEE FINANCIAL EXPERT
 
 The Board of Directors has determined that the Company has at least one audit committee financial expert, Mr. Craig Sturrock, who is an independent director under Rule 803A of the NYSE Amex and Rule 10A-3 of the United States Exchange Act of 1934, as amended, and serves on the Company’s audit committee.
 
 ITEM 16B.  CODE OF ETHICS
 
 The Board of Directors of the Company has adopted a Code of Conduct and Ethics that outlines the Company’s values and its commitment to ethical business practices in every business transaction. This code applies to all directors, officers, and employees of the Company and its subsidiaries and affiliates.  A copy of the Company’s Code of Business Conduct and Ethics is available on the Company’s website at www.dejour.com.
 
 Reporting Unethical and Illegal Conduct/Ethics Questions
 
 The Company is committed to taking prompt action against violations of the Code of Conduct and Ethics and it is the responsibility of all directors, officers and employees to comply with the Code and to report violations or suspected violations to the Company’s Compliance Officer.  Employees may also discuss their concerns with their supervisor who will then report suspected violations to the Compliance Officer.
 
 The Compliance Officer is appointed by the Board of Directors and is responsible for investigating and resolving all reported complaints and allegations and shall advise the President and CEO, the CFO and/or the Audit Committee.
 
 During the fiscal year ended December 31, 2010, the Company did not substantially amend, waive, or implicitly waive any provision of the Code with respect to any of the directors, executive officers or employees subject to it.
  91
  ITEM 16C.  PRINCIPAL ACCOUNTANT FEES AND SERVICES
  The following table sets out the fees billed to us by BDO Canada LLP and Dale Matheson Carr-Hilton Labonte LLP for professional services for the years ended December 31, 2010 and December 31, 2009. During these years, BDO Canada LLP and Dale Matheson Carr-Hilton Labonte LLP were our external auditors.
  Year ended

December 31, 2010


Year ended

December 31, 2009Audit Services

$
180,350


$
97,000Audit of the Corporation's annual consolidated financial statementsAudit Related Services

$
38,764


$
20,000Tax Services

Nil


NilTax compliance and consulting estimated fees
 
 Pre-Approval Policies and Procedures
 
 Generally, in the past, prior to engaging the Company’s auditors to perform a particular service, the Company’s audit committee has, when possible, obtained an estimate for the services to be performed.  The audit committee in accordance with procedures for the Company approved all of the services described above.
 
 In relation to the pre-approval of all audit and audit-related services and fees the Company’s audit committee charter provides that the audit committee shall:
 
 Review and pre-approve all audit and audit-related services and the fees and other compensation related thereto, and any non-audit services, provided by the Company’s external auditors.  The pre-approval requirement is waived with respect to the provision of non-audit services if:
 
 i.
the aggregate amount of all such non-audit services provided to the Company constitutes not more than five percent of the total amount of revenues paid by the Company to its external auditors during the fiscal year in which the non-audit services are provided;
 ii.
such services were not recognized by the Company at the time of the engagement to be non-audit services; and
 iii.
such services are promptly brought to the attention of the Committee by the Company and approved prior to the completion of the audit by the Committee or by one or more members of the Committee who are members of the Board to whom authority to grant such approvals has been delegated by the Committee.
 
 Provided the pre-approval of the non-audit services is presented to the Committee’s first scheduled meeting following such approval such authority may be delegated by the Committee to one or more independent members of the Committee.
 
 ITEM 16D.   EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES
 
 None.
 
 ITEM 16E.   PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS
 
 The Company did not repurchase any common shares in the fiscal year ended December 31, 2010.
 
 ITEM 16F.   CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT
  Effective on August 20, 2010, we terminated the services of our principal registered independent public accountant, Dale Matheson Carr-Hilton Labonte LLP (“DMCL”).
  92
  In DMCL’s principal accountant reports on our financial statements for each of the past two fiscal years ended December 31, 2009 and 2008, no adverse opinion was issued and no opinion of DMCL was modified as to audit scope or accounting principles. No audit reports of DMCL in each of the past two fiscal years contained any adverse opinion or a disclaimer of opinion, or was qualified or modified as to uncertainty, audit scope, or accounting principles.
  The change in auditor was recommended and approved by our audit committee.
 
 In the two most recent fiscal years and any interim period preceding the dismissal of DMCL, we are not aware of any disagreements with DMCL on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreement(s), if not resolved to the satisfaction of DMCL, would have caused it to make references to the subject matter of the disagreement(s) in connection with its report.
  We are not aware of any reportable events (as set forth in Item 16F(a)(1)(v) of Form 20-F) that have occurred during the two most recent fiscal years and the interim period preceding the dismissal of DMCL.
  On August 20, 2010, we engaged BDO Canada LLP (“BDO”) as its new principal registered independent accountant effective on August 20, 2010, to audit our financial records. BDO is registered with the Public Company Accounting Oversight Board. During the two most recent fiscal years and the interim period preceding the appointment of BDO, we did not consult BDO regarding the application of accounting principles to a specified transaction, either completed or proposed; or the type of audit opinion that might be rendered on our financial statements, and neither a written report nor oral advice was provided to us that it considered an important factor in reaching a decision as to any accounting, auditing or financial reporting issue; or any matter that was either the subject of a disagreement (as defined in Item 16F(a)(1)(iv) of Form 20-F) or a reportable event (as described in Item 16F(a)(1)(v) of Form 20-F).
  ITEM 16G.   CORPORATE GOVERNANCE
  The Company’s common shares are listed on the NYSE Amex. Section 110 of the NYSE Amex Company Guide permits the NYSE Amex to consider the laws, customs and practices of foreign issuers in relaxing certain NYSE Amex listing criteria, and to grant exemptions from NYSE Amex listing criteria based on these considerations. A company seeking relief under these provisions is required to provide written certification from independent local counsel that the non-complying practice is not prohibited by home country law. A description of the significant ways in which the Company’s governance practices differ from those followed by domestic companies pursuant to NYSE Amex standards is as follows:
  Shareholder Meeting Quorum Requirement: The NYSE Amex minimum quorum requirement for a shareholder meeting is one-third of the outstanding shares of common stock. In addition, a company listed on NYSE Amex is required to state its quorum requirement in its bylaws. The Company’s quorum requirement is set forth in its Articles and bylaws. A quorum for a meeting of members of the Company is one holder of common shares issued, outstanding and entitled to vote, represented in person or by proxy.
  Proxy Delivery Requirement: NYSE Amex requires the solicitation of proxies and delivery of proxy statements for all shareholder meetings, and requires that these proxies shall be solicited pursuant to a proxy statement that conforms to SEC proxy rules. The Company is a “foreign private issuer” as defined in Rule 3b-4 under the Exchange Act, and the equity securities of the Company are accordingly exempt from the proxy rules set forth in Sections 14(a), 14(b), 14(c) and 14(f) of the Exchange Act. The Company solicits proxies in accordance with applicable rules and regulations in Canada.
  Shareholder Approval Requirement:The Company will follow Toronto Stock Exchange rules for shareholder approval of new issuances of its common shares. Following Toronto Stock Exchange rules, shareholder approval is required for certain issuances of shares that: (i) materially affect control of the Company; or (ii) provide consideration to insiders in aggregate of 10% or greater of the market capitalization of the listed issuer and have not been negotiated at arm’s length. Shareholder approval is also required, pursuant to TSX rules, in the case of private placements: (x) for an aggregate number of listed securities issuable greater than 25% of the number of securities of the listed issuer which are outstanding, on a non-diluted basis, prior to the date of closing of the transaction if the price per security is less than the market price; or (y) that during any six month period are to insiders for listed securities or options, rights or other entitlements to listed securities greater than 10% of the number of securities of the listed issuer which are outstanding, on a non-diluted basis, prior to the date of the closing of the first private placement to an insider during the six month period.
  93
  The foregoing is consistent with the laws, customs and practices in Canada.
  In addition, the Company may from time-to-time seek relief from NYSE Amex corporate governance requirements on specific transactions under Section 110 of the NYSE Amex Company Guide by providing written certification from independent local counsel that the non-complying practice is not prohibited by our home country law, in which case, the Company shall make the disclosure of such transactions available on the Company’s website at www.dejour.com. Information contained on its website is not part of this annual report.
  PART III
 
 ITEM 17.  FINANCIAL STATEMENTS
 
 The Company has elected to provide financial statements pursuant to Item 18.
 
 ITEM 18.  FINANCIAL STATEMENTS
 
 The Company’s financial statements are stated in Canadian Dollars and are prepared in accordance with Canadian Generally Accepted Accounting Principles (GAAP), the application of which, in our case, conforms in all material respects for the periods presented with United States GAAP, except as discussed in Reconciliation Between Canadian and United States Generally Accepted Accounting Principles for the year ended December 31, 2010.
 
 Report of Independent Registered Chartered Accountants, dated March 29, 2011, except for Note 21 which is as of June 29, 2011
 
 Independent Auditors’ Report dated March 26, 2010
 
 Consolidated Balance Sheets at December 31, 2010 and 2009
 
 Consolidated Statements of Operations and Deficit for the years ended December 31, 2010, 2009 and 2008
 
 Consolidated Statements of Comprehensive Loss and Accumulated Other Comprehensive Income (Loss) for the years ended December 31, 2010, 2009 and 2008
 
 Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008
 
 Notes to the Consolidated Financial Statements for the years ended December 31, 2010, 2009 and 2008
  94
  ITEM 19.  EXHIBITS
 
 Financial Statements
 
 Description

PageConsolidated Financial Statements for the Years Ended December 31, 2010, 2009 and 2008.

F-1 - F-43
 
 EXHIBIT

NUMBER

DESCRIPTION1.1

Certificate of Incorporation (1)1.2

Certificate of Name Change (1)1.3

Articles of Incorporation (1)1.4

Revised Articles of Incorporation(2)1.5

Articles of Amalgamation(1)1.6

Bylaws Number A (1)1.7

Certificate of Name Change4.1

Property Purchase Agreement between the Registrant and Titan Uranium Inc. dated December 13, 2006(3)4.2

Participation Agreement between the Registrant, Retamco Operating, Inc. and Brownstone Ventures (US) dated July 14, 2006(3)4.3

Purchase and Sale Agreement between the Registrant, Retamco Operating, Inc., and Brownstone Ventures (US) Inc. dated June 17, 2008 (4)4.4

Loan Agreement between DEAL and HEC dated May 15, 2008 (5)4.5

Loan Agreement between the Company and HEC dated August 11, 2008 (5)4.6

Loan Agreement between the Company and HEC dated June 22, 2009 (5)4.7

Loan Agreement between the Company and Brownstone Ventures (US) Inc. dated June 22, 2009 (5)4.8

Purchase and Sale Agreement between the Registrant and Pengrowth Corporation dated April 17, 2009 (5)4.9

Purchase and Sale Agreement between the Registrant and John James Robinson dated June 10, 2009 (5)4.10

Purchase and Sale Agreement between the Registrant and C.U. YourOilRig Corp. dated June 15, 2009 (5)4.11

Purchase and Sale Agreement between the Registrant and Woodrush Energy Partners LLC dated July 8, 2009 (5)4.12

Purchase and Sale Agreement between the Registrant and RockBridge Energy Inc. dated July 31, 2009 (5)4.13

Purchase and Sale Agreement between the Registrant and HEC dated December 31, 2009 (5)4.14

Loan Agreement between the Registrant and Toscana Capital Corporation dated February 19, 20104.15

Amended Loan Agreement between the Registrant and Toscana Capital Corporation dated September 1, 20108.1

List of Subsidiaries12.1

Certification of CEO Pursuant to Rule 13a-14(a)
  95
  EXHIBIT

NUMBER

DESCRIPTION12.2

Certification of CFO Pursuant to Rule 13a-14(a)13.1

Certification of CEO Pursuant to 18 U.S.C. Section 135013.2

Certification of CFO Pursuant to 18 U.S.C. Section 135015.1

Third Party Report on Reserves, dated June 29, 201115.2

Letter from Gustavson Associates regarding Reserve Estimate and Financial Forecast as to Dejour’s Interests in the Gibson Gulch Area, dated March 1, 201115.3

Consent of BDO Canada  LLP15.4

Consent Letters from Dale Matheson Carr-Hilton Labonte LLP15.5

Consent Letter from GLJ Petroleum Consultants15.6

Consent Letter from Gustavson Associates15.7

Supplementary Oil and Gas Reserve Estimation and Disclosures
  (1)
Incorporated by reference to the Registrant’s registration statement on Form 20-F, filed with the commission on May 24, 2005.
 (2)
Incorporated by reference to the Registrant’s annual report on Form 20-F, filed July 14, 2006.
 (3)
Incorporated by reference to the Registrant’s annual report on Form 20-F/A amendment no. 2, filed December 7, 2007.
 (4)
Incorporated by reference to the Registrant’s annual report on Form 20-F, filed on June 30, 2009.
 (5)
Incorporated by reference to the Registrant’s annual report on Form 20-F, filed on June 30, 2010.
  96
  SIGNATURES
 
 The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.
 
 DEJOUR Energy Inc.Dated:
June 30,  2011

/s/ Robert L. HodgkinsonRobert L. HodgkinsonChairman & CEO




97




(formerly operating as Dejour Enterprises Ltd.)
  
