- Report of Foreign Issuer (6-K)

Share Name	Share Symbol	Market	Type
DXI Capital Corporation (CE)	USOTC:DXIEF	OTCMarkets	Common Stock

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 6-K

REPORT OF FOREIGN ISSUER PURSUANT TO RULE 13a-16 AND 15d-16

UNDER THE SECURITIES EXCHANGE ACT OF 1934

For the month of November 2010 File No. 001-33510

DEJOUR ENTERPRISES LTD.

(Name of Registrant)

598-999 Canada Place, Vancouver, British Columbia, Canada, V6C 3E1

(Address of principal executive offices)

Indicate by check mark whether the Registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

FORM 20-F x FORM 40-F ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1) ¨

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7) ¨

The Company hereby incorporates by reference this Form 6-K and the exhibits hereto into its registration statement on Form F-3 (File No. 333-162677) and the prospectus contained therein.

Disclosure of Recent Material Developments

On November 9, 2010, Dejour Enterprises Ltd. (hereinafter referred to as Dejour) announced that it had submitted to the British Columbia Oil and Gas Commission an application for improved recovery in the Halfway Oil Pool at the Woodrush Field, Northeast British Columbia, through the implementation of a waterflood program. Dejour has commissioned the engineering design and procurement effort for the project in anticipation of commencing water injection prior to the end of January, 2011. Due to a naturally increasing gas component, the Woodrush oil production is currently experiencing a well allowable restriction imposed by the British Columbia Oil and Gas Commission, to conserve this oil resource during waterflood implementation. This will be phased out once water injection has commenced. Dejour expects average daily gross production from Woodrush to be approximately 650 Barrels of Oil Equivalent per day for the remainder of the fourth quarter of 2010. This gross production profile is expected to increase to an estimated 850 Barrels of Oil Equivalent per day in early 2011 and continue to increase to a level of 1200 to 1400 Barrels of Oil Equivalent per day by the second half of 2011, 65% oil, a gross production level sustainable for the foreseeable future. Dejour, the operator, holds a 75% working interest in this project. Dejour expects, on a temporary basis, to experience lower sequential operating revenue and cash flow in the fourth quarter of 2010 as a result of the above. However, proceeds from disposition of a non-core property will substantially offset this impact. For fiscal year 2010, Dejour expects total revenue of C$8 Million (an 18% increase over 2009), all from the Woodrush Field. Revenue contribution to Dejour in 2011 from Woodrush current operations is estimated to increase by 50% to C$12 Million, unrisked, current pricing, as the waterflood takes hold. At this production rate the project is expected to have a reserve life of at least 6 years.

On September 15, 2010, Dejour announced that that it had closed the placement of 2,000,000 flow-through common shares at a price of C$0.375 per share with MineralFields Group, an Ontario-based institution, for a total consideration of CAD$750,000. Dejour paid a 5% fee of the proceeds in cash. . The Company further announced that it had secured a credit limit increase of C$1.5 Million for its existing loan facility with an Alberta-based lender, bringing the facility ’ s total available credit to C$5 Million.

On August 16, 2010 , Dejour filed quarterly financial statements and management discussion & analysis for the period ending June 30, 2010 and the related Form 52-109F2 Certification of Interim Filings of the Chief Executive Officer and Chief Financial Officer of Dejour . These documents are incorporated herein by reference to Exhibit 99. 1 hereto .

On May 13, 2010 , Dejour filed quarterly financial statements and management discussion & analysis for the period ending March 31, 2010 and the related Form 52-109F2 Certification of Interim Filings of the Chief Executive Officer and Chief Financial Officer of Dejour . These documents are incorporated herein by reference to Exhibit 99. 2 hereto .

On March 5, 2010 , Dejour announced that it had closed a non-brokered private placement. Gross proceeds from this flow through financing totalled C$1,017,500 corresponding to 2,907,300 units sold at $0.35. Each unit consists of one flow-through common share and half of one share purchase warrant. Each whole warrant allows the holder to purchase one non-flow-through common share at $0.45 within 12 months from closing; Dejour has the right to accelerate the expiry date of the warrants if the average closing price of a Dejour share is above $0.65 during any twenty day period, following the mandatory hold period. Insiders of Dejour purchased approximately 15% of this offering. Dejour paid finders' fees of up to 6.25% of the proceeds in cash in connection with this sale and up to 1.5% warrants on the number of units sold through the agent.

DOCUMENTS FILED

See the Exhibit Index hereto for a list of the documents filed herewith and forming a part of this Form 6-K.

SIGNATURES

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

Dejour Enterprises Ltd.
(Registrant)

Dated: November 10, 2010

By: /s/ Mathew Wong
Mathew Wong,
Chief Financial Officer

EXHIBIT INDEX

Exhibit		Description

99.1		First Quarter Interim Financial Statements and Managements Discussion and Analysis for the period ended March 31, 2010, Form 52-109f2 Certification of Interim Filings Chief Executive Officer, Form 52-109f2 Certification of Interim Filings Chief Financial Officer
99.2		Second Quarter Interim Financial Statements and Managements Discussion and Analysis for the period ended June 30, 2010, Form 52-109f2 Certification of Interim Filings Chief Executive Officer, Form 52-109f2 Certification of Interim Filings Chief Financial Officer
99.3		U.S. GAAP Reconciliation Note for the period ended June 30, 2010

Exhibit 99.1

CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

March 31, 2010

These unaudited financial statements have not been reviewed by the Company’s auditor.

DEJOUR ENTERPRISES LTD.