 CONSOLIDATED FINANCIAL STATEMENTS
 
 December 31, 2010
 
 
 REPORT OF INDEPENDENT REGISTERED CHARTERED ACCOUNTANTS dated March 29, 2011, except for Note 21 which is as of June 29, 2011

F-2INDEPENDENT AUDITORS’ REPORT dated March 26, 2010

F-4CONSOLIDATED BALANCE SHEETS

F-6CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT

F-7CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS AND ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

F-8CONSOLIDATED STATEMENTS OF CASH FLOWS

F-9NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

F-10
  F-1
  
  F-2
  F-3
  F-4
  F-5
  DEJOUR ENERGY INC.
 CONSOLIDATED BALANCE SHEETS
 (Expressed in Canadian Dollars)
 
 
 December 31,


December 31,2010


2009ASSETSCurrentCash and cash equivalents

$
4,757,525


$
2,732,696Accounts receivable


688,626



724,773Prepaids and deposits


92,738



126,2665,538,889



3,583,735Deposits


442,261



429,406Equipment(Note 4)


102,765



114,747Uranium properties(Note 6(a))


523,205



533,085Oil and gas properties(Note 6(b))


39,748,046



41,224,903$
46,355,166


$
45,885,876LIABILITIESCurrentBank line of credit and bridge loan (Note 7)

$
4,800,000


$
850,000Accounts payable and accrued liabilities


2,472,746



2,653,483Unrealized financial instrument loss


-



99,894Loans from related parties (Note 8)


250,000



-7,522,746



3,603,377Loans from related parties(Note 8)


-



2,345,401Deferred leasehold inducement


31,707



39,913Asset retirement obligations(Note 9)


541,218



208,5168,095,672



6,197,207SHAREHOLDERS' EQUITYShare capital (Note 10)


75,575,012



72,559,504Contributed surplus (Note 12)


7,235,106



6,614,805Deficit


(44,550,624
)


(39,385,746
)Accumulated other comprehensive loss


-



(99,894
)38,259,494



39,688,669$
46,355,166


$
45,885,876
  Basis of presentation and going concern(Note 1)Commitments(Notes 7, 8, 9 and 16)Subsequent Events(Note 20)Approved on behalf of the Board:  “Robert Hodgkinson”

“Craig Sturrock”Robert Hodgkinson – Director

Craig Sturrock – Director
   The accompanying notes are an integral part of these consolidated financial statements
  F-6
  DEJOUR ENERGY INC.
 CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT
 (Expressed in Canadian Dollars)
 
 
 Year Ended


Year Ended


Year EndedDecember 31


December 31


December 312010


2009


2008REVENUESOil and natural gas revenue

$
8,085,627


$
6,470,725


$
5,765,555Realized financial instrument gain


67,922



315,270



-8,153,549



6,785,995



5,765,555EXPENSESRoyalties


1,311,767



569,476



1,148,655Operating and transportation


2,604,666



2,915,002



1,973,300General and administrative


3,423,906



4,038,332



4,214,783Interest expense and finance fee


1,074,923



818,494



481,252Stock based compensation (Note 11)


620,301



697,467



2,719,957Foreign exchange loss (gain)


27,692



(257,319
)


675,599Impairment of oil and gas properties (Note 6(b))


-



5,359,783



2,029,942Amortization, depletion and accretion (Notes 4, 6, and 9)


5,249,894



6,436,553



3,690,93914,313,149



20,577,788



16,934,427LOSS BEFORE THE FOLLOWING AND INCOME TAXES


(6,159,600
)


(13,791,793
)


(11,168,872
)Interest and other income


36,602



417,024



236,838Loss on disposition of investment in Titan (Note 5)


-



(274,187
)


(8,846
)Equity (loss) income from Titan (Note 5)


-



(142,196
)


3,636,710Impairment of investment in Titan (Note 5)


-



-



(12,990,343
)Impairment of uranium properties (Note 6(a))


(9,880
)


(148,906
)


-LOSS BEFORE INCOME TAXES


(6,132,878
)


(13,940,058
)


(20,294,513
)FUTURE INCOME TAX RECOVERY (EXPENSE)(Note 15)


968,000



1,133,140



(596,240
)NET LOSS FOR THE YEAR


(5,164,878
)


(12,806,918
)


(20,890,753
)DEFICIT, BEGINNING OF THE YEAR


(39,385,746
)


(26,578,828
)


(5,688,075
)DEFICIT, END OF THE YEAR

$
(44,550,624
)

$
(39,385,746
)

$
(26,578,828
)NET LOSS PER SHARE - BASIC AND DILUTED

$
(0.05
)

$
(0.16
)

$
(0.29
)WEIGHTED AVERAGE NUMBER OFCOMMON SHARES OUTSTANDING - BASIC AND DILUTED


99,788,625



78,926,223



72,210,852
   The accompanying notes are an integral part of these consolidated financial statements
  F-7
  Dejour Enterprises Ltd.
 Consolidated Statements of Comprehensive Loss and Accumulated Other Comprehensive Income (Loss)
 Expressed in Canadian Dollars
  
 Year Ended


Year Ended


Year EndedDecember 31


December 31,


December 31,2010


2009


2008NET LOSS FOR THE YEAR

$
(5,164,878
)

$
(12,806,918
)

$
(20,890,753
)Unrealized financial instrument loss


-



(99,894
)


107,768COMPREHENSIVE LOSS FOR THE YEAR

$
(5,164,878
)

$
(12,906,812
)

$
(20,782,985
)ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS),BEGINNING OF THE YEAR

$
(99,894
)

$
107,768


$
(5,400
)Unrealized loss arising during the year


-



(99,894
)


107,768Realized loss (gain) during the year


99,894



(107,768
)


5,400ACCUMULATED OTHER COMPREHENSIVE LOSS,END OF THE YEAR

$
-


$
(99,894
)

$
107,768
 
 The accompanying notes are an integral part of these consolidated financial statements
  F-8
  DEJOUR ENERGY INC.
 CONSOLIDATED STATEMENTS OF CASH FLOWS
 (Expressed in Canadian Dollars)
 Year Ended


Year Ended


Year EndedDecember 31


December 31


December 312010


2009


2008CASH FLOWS FROM (USED IN) OPERATING ACTIVITIESNet loss for the year

$
(5,164,878
)

$
(12,806,918
)

$
(20,890,753
)Adjustment for items not affecting cash:Amortization, depletion and accretion


5,249,894



6,436,553



3,690,939Equity loss from Titan


-



142,196



(3,636,710
)Stock based compensation


620,301



697,467



2,719,957Non-cash finance fees


112,666



56,334



-Capitalized interests on convertible debentures


-



-



143,758Foreign exchange (gain) / loss


-



(333,900
)


749,575Impairment of investment in Titan


-



-



12,990,343Impairment of uranium properties


9,880



148,906



-Impairment of oil and gas properties


-



5,359,783



2,029,942Future income tax (recovery) / expenses


(968,000
)


(1,133,140
)


596,240Loss on disposal of investment in Titan


-



274,187



8,846Non-cash general and administrative expenses


10,609



-



-Deferred leasehold inducement


-



43,332



-Amortization of deferred leasehold inducement


(8,206
)


(3,419
)


-Changes in non-cash operating working capital (Note 13)


533,411



(47,977
)


449,233395,678



(1,166,596
)


(1,148,630
)CASH FLOWS FROM (USED IN) INVESTING ACTIVITIESDeposits


(12,855
)


(158,151
)


735,663Purchase of equipment


(26,945
)


(39,279
)


(67,049
)Proceeds from sales of marketable securities


-



-



27,403Proceeds on disposal of investment in Titan (Note 5)


-



2,305,491



529,894Proceeds from sales of oil and gas properties


1,603,971



5,542,497



-Resource properties expenditures


(5,015,989
)


(2,587,209
)


(27,591,251
)Changes in non-cash investing working capital (Note 13)


(402,811
)


(1,187,318
)


119,540(3,854,629
)


3,876,031



(26,245,800
)CASH FLOWS FROM (USED IN) FINANCING ACTIVITIESLine of credit (repayment)


(850,000
)


(5,037,450
)


5,887,450Advance of bridge loan


4,800,000



-



-Loans from related parties (repayment)


(2,208,067
)


(800,350
)


6,404,465Shares issued for cash


3,983,508



4,823,105



2,335,085Changes in non-cash financing working capital (Note 13)


(241,661
)


293,731



-5,483,780



(720,964
)


14,627,000INCREASE (DECREASE) IN CASH AND  CASH EQUIVALENTS


2,024,829



1,988,471



(12,767,430
)CASH AND CASH EQUIVALENTS, BEGINNING OF THE YEAR


2,732,696



744,225



13,511,655CASH AND CASH EQUIVALENTS, END OF THE YEAR

$
4,757,525


$
2,732,696


$
744,225
     The accompanying notes are an integral part of these consolidated financial statements
  F-9
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 
  NOTE 1 – NATURE OF OPERATIONS AND GOING CONCERN
 
 Dejour Energy Inc. (the “Company”) is a public company trading on the New York Stock Exchange AMEX (“NYSE-AMEX”) and the Toronto Stock Exchange (“TSX”), under the symbol “DEJ.”  The Company is in the business of exploring and developing energy projects with a focus on oil and gas in North America. On March 9, 2011, the Company changed its name from Dejour Enterprises Ltd. to Dejour Energy Inc.
 
 All dollar amounts are stated in Canadian dollars, the Company’s reporting currency, unless otherwise indicated.Certain of the comparative figures have been reclassified to conform to the current year’s presentation, if necessary.
 
 The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Dejour Energy (USA) Corp. (“Dejour USA”), incorporated in Nevada, Dejour Energy (Alberta) Ltd. (“DEAL”), Wild Horse Energy Ltd. (“Wild Horse”), incorporated in Alberta, and 0855524 B.C. Ltd., incorporated in B.C.  All intercompany transactions are eliminated upon consolidation.
  These consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the payment of liabilities in the ordinary course of business.  Should the Company be unable to continue as a going concern, it may be unable to realize the carrying value of its assets and to meet its liabilities as they become due. At December 31, 2010, the Company has an accumulated deficit of $44,550,624 and a working capital deficiency of $1,983,857 and incurred a loss for the year of $5,164,878.  The Company’s $4,800,000 bridge loan facility is due April 30, 2011 (Note 7). As described in Note 20 subsequent to year end, the Company raised US$3,303,000 gross proceeds by way of a private placement which was used for resource property expenditures and to supplement working capital, repaid its loan from a related party and entered into a joint venture agreement that upon satisfactory achievement of certain objectives commits the Company to certain capital expenditures. The Company's ability to continue as a going concern is dependent upon attaining profitable operations and obtaining sufficient debt and equity financing to meet obligations and continue exploration and development activities.  There is no assurance that these activities will be successful.  These consolidated financial statements do not reflect the adjustments to the carrying values of assets and liabilities, the reported expenses, and the balance sheet classifications used, that would be necessary if the going concern assumption were not appropriate and such adjustments may be significant.
  NOTE 2 – RECENTLY ADOPTED ACCOUNTING POLICIES AND FUTURE ACCOUNTING PRONOUNCEMENTS
 
 (a)
Recently Adopted Accounting Policies
 
 On January 1, 2010, the Company adopted the following Canadian Institute of Chartered Accountants (“CICA”) Handbook sections:
 
 ·
Business Combinations, Section 1582, which replaces the previous business combinations standard. The standard requires assets and liabilities acquired in a business combination, contingent consideration and certain acquired contingencies to be measured at their fair values as of the date of acquisition. In addition, acquisition-related and restructuring costs are to be recognized separately from the business combination and included in the statement of operations. The adoption of this standard had no impact but will impact the accounting treatment of future business combinations entered into after January 1, 2010.
 
 ·
Consolidated Financial Statements, Section 1601, which, together with Section 1602 below, replace the former consolidated financial statements standard. Section 1601 establishes the requirements for the preparation of consolidated financial statements. The adoption of this standard had no impact on the Company’s consolidated financial statements.
 
 ·
Non-controlling Interests, Section 1602, which establishes the accounting for a non-controlling interest in a subsidiary in consolidated financial statements subsequent to a business combination. The standard requires a non-controlling interest in a subsidiary to be classified as a separate component of equity. In addition, net earnings and components of other comprehensive income are attributed to both the parent and non-controlling interest. The adoption of this standard has had no impact on the Company’s consolidated financial statements.
  F-10
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 
 NOTE 2 – RECENTLY ADOPTED ACCOUNTING POLICIES AND FUTURE ACCOUNTING PRONOUNCEMENTS (continued)
 
 (b)
Future Accounting Pronouncements
 
 The following accounting pronouncements are applicable to future reporting periods.  The Company is currently evaluating the effects of adopting these standards:
 
 In February 2008 the CICA’s Accounting Standards Board announced that Canadian publicly accountable enterprises will be required to adopt International Financial Reporting Standards (IFRS) effective January 1, 2011.  As a result, the Company will publish its first consolidated financial statements, prepared in accordance with IFRS, for the quarter ending March 31, 2011. The Company will also provide comparative data on an IFRS basis, including an opening balance sheet as at January 1, 2010.
  NOTE 3 – SUMMARY OF OTHER SIGNIFICANT ACCOUNTING POLICIES
 
 (a)
Cash and Cash Equivalents
 
 Cash and cash equivalents consist of cash and highly liquid investments having maturity dates of three months or less from the date of acquisition that are readily convertible to cash.
 
 (b)
Resource Properties
 
 Mineral properties
 
 The Company records its interests in mineral properties at cost less any impairment.  Where specific exploration programs are planned and budgeted by management, the cost of mineral properties and related exploration expenditures are capitalized until the properties are placed into commercial production, sold, abandoned or determined by management to be impaired in value.  These costs will be amortized over the estimated useful lives of the properties following the commencement of production or written off if the properties are sold or abandoned.
 
 The costs include the cash or other consideration and the assigned value of shares issued, if any, on the acquisition of mineral properties.  Costs related to properties acquired under option agreements or joint ventures, whereby payments are made at the sole discretion of the Company, are recorded in the accounts at such time as the payments are made.  For properties held jointly with other parties the Company only records its proportionate share of acquisition and exploration costs.  The proceeds from options granted are deducted from the cost of the related property and any excess is deducted from other remaining capitalized property costs.  The Company does not accrue estimated future costs of maintaining its mineral properties in good standing. To date the Company has not recorded any asset retirement obligations for its mineral properties as it has only performed preliminary exploratory work and has not incurred significant reclamation obligations.
 
 Capitalized costs as reported on the balance sheet represent costs incurred to date and may not reflect recoverable value.  Recovery of carrying value is dependent upon future commercial success or proceeds from disposition of the mineral interests.
 
 Management evaluates each mineral interest on a reporting period basis or as events and changes in circumstances warrant, and makes a determination based on exploration activity and results, estimated future cash flows and availability of funding as to whether costs are capitalized or charged to operations. Mineral property interests, where future cash flows are not reasonably determinable, are evaluated for impairment based on management’s intentions and determination of the extent to which future exploration programs are warranted and likely to be funded.
 
 General exploration costs not related to specific properties and general administrative expenses are charged to operations in the year in which they are incurred.
 
 The Company does not have any producing mineral properties and all of its efforts to date have been exploratory in nature.
  F-11
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
  NOTE 3 – SUMMARY OF OTHER SIGNIFICANT ACCOUNTING POLICIES (continued)
 
 Oil and gas properties
 
 The Company follows the full cost method of accounting for its oil and gas operations whereby all costs related to the acquisition of, exploration for and development of petroleum and natural gas interests are capitalized by country in a cost centre.  Such costs include land and lease acquisition costs, annual carrying charges of non-producing properties, geological and geophysical costs, interest costs, costs of drilling and equipping productive and non-productive wells, and direct exploration consulting fees. Proceeds from the disposal of oil and gas interests are recorded as a reduction of the related expenditures without recognition of a gain or loss unless the disposal would result in a change of 20 percent or more in the depletion rate.
 
 Depletion and depreciation of the capitalized costs are computed using the unit-of-production method based on the estimated proven reserves of oil and gas determined by independent consultants.  Costs of significant unproved properties, net of impairment, and estimated salvage values are excluded from the depletion and depreciation calculation.
 
 Estimated future removal and site restoration costs are provided over the life of proven reserves on a unit-of-production basis. Costs, which include the cost of production, equipment removal and environmental clean-up, are estimated each period by management based on current regulations, costs, technologies and industry standards.
 
 The Company places a limit on the aggregate carrying value of its oil and gas properties, which may be amortized against revenues of future periods.
 
 Impairment is recognized if the carrying amount of the oil and gas properties exceeds the sum of the undiscounted cash flows expected to result from the Company’s proved reserves.  Cash flows are calculated based on third party quoted forward prices, adjusted for the Company’s contract prices and quality differentials.  Upon recognition of impairment, the Company measures the amount of impairment by comparing the carrying amount of oil and gas properties to the estimated net present value of future cash flows from proved plus risked probable reserves discounted at the market interest rate.  Any excess carrying amount above the net present value of the Company’s future expected cash flows is recorded as a permanent impairment and charged to operations.
 
 The cost of unproved properties is excluded from the impairment test described above and subject to a separate impairment test.  In the case of impairment, the book value of the impaired properties is moved to the petroleum and natural gas depletion base.
 
 (c)
Equipment
 
 Equipment is recorded at cost with amortization being provided using the declining balance basis at the following rates:
  Office furniture and equipment
20%Computer equipment
45%Software
100%Leasehold improvements
term of lease
 
 The carrying values of all categories of equipment are reviewed for impairment whenever events or changes in circumstances indicate the recoverable value may be less than the carrying amount. Recoverable value is based on estimates of undiscounted future net cash flows expected to be recovered from specific assets or groups through use or future disposition. One-half of the annual rates are used in the year of the acquisition.
 
 F-12
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 3 – SUMMARY OF OTHER SIGNIFICANT ACCOUNTING POLICIES (continued)
 
 (d)
Investments
 
 The Company accounts for its investments in other companies over which it has significant influence using the equity basis of accounting whereby the investments are initially recorded at cost and subsequently adjusted to recognize the Company’s share of earnings or losses of the investee company and reduced by dividends received. Carrying values of equity investments are reduced to estimated fair value if there is other than a temporary decline in the value of the investment.
 
 (e)
Earnings (Loss) per Share
 
 The Company uses the treasury stock method for the computation and disclosure of diluted earnings (loss) per share.  The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments which assume that proceeds received from in-the-money warrants and stock options are used to repurchase common shares at the prevailing market rate.
 
 Basic earnings (loss) per share figures have been calculated using the weighted average number of shares outstanding during the  periods.  Diluted earnings (loss) per share figure are equal to that of basic earnings (loss) per share since the effects of options and warrants have been excluded as they are anti-dilutive.
 
 (f)
Joint Operations
 
 Exploration, development, and production activities may be conducted jointly with others and accordingly, the Company only reflects its proportionate interest in such activities.
 
 (g)
Foreign Currency Translation
 
 The financial statements are presented in Canadian dollars.  Foreign denominated monetary assets and liabilities are translated into their Canadian dollar equivalents using foreign exchange rates which prevailed at the balance sheet date.  Non-monetary items are translated at historical exchange rates, except for items carried at fair value, which are translated at the rate of exchange in effect at the balance sheet date.  Revenue and expenses are translated at average rates of exchange during the year.  Exchange gains or losses arising on foreign currency translation are included in the determination of operating results for the year.
 
 The Company's US subsidiary is an integrated foreign operation and is translated into Canadian dollars using the temporal method.  Monetary items are translated at the exchange rate in effect at the balance sheet date; non-monetary items are translated at historical exchange rates.  Income and expense items are translated at the average exchange rate for the period.  Translation gains and losses are reflected in income (loss) for the year.
 
 (h)
Use of Estimates
 
 The preparation of financial statements in conformity with 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 financial statements and the reported amounts of revenues and expenses during the period.  Actual results could differ from those estimates.  The significant areas requiring management’s estimates relate to the recoverability of the carrying value of the Company’s resource properties, the amounts recorded for depletion and depreciation of oil and natural gas property, properties and equipment, the provision for asset retirement obligations, income tax effects and the determination of fair value of stock-based compensation.  The cost recovery ceiling test is based on estimates of proved reserves, production rates, oil and natural gas prices, future development cost, and other relevant assumptions.  By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be significant.
  F-13
 DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 
 NOTE 3 – SUMMARY OF OTHER SIGNIFICANT ACCOUNTING POLICIES (continued)
 
 (i)
Financial Instruments
 
 A financial instrument is any contract that gives rise to a financial asset of one entity and a financial liability or equity instrument to another entity.  Upon initial recognition all financial instruments, including derivatives, are recognized on the balance sheet at fair value, except for certain related party transactions.  Subsequent measurement is then based on the financial instruments being classified into one of five categories: held for trading, held to maturity, loans and receivables, available for sale and other liabilities.
 
 The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, bank line of credit and bridge loan, accounts payable and accrued liabilities, and loans from related parties.  Management has determined that the fair value of these financial instruments approximates their carrying values.
 
 The Company designated its cash and cash equivalents and bank line of credit and bridge loan as held-for-trading, which are measured at fair value.  Receivables are classified under loans and receivables, which are measured at amortized cost. Accounts payable and accrued liabilities and loans from related parties are classified as other financial liabilities, which are measured at amortized cost.
 
 Transaction costs related to the acquisition or issuance of financial instruments are expensed as incurred.
 
 The Company enters into derivative financial instruments to manage its exposure to volatility in commodity prices.  These instruments are not used for trading or other speculative purposes.  For derivative instruments that do qualify as effective accounting hedges, policies and procedures are in place to ensure that documentary and approvals requirements are met. The documentation specifically ties the derivative financial instruments to their use, and in the case of commodities, to the mitigation of market price risk associated with cash flows expected to be generated.  The Company also identifies all relationships between hedging instruments and hedged items, as well as its risk management objective and the strategy for undertaking hedge transactions. This would include linking the particular derivative to specific assets and liabilities or to specific firm commitments or forecasted transactions. Where specific hedges are executed, the Company assesses, both at the inception of the hedge and on an ongoing basis, whether the derivative used in the particular hedging transaction is effective in offsetting changes in fair value or cash flows of the hedged item.
 
 Cash flow hedges:  The effective portion of changes in the fair value of financial instruments designated as a cash flow hedge is recognized in other comprehensive income (loss), net of tax, with any ineffective portion being recognized in net income (loss).  Gains and losses are reclassified from other comprehensive income (loss) and recognized in net income (loss) in the same period as the hedged item.
 
 Fair value hedges:  Both the financial instrument designated as the hedging item, and the underlying hedged asset or liability, are measured at fair value.  Changes in the fair value of both the hedging and hedged item are reflected in net income (loss).
 
 Hedge accounting is discontinued prospectively when the derivative no longer qualifies as an effective hedge, or the derivative is terminated or sold, or upon the sale or early termination of the hedged item.  Derivative instruments that qualify as hedges, or have been designated as hedges, are recorded at fair value on inception.  At the end of each reporting period, the change in the fair value of the hedging derivative is recognized in other comprehensive income (loss).  When hedge accounting is discontinued or when the hedged item is sold or early terminated, the amounts previously recognized in accumulated other comprehensive income are reclassified to net income (loss).
 
 Net smelter royalties and related rights to earn or relinquish interests in mineral properties constitute derivative instruments.  No value or discounts have been assigned to such instruments as there is no reliable basis to determine fair value until properties are in development or production and reserves have been determined.
 
 F-14
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 3 – SUMMARY OF OTHER SIGNIFICANT ACCOUNTING POLICIES (continued)
 
 (j)
Future Income Taxes
 
 Future income taxes are recognized for the future income tax consequences attributable to differences between financial statement carrying values and their corresponding tax values (temporary differences).  Future income tax assets and liabilities are measured using substantively enacted income tax rates expected to apply to taxable income in years in which temporary differences are expected to be recovered or settled.  The effect on future income tax assets and liabilities of a change in tax rates is included in income (loss) in the period in which the change occurs.  The amount of future income tax assets recognized is limited to the amount that, in the opinion of management, is more likely than not to be realized.
 
 (k)
Revenue Recognition
 
 Revenues from the sale of oil and natural gas are recorded when title passes to an external party and collectability is reasonably assured.
 
 (l)
Stock-Based Compensation
 
 The Company follows the recommendations of the CICA Handbook in accounting for stock-based compensation. The Company adopted the fair value method for all stock-based compensation. Under the fair value based method, compensation cost is measured at fair value at the date of grant for employee awards and the earlier of performance, performance commitment or vest date for non-employee awards and are expensed over the award's vesting period for officers, directors and employees and over the service life for consultants.  The fair value of options and other stock based awards issued or altered in the period, are determined using the Black-Scholes option pricing model.
 
 (m)
Asset Retirement Obligations
 
 The Company reviews and recognizes legal obligations associated with the retirement of tangible long-lived assets, including rights to explore or exploit natural resources.  When such obligations are identified and measurable, the estimated fair values of the obligations are recognized on a systematic basis over the remaining period until the obligations are expected to be settled.  On recognition of the liability, there is a corresponding increase in the carrying amount of the related assets known as the asset retirement cost, which is depleted on a unit-of-production basis over the life of the assets.  The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to income (loss), and for revisions to the estimated future cash flows.  Actual costs incurred upon settlement of the obligations are charged against the liability to the extent of the recognized amount.
 
 F-15
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 3 – SUMMARY OF OTHER SIGNIFICANT ACCOUNTING POLICIES (continued)
 
 (n)
Flow-Through Shares
 
 The Company provides certain share subscribers with a flow-through component for tax incentives available on qualifying Canadian exploration expenditures.  The Company renounces the qualifying expenditures and accordingly is not entitled to the related taxable income deductions from such expenditures.
 
 The Company has adopted the recommendation by the Emerging Issues Committee of the CICA relating to the recording of flow-through shares.  EIC 146 stipulates that future income tax liabilities resulting from the renunciation of qualified resource expenditures by the Company from the issuance of flow-through shares are recorded as a reduction of share capital.  Any corresponding realization of future income tax benefits resulting in the utilization of prior year losses available to the Company not previously recorded, whereby the Company did not previously meet the criteria for recognition, are reflected as part of the Company’s operating results in the period the expenses are renounced to the share subscribers and applicable tax filing have been made with the Canada Revenue Agency.
 
 (o)
Impairment of Long-lived Assets
 
 CICA Handbook, Section 3063, Impairment of Long-lived Assets provides guidance on recognizing, measuring and disclosing the impairment of long-lived assets. The determination of when to recognize an impairment loss for a long-lived asset to be held and used is made when its carrying value exceeds the total undiscounted cash flows expected from its use and eventual disposition. When impairment is indicated other than a temporary decline, the amount of the impairment loss is determined as the excess of the carrying value of the amount over its fair value based on estimated discounted cash flows from use or disposition.
 
 (p)
Comprehensive Income (Loss)
 
 The Company follows CICA Handbook, Section 1530, Comprehensive Income.  Comprehensive income (loss) is defined as the change in equity from transactions and other events from non-owner sources.  Section 1530 establishes standards for reporting and presenting certain gains and losses not normally included in net income or loss, such as unrealized gains and losses related to available for sale securities, gains and losses resulting from the translation of self-sustaining foreign operations, and gains and losses resulting from changes in fair value of effective cash flow hedges, in a statement of comprehensive income (loss).
 
 NOTE 4 – EQUIPMENT
  December 31, 2010


December 31, 2009Accumulated








AccumulatedCost


Amortization


Net


Cost


Amortization


NetOffice furniture andequipment

$
138,709


$
84,605


$
54,104


$
135,804


$
71,350


$
64,454Computer equipment


96,528



76,836



19,692



85,020



66,033



18,987Software


32,334



26,068



6,266



19,802



17,686



2,116Leasehold improvements


32,433



9,730



22,703



32,433



3,243



29,190$
300,004


$
197,239


$
102,765


$
273,059


$
158,312


$
114,747
 F-16
 DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 5 – INVESTMENT IN TITAN URANIUM INC.
 
 In December 2006, the Company sold a 90% interest in its uranium properties, consisting of 68 claims and 4 permits totaling 966,969 acres located in the Athabasca Basin, Saskatchewan, Canada, and all related exploration data to Titan Uranium Inc. (“Titan”), a public company traded on the TSX-V, under the following terms:
 
 (a)
Titan issued the Company 17,500,000 fully paid and assessable common shares in the capital of Titan (representing a 36.47% of Titan’s issued and outstanding shares at closing).  Titan issued the Company 3,000,000 transferable common share purchase warrants, entitling the holder to acquire up to 3,000,000 common shares in the capital of Titan at an exercise price of $2.00 per common share for a period of 24 months. These warrants expired unexercised on December 15, 2008;
 
 (b)
The Company retained a 1% Net Smelter Return on all properties and a 10% working interest in each claim, carried by Titan to completed bankable feasibility study after which the Company may elect to participate as to its 10% interest or convert to an additional 1% Net Smelter Return.
 
 The Company accounted for its investment in Titan using the equity method until February 28, 2009, at which point the Company disposed of the majority of its shares in Titan and therefore is no longer qualified for the use of the equity method of accounting.The Company’s share of losses in Titan under the equity method for the year ended December 31, 2009 was $142,196.   During the year ended December 31, 2009, the Company sold all of its investment in Titan, resulting in a loss of $274,187.
  NOTE 6 – RESOURCE PROPERTIES
 
 (a)
Uranium Properties
 
 The carrying value of the Company’s remaining 10% carried interest and 1% net smelter return in the Athabasca Basin was $523,205 as at December 31, 2010 and $533,085 as at December 31, 2009 (Note 5).
  (b)
Oil and Gas Properties
 
 As at December 31

2010


2009$


$United StatesOil and gas properties, at cost


30,163,795



30,020,053Accumulated depletion


-



-Impairment of oil and gas properties


(1,403,929
)


(1,403,929
)28,759,866



28,616,124CanadaOil and gas properties, at cost


30,140,850



26,582,984Accumulated depletion


(15,196,816
)


(10,018,351
)Impairment of oil and gas properties


(3,955,854
)


(3,955,854
)10,988,180



12,608,77939,748,046



41,224,903
 
 F-17
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 6 – RESOURCE PROPERTIES (continued)
 
 United States Oil and Gas Properties
 
 As at December 31, 2010, the Company holds approximately 110,000 net acres of oil and gas leases in the Piceance, Parados and Uinta Basins in the US Rocky Mountains (2009 – 110,000 net acres).
 
 During the year ended December 31, 2010, the Company sold its entire 72% working interest in certain oil and gas leases in the area of Colorado to an unrelated third party for gross proceeds of $652,405 (US$650,000).
 
 Before determining proved reserves effective December 31, 2009 in March 2010, the Company recognized an impairment of $1,403,929 on the expiry of a number of leases.  The Company performed a ceiling test calculation at December 31, 2010 to assess the recoverable value of its US oil and gas properties.  Based on the calculation, the value of future net revenues from the Company’s US proved reserves exceeded the carrying value of its properties at December 31, 2010.  The benchmark prices used in the calculation are described below.
 
 During the year ended December 31, 2010, the Company capitalized $553,953 (2009 - $313,577) of general and administrative costs to its US properties. During fiscal 2010 and 2009, the Company did not have any production from its US oil and gas properties and accordingly did not deplete any of its US oil and gas properties.
 
 Natural gas(Henry Hub)US$ / mmbtu2011
5.362012
5.602013
5.782014
5.952015
6.132016
6.332017
6.542018
6.752019
6.962020
7.182021
7.392022 and thereafter
7.66
 * At December 31, 2010, the US$ to CAD$ exchange rate was 0.9946.
 
 Canadian Oil and Gas Properties
 
 As at December 31, 2010, the Company holds approximately 13,000 net acres of oil and gas leases in the Peach River Arch of northwestern British Columbia and northeastern Alberta of Canada (2009 – 20,000 net acres).
 
 During the year ended December 31, 2010, the Company sold its entire 90% working interest in the Buick Creek area to an unrelated third party for gross proceeds of $951,566. This property disposition did not result in more than 20% change in depletion; accordingly there was no gain or loss recognized on the disposition.
 
 During the year ended December 31, 2009, the Company sold 100% of its working interest in the Carson Creek area to an unrelated third party for gross proceeds of $2,100,000.  In addition, the Company sold a 25% working interest in its Drake/Woodrush properties for gross proceeds of $4,500,000, 5% of which was purchased by a private company controlled by the Chief Executive Officer (“CEO”) of the Company in settlement of debt of $911,722 (Note 8). This related party transaction has been measured at the agreed to exchange amount as there was a substantive change in ownership of the transferred asset that is supported by independent evidence of fair value. The Company still retained 75% working interest in the Drake/Woodrush properties as at December 31, 2010.
  F-18
 DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 6 – RESOURCE PROPERTIES (continued)
 
 Depletion and depreciation is computed using the unit-of-production method based on the estimated net proven reserves of oil and gas determined by independent consultants. The calculation of amortization and depletion included an estimated $3,264,000 (2009 - $2,289,000) for future development costs associated with proved undeveloped reserves and excluded $Nil (2009 - $915,782) for the carrying amount of unproved properties.
 
 For the year ended December 31, 2010, $694,628 (2009 - $322,200) of geological and geophysical consultant costs and general and administrative expenses were capitalized to its Canadian oil and gas properties.
 
 The Company performed a ceiling test calculation at December 31, 2010 to assess the recoverable value of the properties.  The oil and gas future prices are based on the commodity price forecast of independent reserve evaluators.  Based on these assumptions, the undiscounted value of future net revenues from the Company’s proved reserves were more than the carrying value of oil and gas properties at December 31, 2010. As a result, the Company recorded an impairment of oil and gas properties of $Nil (2009 - $3,955,854).
 
 The benchmark prices on which the December 31, 2010 ceiling test is based are as follows:
 
 Natural gas
Condensate
Crude oil(AECO)
(Edmonton Pentanes Plus)
(Edmonton Par)Cdn $ / mmbtu
Cdn $ / bbl
Cdn $ / bbl2011
4.16
90.54
86.222012
4.74
91.96
89.292013
5.31
92.74
90.922014
5.77
94.82
92.962015
6.22
98.12
96.19Each benchmark price increased on average approximately 2% from 2016 and thereafter
 
 NOTE 7 – BANK LINE OF CREDIT AND BRIDGE LOAN
 
 In August 2008, the Company secured a revolving operating loan facility with a Canadian Bank for up to $7,000,000, subject to certain production targets.  This facility collateralized by DEAL’s oil and gas properties in Canada, bore interest at Canadian prime plus 1% per annum.  In accordance with the terms of the facility, the Company was required to maintain an adjusted working capital ratio of not less than 1.10:1.  The adjusted working capital ratio is defined as the ratio of (i) current assets plus any undrawn availability under the facility, to (ii) current liabilities less any amount drawn under the facility.
 
 During the year ended December 31, 2009, the terms of the bank line of credit were amended. The facility was reduced from $7,000,000 to $1,780,000 and the interest rate was adjusted to Canadian prime plus 2%.As at December 31, 2009, $850,000 of this facility was utilized and the Company was in compliance with the working capital ratio requirement.In January 2010, the terms of the bank line of credit were further amended. The facility was reduced from $1,780,000 to $1,000,000. In March 2010, the bank line of credit was paid off in full in cash.
 
 In March 2010, the Company negotiated a credit facility for a bridge loan of up to $5,000,000. This facility is secured by a first floating charge over all assets of DEAL, bears interest at 12% per annum and was due September 22, 2010 but was extended to March 31, 2011.
 
 F-19
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 7 – BANK LINE OF CREDIT AND BRIDGE LOAN (continued)
 
 By agreement, certain terms of the facility were amended such that the credit limit is reduced by $100,000 per month and the Company is required to make monthly principal payments of $100,000 commencing November 30, 2010 with the borrowing subject to the drawdown fee adjusted to 2% from 1% on any amounts drawn and the deferred fee lowered to 1% from 2% on any repayments with no change in interest rate. Additionally, the due date of bridge loan is extended to March 31, 2011 and can be further extended for a maximum of 3 months subject to a 1% extension fee per month on the outstanding loan balance. In March 2011, the lender approved to extend the due date of the loan to April 30, 2011 and the Company is in discussion with the lender for further extension.
 
 During the year ended December 31, 2010, the Company made monthly principal payment of $100,000 and reduced the outstanding balance to $4,800,000. This facility is used to support the development of its oil and gas properties in the Drake/Woodrush area.
 
 According to the terms of the facility, DEAL is required to maintain (a) a working capital ratio of not less than 1:1; (b) a debt to equity ratio within 0.5:1; and (c) a debt to trailing cash flow ratio within 2.5:1. The working capital ratio is defined as the ratio of (i) current assets (including any undrawn and authorized availability under the facility as cash) to (ii) current liabilities (excluding outstanding balances of the facility unless past due). The debt to equity ratio is defined as the ratio of (i) debt (secured debt plus working capital deficit or minus working capital surplus) to (ii) equity (shareholder equity plus retained earnings or minus deficit plus formally postponed shareholder and related party advances). The debt to trailing cash flow ratio is defined as the ratio of (i) debt (secured debt plus working capital deficit or minus working capital surplus) to (ii) cash flow (net income plus all non-cash charges). As at December 31, 2010, the Company is in compliance with all covenants.
  NOTE 8 – LOANS FROM RELATED PARTIES
 
 (a)
Loan from Hodgkinson Equity Corporation (“HEC”)
 
 HEC loan to DEAL
 
 On May 15, 2008, DEAL issued a promissory note for up to $2,000,000 to HEC, a private company controlled by the CEO of the Company. The promissory note was collateralized by the assets, equipment, fixtures and accounts receivable of DEAL, bears interest at the Royal Bank of Canada Prime Rate per annum, and has a loan fee of 1% of the outstanding amount per month. The principal, interest and loan fee were payable on demand after August 15, 2008.  Upon securing the bank line of credit in August 2008 (note 7), HEC signed a subordination and postponement agreement which restricted the principal repayment of the promissory note subject to the bank’s prior approval and DEAL meeting certain loan covenants. As at December 31, 2008, $1,950,000 had been advanced on the promissory note. Repayments of $150,000 were made during fiscal 2009. As at June 22, 2009, a balance of $1,800,000 remained outstanding and the debt was assumed from DEAL by the Company.
 
 HEC loan to the Company
 
 On June 22, 2009, as amended on September 30, 2009 and December 31, 2009, the Company entered into an agreement with HEC in regard to the outstanding debt of $1,800,000 assumed from DEAL by the Company.  Pursuant to the agreements, $450,000 of the debt was converted into 1,363,636 units consisting of 1,363,636 common shares and 681,818 common share purchase warrants exercisable at a price of $0.55 for a period of 5 years.  The fair value of the units was estimated to be $450,000 with an estimated fair value of $0.33 per unit based on the share trading price and other relevant information. The remaining $1,350,000 of outstanding debt was converted into a 12% note due on January 1, 2011 and the Company was required to pay a 3% fee on the outstanding balance of the loan as at December 31, 2009.  As a result of the sale of 5% working interest in the Drake/Woodrush area to HEC in December 2009 (effective June 1, 2009), both parties agreed to reduce the loan balance by the purchase price of $911,722 including taxes and adjustments (Note 6). In addition, the loan balance was further reduced by a payment of $50,351.  As at December 31, 2009, a balance of $387,927 remained outstanding.
  F-20
 
 DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 8 – LOANS FROM RELATED PARTIES (continued)
 
 In December 2010, a repayment of $137,927 was made to HEC by the Company. As at December 31, 2010, a balance of $250,000 remained outstanding. Subsequent to December 31, 2010, the loan was repaid in full in cash.
 
 (b)
Loan from Brownstone Ventures Inc. (“Brownstone”)
 
 On June 22, 2009, as amended on September 30, 2009 and December 31, 2009, the Company entered into an agreement with Brownstone in regard to the promissory note of $4,604,040 (US$3,780,000). Brownstone owns more than 10% of outstanding common shares of the Company and one of Brownstone’s directors also serves on the board of directors of the Company. Pursuant to the agreement, $2,200,000 (US$2,000,000) of the debt was converted into 6,666,667 units consisting of 6,666,667 common shares and 3,333,333 common share purchase warrants exercisable at a price of $0.55 for a period of 5 years.  The fair value of the units was estimated to be US$2,000,000 with an estimated value of US$0.30 per unit based on the Company’s share price and other relevant information.  The remaining $2,070,140 (US$1,780,000) of the debt was converted into a Canadian dollar denominated 12% note due on January 1, 2011. The note is secured by the assets of Dejour USA.
 
 As part of the debt settlement agreement dated June 22, 2009, the Company also issued Brownstone 2,000,000 common share purchase warrants exercisable at $0.50 for a period of 2 years, with an issuer option to force the exercise of the warrants if the Company’s common shares trade at a price of $0.80 or greater for 30 consecutive calendar days.  The fair value of the warrants of $169,000 has been recorded in contributed surplus and fully amortized as finance fees over the life of the note. The fair value of the warrants was estimated on the grant date using the Black-Scholes option pricing model using a volatility rate of 89.41% and risk-free interest rate of 1.23% for a term of 18 months.
 
 As at December 31, 2009, a balance of $1,957,474 remained outstanding comprised of the loan balance of $2,070,140 minus the unamortized portion of finance fees of $112,666. In December 2010, the loan was repaid in full in cash.
  NOTE 9 – ASSET RETIREMENT OBLIGATIONS
 
 The total future asset retirement obligations were estimated based on the Company’s net ownership interest in all wells and facilities, the estimated cost to abandon and reclaim the wells and facilities and the estimated timing of the cost to be incurred in future periods.  The Company estimated the total undiscounted amount of the cash flows required to settle the retirement obligations related to its oil and gas properties in Canada as at December 31, 2010 to be $1,068,106.  These obligations are expected to be primarily settled in 2019.  A credit adjusted risk-free rate of 9% and an inflation rate of 2.0% was used to calculate the present value of the asset retirement obligations.
 
 Balance at December 31, 2008

$
363,109Change in estimate


(154,160
)Accretion expense


12,863Actual costs incurred


(13,296
)Balance at December 31, 2009


208,516Liabilities incurred during the year


300,200Accretion expense


32,502Balance at December 31, 2010

$
541,218
  F-21
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 10 – SHARE CAPITAL
 
 Authorized:
Unlimited common voting shares, no par value

Unlimited first preferred shares, issuable in series

Unlimited second preferred shares, issuable in series
  CommonShares


ValueBalance at December 31, 2007


70,128,329


$
61,393,964- For conversion of convertible debenture


884,242



1,214,497- For cash on exercise of stock options


1,681,048



887,621- For cash on exercise of warrants


958,263



1,447,464- Contributed surplus reallocated on exercise of stock options


-



532,531- Renounced flow through share expenditures


-



(536,900
)Balance at December 31, 2008


73,651,882



64,939,177- For cash on exercise of stock options


631,856



273,223- For settlement of debt (Note 8)


8,030,303



2,650,000- For cash by private placements, net of share issuance costs


13,476,997



4,549,882- Contributed surplus reallocated on exercise of stock options


-



147,222Balance at December 31, 2009


95,791,038



72,559,504- General share issuance costs


-



(130,593
)- For cash by private placements, net of share issuance costs


14,389,507



4,114,101- Renounced flow through share expenditures


-



(968,000
)Balance at December 31, 2010


110,180,545


$
75,575,012
 
 During the year ended December 31, 2010, the Company completed the following:
 
 In December 2010, the Company renounced $1,767,567 flow-through funds to investors, using the general rule. The flow-through funds had been fully spent by December 31, 2010. As a result of the renunciation, future income tax recovery of $504,000 was recognized against share capital.
 
 In December 2010, the Company completed a private placement and issued 2,339,315 flow-through shares at $0.38 per share. Gross proceeds raised were $888,940.  In connection with this private placement, the Company paid finders’ fees of $53,337 and other related costs of $61,862. The Company also issued 140,359 agent’s warrants, exercisable at $0.38 per share on or before December 23, 2011. The grant date fair values of the agent’s warrants, estimated to be $4,211, have been included in share capital on a net basis and accordingly have not been recorded as a separate component of shareholders’ equity. Directors and Officers of the Company purchased 513,157 shares of this offering.
 
 In November 2010, the Company completed a private placement and issued 7,142,858 units at $0.28 per unit. Each unit consists of one common share and 0.65 of a common share purchase warrant. Each whole common share purchase warrant is exercisable into one common share of the Company at $0.40 per share on or before November 17, 2015. Gross proceeds raised were $2,000,000. In connection with this private placement, the Company paid finders’ fees of $120,000 and other related costs of $123,423. The grant date fair values of the warrants, estimated to be $381,078, have been included in share capital on a net basis and accordingly have not been recorded as a separate component of shareholders’ equity.
 
 In September 2010, the Company completed a private placement and issued 2,000,000 flow-through shares at $0.375 per share. Gross proceeds raised were $750,000.  In connection with this private placement, the Company paid finders’ fees of $37,500 and other related costs of $38,890.
  F-22
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 10 – SHARE CAPITAL (continued)
 
 In March 2010, the Company completed a private placement and issued 2,907,334 flow-through units at $0.35 per unit. Each unit consists of one common share and one-half of a common share purchase warrant. Each whole common share purchase warrant is exercisable into one common share of the Company at $0.45 per share on or before March 3, 2011. Gross proceeds raised were $1,017,567.  In connection with this private placement, the Company paid finders’ fees of $54,575 and other related costs of $52,819. The Company also issued 37,423 agent’s warrants, exercisable at $0.45 per common share on or before March 3, 2011. The grant date fair values of the warrants and agent’s warrants, estimated to be $45,563 and $2,245 respectively, have been included in share capital on a net basis and accordingly have not been recorded as a separate component of shareholders’ equity. Directors and Officers of the Company purchased 412,500 units of this offering and no finders’ fee was paid on their participation in the offering.
 
 In January 2010, the Company renounced $1,626,199 flow-through funds to investors, using the look-back rule. Of this $1,626,199, $1,049,407 of renounced Canadian Exploration Expenditures (“CEEs”) had been spent by December 31, 2009 and the remaining flow-through funds had been fully spent by February 28, 2010. As a result of the renunciation, future income tax recovery of $464,000 was recognized against share capital.
 
 During the year ended December 31, 2009:
 
 In December 2009, the Company completed a private placement and issued 10,766,665 units at US$0.30 per unit. Each unit consists of 10,766,665 common shares and 8,075,000 share purchase warrants, exercisable at US$0.40 per common share on or before December 23, 2014. Gross proceeds raised were $3,425,060 (US$3,230,000). In connection with this private placement, the Company paid finders’ fees of $203,180 and other related costs of $140,788. The Company also issued 645,999 agent’s warrants, exercisable at US$0.46 per common share on or before November 3, 2014. The grant date fair values of the warrants and agent’s warrants, estimated to be $888,250 and $71,060 respectively, have been included in share capital on a net basis and accordingly have not been recorded as a separate component of shareholders’ equity.
 
 In October 2009, the Company completed a private placement and issued 2,710,332 flow-through common shares (“FTS”) at $0.60 per flow-through common share. Gross proceeds raised were $1,626,199.  In connection with this private placement, the Company paid finders’ fees of $83,980 and other related costs of $73,427.
 
 During the year ended December 31, 2008:
 
 In January 2008, the Company renounced $1,820,000 flow-through funds to investors, using the look-back rule. Of this $1,820,000, $263,222 of renounced Canadian Exploration Expenditures (“CEEs”) had been spent by December 31, 2007 and the remaining flow-through funds had been fully spent by February 29, 2008. As a result of the renunciation, future income tax recovery of $536,900 was recognized against share capital.
 
 In February 2008, the Company filed a Part XII.6 tax return with the Canada Revenue Agency related to CEEs with an effective date of renunciation of December 31, 2006 and paid $236,348 of Part XII.6 tax.
  F-23
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 11 – STOCK OPTIONS AND SHARE PURCHASE WARRANTS
  The Stock Option Plan (the “Plan”) is a 10% “rolling” plan pursuant to which the number of common shares reserved for issuance is 10% of the Company’s issued and outstanding common shares as constituted on the date of any grant of options.
  The Plan provides for the grant of options to purchase common shares to eligible directors, senior officers, employees and consultants of the Company (“Participants”). The exercise periods and vesting periods of options granted under the Plan are to be determined by the Board of Directors. The expiration of any option will be accelerated if the participant’s employment or other relationship with the Company terminates. The exercise price of an option is to be set by the Board of Directors at the time of grant but shall not be lower than the market price (as defined in the Plan) at the time of grant.
 
 During the year ended December 31, 2010, the Company granted 3,573,000 (2009 – 3,312,000) options to its officers, directors, consultants, employees and advisors. In addition, 1,043,182 (2009 – 5,461,842) options were cancelled or expired with a weighted average exercise price at $0.43 (2009 - $1.46).
 
 As at December 31, 2010, there were 6,946,500 options outstanding with a weighted average exercise price at $0.40, of which 3,250,075 were vested. The vested options can be exercised for periods ending up to July 25, 2015 to purchase common shares of the Company at prices ranging from $0.35 to $0.45 per common share.
 
 The Company expenses the fair value of all stock options granted over their respective vesting periods for directors and employees and over the service life for consultants. The fair value of the options granted during the year ended December 31, 2010 was determined to be $739,200 (2009 - $930,250). The Company determined the fair value of stock options granted using the Black-Scholes option pricing model using the following weighted average assumptions: Expected option life of 4.85 years (2009 – 3.94 years), risk-free interest rate of 2.37% (2009 – 1.66%) and expected volatility of 86.36% (2009 – 100.52%).
 
 During the year ended December 31, 2010, the Company recognized a total of $620,301 (2009 - $697,467 and 2008 - $2,719,957) of stock based compensation relating to the vesting of options.
 
 As at December 31, 2010, there were 3,696,425 unvested options included in the balance of the outstanding options. As of December 31, 2010, there was $919,267 of total unrecognized compensation cost related to non-vested stock options. That cost is expected to be recognized over a weighted average period of 2.29 years.  The following table summarizes information about stock option transactions:
  Weighted


Weighted AverageNumber of


Average Exercise


RemainingOptions


Price


Contractual LifeBalance, December 31, 2007


5,627,481


$
1.49



1.96 yearsOptions granted


4,945,000



0.88Options exercised


(1,681,048
)


0.53Options cancelled and expired


(1,693,053
)


1.83Balance, December 31, 2008


7,198,380



1.22



2.94 yearsOptions granted


3,312,000



0.46Options exercised


(631,856
)


0.43Options cancelled (forfeited)


(5,287,478
)


1.45Options expired


(174,364
)


1.72Balance, December 31, 2009


4,416,682



0.45



3.54 yearsOptions granted


3,573,000



0.35Options cancelled (forfeited)


(400,000
)


0.39Options expired


(643,182
)


0.46Balance, December 31, 2010


6,946,500


$
0.40



3.47 years
  F-24
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 11 – STOCK OPTIONS AND SHARE PURCHASE WARRANTS (continued)
 
 Details of stock options vested and exercisable as at December 31, 2010 are as follows:
  Weighted AverageNumber of Options





RemainingOutstanding and





Contractual Lifevested


Exercise Price


(Years)1,565,250


$0.35


4.121,684,825


$0.45


2.643,250,075


$0.40


3.35
 
 The following table summarizes information about warrant transactions:
  Weighted AverageOutstanding


Weighted Average


RemainingWarrants


Excercise Price


Contractual LifeBalance, December 31, 2007


2,372,531


$
3.15



1.31 yearsWarrants issued


884,242



1.53Warrants exercised


(958,263
)


1.53Warrants expired


(194,381
)


1.53Balance, December 31, 2008


2,104,129



3.35



0.40 yearsWarrants issued


14,736,150



0.47Warrants expired


(2,104,129
)


3.35Balance, December 31, 2009


14,736,150


$
0.47



4.36 yearsWarrants issued


6,274,305



0.41Balance, December 31, 2010


21,010,455


$
0.44



3.45 years
 
 Details of warrants outstanding as at December 31, 2010 are as follows:
  Number of





Weighted AverageWarrants





Remaining ContractualOutstanding


Exercise Price


Life (Years)140,359


$
0.38


0.984,642,856


$
0.40


4.881,491,090


$
0.45


0.172,000,000


$
0.50


0.474,015,151


$
0.55


3.478,075,000



US$0.40


3.98645,999



US$0.46


3.8421,010,455
  F-25
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 12 – CONTRIBUTED SURPLUS
 
 Details of changes in the Company's contributed surplus balance are as follows:
  Balance at December 31, 2007

$
3,735,270Stock compensation on vesting of options


2,719,957Value of conversion feature on convertible debenture


(27,136
)Allocated to share capital on exercise of options


(532,531
)Balance at December 31, 2008


5,895,560Stock compensation on vesting of options


697,467Value of conversion feature on convertible debenture


(147,222
)Allocated to share capital on exercise of options


169,000Balance at December 31, 2009


6,614,805Stock compensation on vesting of options


620,301Balance at December 31, 2010

$
7,235,106
 
 NOTE 13 – SUPPLEMENTAL CASH FLOW INFORMATION
  a. Changes in operating non-cash working capital consisted of the following:
  2010


2009


2008Changes in non-cash working capital:Accounts receivable

$
36,147


$
115,922


$
(840,695
)Prepaids and deposits


33,528



30,801



331,833Accounts payable and accrued liabilities


(180,737
)


(1,088,287
)


1,077,635$
(111,062
)

$
(941,564
)

$
568,773Comprised of:Operating activities

$
533,411


$
(47,977
)

$
449,233Investing activities


(402,811
)


(1,187,318
)


119,540Financing activities


(241,662
)


293,731



-$
(111,062
)

$
(941,564
)

$
568,773Other cash flow information:Cash paid for interest

$
576,549


$
569,192


$
374,679Income taxes paid


-



-



-$
576,549


$
569,192


$
374,679
  b. Except as disclosed elsewhere, the Company had the following non-cash transactions:
  Supplemental schedule of non-cash transactionsCommon shares issued for settlement of debt (Note 8)

$
-


$
2,650,000


$
-Sale of resource property for settlement of debt (Note 8)

$
-


$
911,721


$
-Common shares issued for conversion of convertible debenture

$
-


$
-


$
1,214,497Conversion feature on convertible debenture

$
-


$
-


$
(27,136
)Contributed surplus as common share capital upon exercise of stock options (Note 10)

$
-


$
147,222


$
532,531
  F-26
 DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 14 – RELATED PARTY TRANSACTIONS
 
 Except as disclosed elsewhere, during the years ended December 31, 2010, 2009 and 2008, the Company entered into the following transactions with related parties:
 
 (a)
The Company incurred a total of $520,152 (2009 - $682,618 and 2008 - $737,112) in consulting and professional fees and a total of $Nil (2009 - $90,714 and 2008 - $111,291) in rent expenses to the companies controlled by officers of the Company.  The consulting and professional fees are included in general and administrative expenses. Included in accounts payable and accrued liabilities at December 31, 2010 is $12,000 (December 31, 2009 and 2008 - $Nil) owing to a company controlled by an officer of the Company. Included in the total consulting and professional fees incurred during 2009 was $107,000 paid to a former senior officer of the Company to terminate his consulting agreement.
 
 (b)
The Company incurred a total of $268,440 (2009 - $382,748 and 2008 - $300,434) in interest expense and finance fee to the company controlled by an officer of the Company and Brownstone. Included in accounts payable and accrued liabilities at December 31, 2010 is $Nil (December 31, 2009 - $47,523 and December 31, 2008 - $8,248) owing to the company controlled by an officer of the Company.
 
 (c)
Included in interest and other income is $30,000 (2009 - $30,000 and 2008 - $28,700) received from the companies controlled by officers of the Company for rental income.
 
 (d)
Included in interest and other income is $Nil (2009 - $114,200 and 2008 - $Nil) received from Brownstone for consulting services.
 
 (e)
In December 2009, the company controlled by the CEO of the Company became a 5% working interest partner in the Drake/Woodrush properties.  Included in accounts payable and accrued liabilities at December 31, 2010 is $166,139 (December 31, 2009 - $63,679) owing to a company controlled by an officer of the Company.
 
 (f)
In July 2008, Brownstone became a 28.53% working interest partner in the US oil and gas properties. Included in accounts receivable at December 31, 2010 is $169,687 (December 31, 2009 - $69,221 and December 31, 2008 - $69,619) owing from Brownstone.
 
 (g)
In December 2010, the Company sold its entire 90% working interest in the Buick Creek area to an unrelated third party for gross proceeds of $951,566, in which HEC had a 10% working interest in the property.
 
 These transactions are measured at the exchange amount established and agreed to by the related parties.
 
 F-27
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 15 – FUTURE INCOME TAXES
 
 The actual income tax provisions differ from the expected amounts calculated by applying the Canadian combined federal and provincial corporate income tax rates to the Company’s loss before income taxes.  The components of these differences are as follows:
  2010


2009


2008Loss before income taxes

$
(6,132,878
)

$
(13,940,058
)

$
(20,294,513
)Corporate tax rate


30.00
%


30.00
%


31.00
%Expected tax recovery


(1,839,863
)


(4,182,017
)


(6,291,299
)Increase (decrease) resulting from:Differences in foreign tax rates and changein effective tax rates


355,931



695,723



(84,595
)Impact of foreign exchange rate changes


(47,332
)


(101,005
)


(350,194
)Titan shares and warrants investment


-



-



886,123Change in future tax asset valuation allowance


1,060,163



3,028,499



5,407,647Stock based compensation, share issue costsand other permanent differences


(39,020
)


(231,005
)


1,122,460Other adjustments


(457,879
)


(343,335
)


(93,902
)Future income taxes recovery

$
(968,000
)

$
(1,133,140
)

$
596,240
 
 The Company’s tax-effected future income tax assets and liabilities are made up as follows:
  2010


2009


2008Future income tax assetsNon-capital losses available

$
7,753,960


$
6,829,131


$
5,253,487Capital losses available


1,042,668



1,365,955



1,594,217Resource tax pools in excess of net book value


1,632,981



1,204,440



-Share issue costs and other


257,182



227,102



322,84210,686,791



9,626,628



7,170,546Future income tax liabilitiesLong term investments


-



-



(392,403
)Net book value in excess of resource tax pools


-



-



(1,312,812
)-



-



(1,705,215
)Net future income tax assets


10,686,791



9,626,628



5,465,331Valuation allowance


(10,686,791
)


(9,626,628
)


(6,598,471
)Net future income tax liabilities

$
-


$
-


$
(1,133,140
)
  F-28
 DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 15 – FUTURE INCOME TAXES (continued)
 
 The Company has the approximate amounts of tax pools available as follows:
  2010


2009


2008As at December 31

$


$


$Canada:Exploration and development expenditures


16,047,000



18,477,000



23,979,000Unamortized share issue costs


1,003,000



772,000



798,00Capital losses


8,242,000



5,274,000



11,058,000Non-capital losses


15,997,000



12,764,000



9,968,00041,289,000



37,287,000



45,803,000United States:Exploration and development expenditures


27,146,000



27,099,000



26,930,000Non-capital losses


10,009,000



9,384,000



6,478,00037,155,000



36,483,000



33,408,000Total


78,444,000



73,770,000



79,211,000
 
 The exploration and development expenditures can be carried forward to reduce future income taxes indefinitely. The Company’s non-capital losses in Canada expire between 2015 and 2030 and the United States non-capital losses expire between 2026 and 2030.
  NOTE 16 – COMMITMENT
 
 In connection with the issuance of flow through shares by the Company during the year ended December 31, 2010, the Company is required to expend $2.7 million of eligible exploration expenditures by December 31, 2011. $1.8 million was expended by December 31, 2010.
 
 In connection with the issuance of flow through shares by the Company during the year ended December 31, 2009, the Company is required to expend $1.6 million of eligible exploration expenditures by December 31, 2010. $1 million was expended by December 31, 2009 and $0.6 million was expended by December 31, 2010.
 
 The Company has entered into lease agreements on office premises for its various locations.  Under the terms of the leases, the Company is required to make minimum annual payments.  Future minimum annual lease payments under the leases are as follows:
 
 2011

$
215,7842012


151,9662013


73,0512014


48,701$
489,502
 
 F-29
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 17 – SEGMENTED DISCLOSURE
 
 As at December 31, 2010, 2009 and 2008, the Company’s significant assets, losses and revenue by geographic location were as follows:
 
 2010


2009


2008CanadaRevenue

$
8,153,549


$
6,785,995


$
5,751,672Interest and other income


36,602



302,824



124,208Future income tax recovery (expense)


968,000



1,133,140



(596,240
)Segmented loss


(4,332,693
)


(10,969,741
)


(17,301,636
)Assets:Current Assets


5,147,727



3,254,900



1,578,847Deposits


396,875



391,870



186,752Equipment, net


76,806



85,664



80,701Investment in Titan


-



-



2,721,875Uranium properties


523,205



533,085



696,991Oil and gas properties, net


10,988,181



12,608,779



27,493,32917,132,794



16,874,298



32,758,495U.S.A.Revenue


-



-



13,883Interest and other income


-



114,200



112,630Segmented loss


(832,185
)


(1,837,177
)


(3,589,117
)Assets:Current Assets


391,162



328,836



270,908Deposits


45,387



37,536



84,502Equipment, net


25,959



29,083



35,883Oil and gas properties, net


28,759,865



28,616,124



29,493,39829,222,372



29,011,578



29,884,691Total assets

$
46,355,166


$
45,885,876


$
62,643,186
 
 NOTE 18 – LITIGATION
 
 The Company was involved in a termination claim and litigation from a former officer and director.  In February 2010, both parties agreed to settle the claim and the Company made a settlement payment of $100,000 to the former director and officer.
  F-30
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 19 – FINANCIAL INSTRUMENTS, RISK MANAGEMENT AND CAPITAL MANAGEMENT STRATEGY
 
 The Company is engaged primarily in oil and gas exploration and production and manages related industry risk issues directly.  The Company may be at risk for environmental issues and fluctuations in commodity pricing.
  The Company’s functional currency is the Canadian dollar. The Company operates in foreign jurisdictions, giving rise to significant exposure to market risks from changes in foreign currency rates.  The financial risk is the risk to the Company's operations that arises from fluctuations in foreign exchange rates and the degree of volatility of these rates.  Currently, the Company does not use derivative instruments to reduce its exposure to foreign currency risk.
 
 The Company also has exposure to a number of risks from its use of financial instruments including: credit risk, liquidity risk, and market risk.  This note presents information about the Company’s exposure to each of these risks and the Company’s objectives, policies and processes for measuring and managing risk, and the Company’s management of capital.
 
 The Board of Directors has overall responsibility for the establishment and oversight of the Company’s risk management framework.  The Board has implemented and monitors compliance with risk management policies.  The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities.
 
 (a)
Credit Risk
 
 Credit risk arises from credit exposure to joint venture partners and marketers included in accounts receivable. The maximum exposure to credit risk is equal to the carrying value of the financial assets.
 
 The Company is exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company’s business, financial condition, and results of operations.
 
 The objective of managing the third party credit risk is to minimize losses in financial assets. The Company assesses the credit quality of the partners, taking into account their financial position, past experience, and other factors. The Company mitigates the risk of collection by obtaining the partners’ share of capital expenditures in advance of a project and by monitoring accounts receivable on a regular basis. As at December 31, 2010, 2009 and 2008, no accounts receivable has been deemed uncollectible or written off during the year.
 
 (b)
Liquidity Risk
 
 Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due.  The Company’s approach to managing liquidity is to ensure, as far as possible, that it will have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions without incurring unacceptable losses or risking harm to the Company’s reputation.
 
 As the industry in which the Company operates is very capital intensive, the majority of the Company’s spending is related to its capital programs.  The Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary.  Further, the Company utilizes authorizations for expenditures on both operated and non-operated projects to further manage capital expenditures.  To facilitate the capital expenditure program, the Company has a bridge loan credit facility (note 7).  The Company also attempts to match its payment cycle with collection of oil and natural gas revenues on the 25th of each month.
 
 Accounts payable are considered due to suppliers in one year or less while the bank line of credit was repaid in full during the year ended December 31, 2010. The bridge loan, which is in discussion with the lender for further extension, is due in April 2011.
  F-31
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 19 – FINANCIAL INSTRUMENTS, RISK MANAGEMENT AND CAPITAL MANAGEMENT STRATEGY (continued)
 
 (c)
Market Risk
 
 Market risk is the risk that changes in market prices, such as foreign exchange rates, commodity prices, and interest rates will affect the Company’s net earnings or the value of financial instruments.  The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns.  The Company utilizes financial derivatives to manage certain market risks.  All such transactions are conducted in accordance with the risk management policy that has been approved by the Board of Directors.
 
 (i)
Foreign Currency Exchange Risk
 
 Foreign currency exchange rate risk is the risk that the fair value of financial instruments or future cash flows will fluctuate as a result of changes in foreign exchange rates.  Although substantially all of the Company’s oil and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for oil and natural gas are impacted by changes in the exchange rate between the Canadian and United States dollars.  Given that changes in exchange rate have an indirect influence, the impact of changing exchange rates cannot be accurately quantified.  The Company had no forward exchange rate contracts in place as at or during the year ended December 31, 2010, 2009 and 2008.
 
 The Company was exposed to the following foreign currency risk at December 31:
  2010


2009


2008Expressed in foreign currencies

US$


US$


US$Cash and cash equivalents


604,785



1,526,455



91,265Accounts receivable


169,687



69,221



107,158Accounts payable and accrued liabilities


(228,767
)


(263,048
)


(44,066
)Balance sheet exposure


545,705



1,332,628



154,357
 
 The following foreign exchange rates applied for the year ended and as at December 31:
  2010


2009


2008YTD average USD to CAD


0.9946



1.1420



1.2115December 31, reporting date rate


1.0305



1.0510



1.2180
 
 YTD average rate rting date rateates applied for the year ended and as at December 31, 2009:ing, and July 1, 2009. nd other com
 The Company has performed a sensitivity analysis on its foreign currency denominated financial instruments. Based on the Company’s foreign currency exposure noted above and assuming that all other variables remain constant, a 10% appreciation of the US dollar against the Canadian dollar would result in the decrease of net loss of $54,276 at December 31, 2010 (2009 - $140,059 and 2008 - $18,801). For a 10% depreciation of the above foreign currencies against the Canadian dollar, assuming all other variables remain constant, there would be an equal and opposite impact on net loss.
 
 (ii)
Interest Rate Risk
 
 Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates.  During the year ended December 31, 2010, interest rate fluctuations on the Company’s credit facility have no significant impact on its net loss because the floating rate debt was repaid in full in early 2010 and the Company had no floating rate debt at December 31, 2010. In the prior year, the Company was exposed to interest rate fluctuations on its credit facility which bore a floating rate of interest.  The Company had no interest rate swaps or financial contracts in place at or during the year ended December 31, 2010, 2009 and 2008.
 
 F-32
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 19 – FINANCIAL INSTRUMENTS, RISK MANAGEMENT AND CAPITAL MANAGEMENT STRATEGY (continued)
 
 (iii)
Commodity Price Risk
 
 Commodity price risk is the risk that the fair value of financial instruments or future cash flows will fluctuate as a result of changes in commodity prices.  Commodity prices for oil and natural gas are impacted by world economic events that dictate the levels of supply and demand.  The Company has attempted to mitigate commodity price risk through the use of financial derivative sales contracts.  The Company had no risk management contracts in place at December 31, 2010.
 
 As at December 31, 2009, the Company had a natural gas derivatives contract for 600 gigajoules (“GJ”) per day for the period from November 1, 2009 to April 30, 2010. This contract consisted of a CAD$4.47 per GJ forward sale agreement.  As at December 31, 2009, the Company also had a crude oil derivatives contract for 100 barrels (“bbl”) per day for the period from September 1, 2009 to April 30, 2010. This contract consisted of a CAD$81.60 per bbl forward sale agreement. For the year ended December 31, 2010, the Company recognized in income a realized gain of $67,923 on the risk management contracts in place during the year (2009 - $315,270).
 
 As at December 31, 2008, the Company had outstanding a natural gas derivatives contract for 1,000 gigajoules (“GJ”) per day for the period from January 1, 2009 to December 31, 2009.  This contract consisted of a $6.27 CAD per GJ forward sale agreement.  During the year ended December 31, 2008, no gain was realized under this contract.  However, as at December 31, 2008, an unrealized gain of $107,768 relating to this contract was recorded in accumulated other comprehensive income.
 
 (d)
Capital Management Strategy
 
 The Company’s policy on capital management is to maintain a prudent capital structure so as to maintain financial flexibility, preserve access to capital markets, maintain investor, creditor and market confidence, and to allow the Company to fund future development.  The Company considers its capital structure to include share capital, cash and cash equivalents, bridge loan, loans from related parties, and working capital.  In order to maintain or adjust capital structure, the Company may from time to time issue shares or enter into debt agreements and adjust its capital spending to manage current and projected operating cash flows and debt levels.
  The Company’s current borrowing capacity is based on the lender’s review of the Company’s oil and gas reserves. The Company is also subject to various covenants. Compliance with these covenants is monitored on a regular basis and at December 31, 2010, the Company is in compliance with all covenants (note 7).
  The Company’s share capital is not subject to any external restrictions.The Company has not paid or declared any dividends, nor are any contemplated in the foreseeable future.  There have been no changes to the Company’s capital management strategy during the year ended December 31, 2010.
 
 NOTE 20 – SUBSEQUENT EVENTS
 
 (a)
Stock Options
 
 Subsequent to December 31, 2010, the Company granted a total of 3,562,500 incentive stock options with a weighted average exercise price at $0.35 per share to independent directors, management, officers, employees and consultants of the Company. The options can be exercised for periods ending up to March 15, 2014.
 
 (b)
Private Placement
 
 In February 2011, the Company completed a private placement of 11,010,000 units at US $0.30 per unit. Each unit consists of one common share and one-half of one common share purchase warrant. Each whole warrant entitles the holder to acquire one additional common share of the Company at US$0.35 per common share on or before February 10, 2012. Gross proceeds raised were US$3,303,000. In connection with this private placement, the Company paid finders’ fees of US$199,710 in cash.
  F-33
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 20 – SUBSEQUENT EVENTS (continued)
 
 (c)
Loan from related party
 
 Subsequent to December 31, 2010, the Company repaid the HEC loan in full in cash.
 
 (d)
Derivative Financial Instruments
 
 The Company uses commodity derivative financial instruments to manage its exposure to commodity price risk associated with the sale of its future crude oil and provide the Company with downside protection insurance on the decrease of commodity prices.
 
 As at February 23, 2011, the Company had the following put options, allowing the Company the right, but not the obligation, to sell Western Texas Instrument (“WTI”) crude oil:
 
 Crude oil Contract
Contract Month
Volume
Price per barrelWTI Crude oil put options
April 2011
6,000 barrels per month
US$93WTI Crude oil put options
May 2011
6,000 barrels per month
US$93WTI Crude oil put options
June 2011
6,000 barrels per month
US$93WTI Crude oil put options
July 2011
6,000 barrels per month
US$93
 
 (e)
Joint Venture Agreement
 
 In February 2011, the Company entered into an exploration joint venture with a NYSE listed company (“US Oilco”) related to certain of its Canadian landholdings.  Terms of the joint venture include an option payment to the Company to a maximum of $1 million tied to its achievement of specific objectives in the first quarter of 2011.
  Upon satisfactory achievement of the initial objectives, it is contemplated that the joint venture will fund land purchases of up to $5 million of any new lands, and in addition fund the drilling of two horizontal wells (combined US$9 million estimate).  US Oilco will pay 65% of the costs to earn a 50% working interest on any new lands purchased and 80% of the drilling costs to earn a 50% working interest in the current lands.  As contemplated by the agreement, the Company and US Oilco would continue to develop the project on an ongoing 50/50 basis beyond the earning period.
 
 (f)
Change of Company Name
 
 On March 9, 2011, the Company changed its name from Dejour Enterprises Ltd. to Dejour Energy Inc.
  (g)
Bridge Loan
 
 In March 2011, the lender approved to extend the due date of the loan to April 30, 2011 and the Company is in discussion with the lender for further extension.
  F-34
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 21 – DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (“GAAP”)
 
 Dejour Energy Inc. (the “Company”) consolidated financial statements have been prepared in accordance with accounting principles generally accepted in Canada (“Canadian GAAP”). The United States Securities and Exchange Commission (“SEC”) requires that financial statements of foreign companies contain a reconciliation presenting the statements on the basis of accounting principles generally accepted in the United States of America (“US GAAP”).   Any difference in accounting principles as they pertain to the accompanying consolidated financial statements are not material except as follows:
 
 (a)
Full Cost Accounting
 
 Under US GAAP, a ceiling test is applied to ensure the unamortized capitalized costs in a country-by- country cost centre do not exceed the sum, net of applicable income taxes, of the present value, discounted at 10 percent, of the estimated future net revenues calculated on the basis of estimated value of future production from proved reserves using 12 month average oil and gas prices, less estimated future development and production costs based on current costs and economic conditions, plus unimpaired unproved property costs. Unproved properties are assessed on at least an annual basis for possible impairments or reductions in value.  If a reduction in the value of unproved properties is determined, the impairment is transferred to the carrying value of proved oil and gas properties.  Depletion charges under US GAAP were calculated by reference to proved reserves estimated using an average price for the prior 12-month period.
 
 Under Canadian GAAP, a similar ceiling test calculation is performed with the exception that cash flows from proved reserves are undiscounted using forecast pricing and future development and production costs to determine whether impairment exists. The impairment amount is measured using the fair value of proved and probable reserves. Depletion charges under Canadian GAAP are also calculated by reference to proved reserves estimated using estimated future prices and costs.
 
 As a result of ceiling test differences between Canadian GAAP and US GAAP, the depletion base of unamortized capitalized costs is less for US GAAP purposes.
 
 (b)
Interest in Mineral Properties
 
 Under US GAAP, mineral exploration costs are expensed as incurred until commercially mineable deposits are determined to exist within a particular property. Under Canadian GAAP, the costs of acquiring mineral properties and related exploration and development expenditures are deferred.  As the Company has not yet determined commercially mineable deposits in regard to its uranium properties all related costs have been expensed for US GAAP purposes.   In addition, under US GAAP, these costs are classified as operating activities whereas under Canadian GAAP, the cash flows relating to unproven mineral properties are reported as investing activities.
 
 (c)
Flow-through Shares
 
 Under US GAAP, the proceeds from the issuance of flow-through shares are allocated between the offering of shares and the sale of tax benefits.  The allocation is based on the difference between the issue price of flow-through shares and the fair value of the shares at the date of issuance.  A liability is recorded for this premium difference and is reversed when the tax benefits are renounced. To the extent that the Company has available tax pools for which a full valuation allowance has been provided, the premium is recognized in operations as a reduction in the valuation allowance at the time of renunciation of the tax pools.
 
 Under Canadian GAAP, share capital is reduced and future income tax liabilities are increased by the estimated income tax benefits renounced by the Company to the subscribers on the date of the renouncement, except to the extent that the Company has unrecorded loss carry forwards and tax pools in excess of book value available for deduction against which a valuation allowance has been provided.
 
 Under US GAAP, funds raised from the issuance of flow-through shares, which have not yet been disbursed on qualifying exploration expenditures would be disclosed as restricted cash.  Under Canadian GAAP unspent flow through share proceeds are not recognized as restricted cash.
  F-35
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 21 – DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (“GAAP”) (continued)
 
 (d)
Derivative financial instruments
 
 Effective January 1, 2009, the Company adopted ASC 815-40 (formerly EITF Issue No. 07-05), “Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock” (“ASC 815-40”). ASC 815-40 clarifies the determination of whether an instrument issued by an entity (or an embedded feature in the instrument) is indexed to an entity’s own stock, which would qualify as a scope exception under SFAS 133. Based on the Company’s analysis of the ASC 815-40 criteria, the Company determined that the foreign currency denominated warrants (“US dollar warrants”) issued in connection with a private placement must be treated as derivative liabilities in the Company’s statement of financial position. Any issuance costs related to the US$ denominated warrants are expensed upon initial issuance.
 
 Prospectively, the US dollar warrants will be re-measured at each balance sheet date based on estimated fair value, and any resultant changes in fair value will be recorded as non-cash valuation adjustments as income or expense in the respective period.  Under US GAAP the costs related to the warrant liability are expensed. At the time the Company’s foreign denominated warrants are exercised, the value of the warrants will be reclassified to shareholders’ equity for US GAAP purposes.
 
 As part of the financing which closed on December 23, 2009, the Company issued 8,075,000 share purchase warrants denominated in US$, while the functional currency of the Company is CAD$.  Each of these share purchase warrants entitles the holder to purchase one common share of the Company at an exercise price of US$0.40 per common share on or before December 23, 2014. In connection with this private placement, the Company also issued 645,999 agent’s warrants, exercisable at US$0.46 per common share on or before November 3, 2014. Under Canadian GAAP, these US$ denominated warrants are accounted for as equity with related costs recognized as a reduction of equityand changes in fair value were not recognized.
 
 After the adoption of ASC 815-40, under US GAAP, these US$ denominated warrants are recorded as financial instruments and their fair value is accounted for as a liability instead of equity. The issuance costs related to the US$ denominated warrants are expensed upon initial issuance. The Company has also revalued these US$ denominated warrants on each balance sheet date and any changes in fair value are recorded in the reported net loss for each period.
 
 As of December 31, 2010, the fair value of these warrants of CAD$1,180,754 (December 31, 2009: CAD$1,248,688 and December 23, 2009: CAD$1,191,154) was estimated using the Hull-White Trinomial option pricing model under the following assumptions: expected dividend yield of 0%, expected volatility of 88%, risk-free interest rate of 1% and an expected life of 3 years.
 
 (e)
Statements of cash flows
 
 For Canadian GAAP, all cash flows relating to mineral property costs are reported as investing activities. For US GAAP, mineral property acquisition costs would be characterized as investing activities and mineral property exploration costs as operating activities.
 
 (f)
International Financial Reporting Standards (“IFRS”)
 
 Effective January 1, 2011, the Company will be preparing consolidated financial statements in accordance with IFRS and a  reconciliation to US GAAP will not be required. As a result, SAB Topic 11M, “Disclosure of the Impact that Recently Issued Accounting Standards Will Have on the Financial Statements of the Registrant When Adopted in a Future Period” was not provided for 2010.
 
 (g)
Reconciliations
 
 The effect of the differences between Canadian GAAP and US GAAP (including practices prescribed by the SEC) are summarized as below. The Company restated certain prior year comparative figures on its US GAAP Reconciliation. A summary of the restatements is described at Note (h) – Summary of Restatement, below.
  F-36
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 21 – DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (“GAAP”) (continued)
 
 (g)
Reconciliations (continued)
 
 Assets
 December 31,December 31,


2009Note

2010


(As Restated)Total assets, under Canadian GAAP



$
46,355,166


$
45,885,876Uranium properties under US GAAP

b


(472,968
)


(481,714
)Oil and gas properties under Canadian GAAP

a


19,152,670



13,974,205Oil and gas properties under US GAAP

a


(27,710,714
)


(24,209,227
)Total assets, under US GAAP



$
37,324,154


$
35,169,140
   LiabilitiesDecember 31,December 31,


2009Note 21

2010


(As Restated)Total liabilities, under Canadian GAAP



$
8,095,672


$
6,197,207Fair value of US$ denominated warrants

d


1,180,754



1,248,688Premium on flow through shares

c


187,145



271,033Total liabilities, under US GAAP



$
9,463,571


$
7,716,928
 
 Share CapitalDecember 31,December 31,


2009Note 21

2010


(As Restated)Total share capital, under Canadian GAAP



$
75,575,012


$
72,559,504Fair value of US$ denominated warrants on issuance date

d


(1,050,834
)


(1,050,834
)Flow through shares future income tax adjustment

c


5,637,883



4,669,883Premium on flow through shares

c


(864,008
)


(456,033
)Total share capital, under US GAAP



$
79,298,053


$
75,722,520
  F-37
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 21 – DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (“GAAP”) (continued)
 
 (g)
Reconciliations (continued)
 
 Deficit
 December 31,December 31,


2009Note 21

2010


(As Restated)Deficit, under Canadian GAAP



$
(44,550,624
)

$
(39,385,746
)Uranium properties impairment under Canadian GAAP

b


158,786



148,906Uranium properties expenditures and impairment under US GAAP

b


(631,754
)


(630,620
)Flow through share future tax recovery under Canadian GAAP

c


(5,637,883
)


(4,669,883
)Flow through share future tax recovery under US GAAP

c


676,863



185,000Issuance costs of US$ denominated warrants

d


(129,920
)


(197,854
)Oil and gas properties depletion and impairment under Canadian GAAP

a


19,152,670



13,974,206Oil and gas properties depletion and impairment under US GAAP

a


(27,710,714
)


(24,209,227
)Deficit, under US GAAP



$
(58,672,576
)

$
(54,785,219
)
  F-38
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 21 – DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (“GAAP”) (continued)
 
 (g)
Reconciliations (continued)
 
 Net LossFor the years ended December 31,2009Note 21

2010


(As Restated)


2008Net loss for the year, under Canadian GAAP



$
(5,164,878
)

$
(12,806,918
)

$
(20,890,753
)Uranium property expenditures

b


-



15,000



-Uranium properties impairment under Canadian GAAP

b


9,880



148,906



-Uranium properties impairment under US GAAP

b


(1,134
)


(17,602
)


-Issuance costs of US$ denominated warrants

d


-



(140,320
)


-Change in fair value of US$ denominated warrants

d


67,934



(57,534
)


-Flow through share future tax recovery under Canadian GAAP

c


(968,000
)


-



(536,900
)Flow through share future tax recovery under US GAAP

c


491,863



-



70,000Oil and gas properties depletion under Canadian GAAP

a


5,178,465



6,382,574



3,635,777Oil and gas properties impairment under Canadian GAAP

a


-



3,955,854



-Oil and gas properties depletion under US GAAP

a


(2,197,383
)


(3,628,502
)


(4,063,107
)Oil and gas properties impairment under US GAAP

a


(1,304,104
)


(4,121,713
)


(12,395,905
)Net loss for the year, under US GAAP




(3,887,357
)


(10,270,255
)


(34,180,888
)Unrealized financial instrument loss




-



(99,894
)


107,768Comprehensive loss for the year, under US GAAP



$
(3,887,357
)

$
(10,370,149
)

$
(34,073,120
)Net loss per share - Basic and Diluted



$
(0.04
)

$
(0.13
)

$
(0.47
)Weighted Average Number of Common Shares Outstanding - Basic and Diluted




99,788,625



78,926,223



72,210,852Deficit, beginning of the year, under US GAAP



$
(54,785,219
)

$
(44,514,964
)

$
(10,334,076
)Net loss under US GAAP




(3,887,357
)


(10,270,255
)


(34,180,888
)Deficit, end of the year, under US GAAP



$
(58,672,576
)

$
(54,785,219
)

$
(44,514,964
)
 
 F-39
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 21 – DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (“GAAP”) (continued)
 
 (g)
Reconciliations (continued)
 
 Cash Flows
 2009For the year ended December 31,

Note 21

2010


(As Restated)


2008Cash flows from (used in) operating activities, under Canadian GAAP



$
395,678


$
(1,166,596
)

$
(1,148,630
)Net loss for the period, under Canadian GAAP




5,164,878



12,806,918



20,890,753Net loss for the period, under US GAAP




(3,887,357
)


(10,270,255
)


(34,180,888
)Depletion and impairment under Canadian GAAP

a,b


(5,188,345
)


(10,487,334
)


(3,635,777
)Depletion and impairment under US GAAP

a,b


3,502,621



7,767,817



16,459,012Change in fair value of warrant liability

d


(67,934
)


57,534



-Differences in future income taxes expenses recovery

c


476,137



-



466,900Cash flows from (used in) operating activities, under US GAAP




395,678



(1,291,916
)


(1,148,630
)Cash flows from (used in) investing activities, under Canadian GAAP




(3,854,629
)


3,876,031



(26,245,800
)Restricted cash from flow through shares




(312,148
)


(576,792
)


-Uranium property expenditures

b


-



(15,000
)


-Cash flows from (used in) investing activities, under US GAAP




(4,166,777
)


3,284,239



(26,245,800
)Cash flows from (used in) financing activities, under Canadian GAAP




5,483,780



(720,964
)


14,627,000Shares issued for cash, net of share issue costs

c,d


-



140,320



-Cash flows from (used in) financing activities, under US GAAP




5,483,780



(580,644
)


14,627,000INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS




1,712,681



1,411,679



(12,767,430
)CASH AND CASH EQUIVALENTS, BEGINNING OF THE YEAR




2,155,904



744,225



13,511,655CASH AND CASH EQUIVALENTS, END OF THE YEAR



$
3,868,585


$
2,155,904


$
744,225
  F-40
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 21 – DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (“GAAP”) (continued)
 
 (g)
Reconciliations (continued)
 
 Condensed Consolidated Balance Sheet – US GAAP
 2010


2009Note 21

As reported


US GAAP


As reported


US GAAP(As Restated)ASSETSCurrentCash and cash equivalents



$
4,757,525


$
3,868,585


$
2,732,696


$
2,155,904Accounts receivable




688,626



688,626



724,773



724,773Prepaids and deposits




92,738



92,738



126,266



126,2665,538,889



4,649,949



3,583,735



3,006,943Restricted cash from flow through shares




-



888,940



-



576,792Deposits




442,261



442,261



429,406



429,406Equipment, net




102,765



102,765



114,747



114,747Uranium properties

b


523,205



50,237



533,085



51,371Oil and gas properties

a


39,748,046



31,190,002



41,224,903



30,989,881$
46,355,166


$
37,324,154


$
45,885,876


$
35,169,140LIABILITIESCurrentBank line of credit and bridge loan



$
4,800,000


$
4,800,000


$
850,000


$
850,000Accounts payable and accrued liabilities

c


2,472,746



2,659,891



2,653,483



2,924,516Loans from related parties




250,000



250,000



-



-Unrealized financial instrument loss




-



-



99,894



99,8947,522,746



7,709,891



3,603,377



3,874,410Derivative financial instruments

d


-



1,180,754



-



1,248,688Loans from related parties




-



-



2,345,401



2,345,401Deferred leasehold inducement




31,708



31,708



39,913



39,913Asset retirement obligations




541,218



541,218



208,516



208,5168,095,672



9,463,571



6,197,207



7,716,928SHAREHOLDERS' EQUITYShare capital

c,d


75,575,012



79,298,053



72,559,504



75,722,520Contributed surplus

a,b,c


7,235,106



7,235,106



6,614,805



6,614,805Deficit

d


(44,550,624
)


(58,672,576
)


(39,385,746
)


(54,785,219
)Accumulated other comprehensive income




-



-



(99,894
)


(99,894
)38,259,494



27,860,583



39,688,669



27,452,212$
46,355,166


$
37,324,154


$
45,885,876


$
35,169,140
 
 F-41
  DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 21 – DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (“GAAP”) (continued)
 
 (h)           Summary of Restatement
 
 (i)
Derivative Financial Instruments
 
 As part of the financing closed on December 23, 2009, the Company issued 8,075,000 share purchase warrants denominated in US$, while the functional currency of the Company is CAD$. Each of these share purchase warrants entitles the holder to purchase one common share of the Company at an exercise price of US$0.40 per common share on or before December 23, 2014. In connection with this private placement, the Company also issued 645,999 agent’s warrants, exercisable at US$0.46 per common share on or before November 3, 2014.  Under Canadian GAAP, these US$ denominated warrants are accounted for as equity with related costs recognized as a reduction of equity.
 
 Previously, these warrants were accounted for as equity. After the adoption of ASC 815-40, under US GAAP, these US$ denominated warrants, should have been recorded as financial instruments and their fair value is accounted for as a liability instead of equity.  .
 
 In accordance with ASC 815-40, CAD$1,050,834 of share capita related to the US$ denominated warrants are reclassified to derivative financial instruments and CAD$140,320 of issuance costs are expensed upon initial issuance dated December 23, 2009. The Company also revalued these US$ denominated warrants on each balance sheet date and a CAD$57,534 loss on fair value revaluation was recorded in the net loss for the period ended December 31, 2009.
  (ii)
Depletion, Impairment and Oil and Gas Properties
 
 The previously issued U.S. GAAP Reconciliation for the year ended December 31, 2009 recognized amortization, depletion and accretion under U.S. GAAP of $4,719,295 that should have been recognized as $3,628,502. Accordingly, the comparative consolidated financial statement under U.S. GAAP for the year ended December 31, 2009 includes an adjustment to decrease the cumulative amortization, depletion and accretion by $1,090,793 and increase oil and gas properties by $1,090,793 with a corresponding decrease in the net loss and deficit at the end of the year.
 
 The previously issued U.S. GAAP Reconciliation for the year ended December 31, 2009 recognized impairment of oil and gas properties under U.S. GAAP of $3,412,055 that should have been recognized as $4,121,713. Accordingly, the comparative consolidated financial statement under U.S. GAAP for the year ended December 31, 2009 includes an adjustment to increase the cumulative impairment of oil and gas properties by $709,658 and decrease oil and gas properties by $709,658 with a corresponding increase in the net loss and deficit at the end of the year.
 
 As a result of the depletion and impairment adjustments, the net book value of the Company’s oil and gas properties increased by $381,135 with a corresponding decrease in the net loss and deficit at the end of the year.
 
 Cumulative Effect of Adjustments



The cumulative effect of these adjustments on previously reported US GAAP amounts is summarized below as at and for the year ended December 31, 2009:
 
 F-42
 
 DEJOUR ENERGY INC.
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 For the Years Ended December 31, 2010, 2009 and 2008
 NOTE 21 – DIFFERENCES BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (“GAAP”) (continued)
 
 (h)
Summary of Restatement (continued)
  As PreviouslyReported


Adjustments


As Restated$


$


$Assets:Oil and gas properties(ii)


30,608,746



381,135



30,989,881Liabilities:Derivative financial instruments(i)


-



1,248,688



1,248,688Share Capital:Fair value of US$ denominated warrants on issuance date (i)


-



(1,050,834
)


(1,050,834
)Share Capital:


76,773,354



(1,050,834
)


75,722,520Net Loss for the Year:Amortization, depletion and accretion (ii)


4,719,295



(1,090,793
)


3,628,502Impairment of oil and gas properties (ii)


3,412,055



709,658



4,121,713Fair value of issuance costs of US$ denominated warrants (i)


-



140,320



140,320Change in fair value of US$ denominated warrants


-



57,534



57,534Net Loss for the Year (i)(ii)


10,453,536



(183,281
)


10,270,255Deficit - end of the year(i) (ii)


54,968,499



(183,281
)


54,785,219
 Net loss per share, basic and diluted


(0.13
)


-



(0.13
)Cash flows from (used in) operating activities (ii)Share issuance costs of US$ denominated warrants (i)


-



(140,320
)


(140,320
)Cash flows from (used in) operating activities


(1,151,596
)


(140,320
)


(1,291,916
)
 Cash flows from (used in) financing activities (ii)Share issued for cash, net of share issue costs (i)


-



140,320



140,320Cash flows from (used in) financing activities


(720,964
)


140,320



(580,644
)
 
 F-43