CONSOLIDATED BALANCE SHEETS

(Expressed in Canadian Dollars)

	March 31,			December 31,
	2010			2009
	(Unaudited)			(Audited)

ASSETS
Current
Cash and cash equivalents	$	1,336,449		$	2,732,696
Accounts receivable		882,299			724,773
Prepaids and deposits		655,115			555,672
		2,873,863			4,013,141
Equipment (Note 4)		107,521			114,747
Uranium properties (Note 5 (a))		533,085			533,085
Oil and gas properties (Note 5 (b))		42,748,109			41,224,903
	$	46,262,578		$	45,885,876

LIABILITIES
Current
Bank line of credit snd bridge loan (Note 6)	$	1,500,000		$	850,000
Accounts payable and accrued liabilities		3,337,036			2,653,483
Unrealized financial instrument loss		-			99,894
Loans from related parties (Note 7)		2,373,568			-
		7,210,604			3,603,377
Loans from related parties (Note 7)		-			2,345,401
Deferred leasehold inducement		37,861			39,913
Asset retirement obligations (Note 8)		211,892			208,516
		7,460,357			6,197,207

SHAREHOLDERS ' EQUITY
Share capital (Note 9)		73,323,780			72,559,504
Contributed surplus (Note 11)		6,779,161			6,614,805
Deficit		(41,300,720	)		(39,385,746	)
Accumulated other comprehensive income (loss)		-			(99,894	)
		38,802,221			39,688,669
	$	46,262,578		$	45,885,876

Commitments (Notes 6, 7, 8 and 14)

Subsequent Event (Note 18)

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

DEJOUR ENTERPRISES LTD.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS AND ACCUMULATED OTHER

COMPREHENSIVE INCOME (LOSS) AND DEFICIT

(Expressed in Canadian Dollars)

	Three Months			Three Months
	Ended			Ended
	March 31			March 31
	2010			2009

REVENUES
Oil and natural gas revenue	$	1,347,463		$	2,412,426
Realized financial instrument gain (loss)		(42,407	)		289,561
		1,305,056			2,701,987

EXPENSES
Royalties		220,949			526,356
Operating and transportation		842,579			998,117
Amortization, depletion and accretion		745,842			2,710,248
Interest expense and finance fee		252,446			200,008
General and administrative (Note 13)		986,916			938,379
Stock based compensation (Note 10)		164,356			209,959
		3,213,088			5,583,067

LOSS BEFORE THE FOLLOWING AND INCOME TAXES		(1,908,032	)		(2,881,080	)
Interest and other income		8,719			258,113
Loss on disposition of investment		-			(310,796	)
Equity loss from Titan		-			(142,196	)
Foreign exchange loss		(15,661	)		(152,210	)

LOSS BEFORE INCOME TAXES		(1,914,974	)		(3,228,169	)

FUTURE INCOME TAXES RECOVERY		-			779,111
NET LOSS FOR THE PERIOD		(1,914,974	)		(2,449,058	)

DEFICIT, BEGINNING OF THE PERIOD		(39,385,746	)		(26,578,828	)

DEFICIT, END OF THE PERIOD	$	(41,300,720	)	$	(29,027,886	)

NET LOSS PER SHARE - BASIC AND DILUTED	$	(0.02	)	$	(0.03	)

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC AND DILUTED		97,727,038			73,721,421

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

DEJOUR ENTERPRISES LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Expressed in Canadian Dollars)

	Three Months			Three Months
	Ended			Ended
	March 31,			March 31,
	2010			2009

CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
Net loss for the period	$	(1,914,974	)	$	(2,449,058	)
Adjustment for items not affecting cash:
Amortization, depletion and accretion		745,842			2,710,248
Equity (income) loss from Titan		-			142,196
Non-cash stock based compensation		164,356			209,959
Non-cash finance fees		28,167			-
Unrealized foreign exchange loss		-			163,674
Future income taxes expense (recovery)		-			(779,111	)
Loss on disposal of investment		-			310,796
Amortization of deferred leasehold inducement		(2,052	)		-
Changes in non-cash working capital balances (Note 12)		426,583			(204,216	)
		(552,077	)		104,488

CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
Purchase of equipment		(240	)		(4,599	)
Proceeds on disposal of investment		-			2,187,633
Resource properties expenditures		(2,258,206	)		(494,491	)
		(2,258,446	)		1,688,543

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
Bank indebtedness and line of credit		650,000			(187,450	)
Loans from related parties		-			(690,642	)
Shares issued for cash		764,276			20,248
		1,414,276			(857,844	)

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(1,396,247	)		935,187

CASH AND CASH EQUIVALENTS, BEGINNING OF THE PERIOD		2,732,696			744,225

CASH AND CASH EQUIVALENTS, END OF THE PERIOD	$	1,336,449		$	1,679,412

Supplemental Cash Flow Information – Note 12

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

NOTE 1 – NATURE OF OPERATIONS AND BASIS OF PRESENTATION

Dejour Enterprises Ltd. (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.

These consolidated financial statements are prepared in accordance with generally accepted accounting principles (“GAAP”) in Canada with respect to the preparation of interim financial statements. Accordingly, they do not include all of the information and disclosures required by the Canadian GAAP in the preparation of annual financial statements. The accounting policies used in the interim financial statements are the same as those described in the audited December 31, 2009 consolidated financial statements and the notes thereto. The interim financial statements should be read in conjunction with the Company’s audited financial statements for the year ended December 31, 2009. 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 period’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.

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 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 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.

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:

(i)

In January 2006, the CICA Accounting Standards Board (“AcSB”) adopted a strategic plan for the direction of accounting standards in Canada. As part of that plan, accounting standards in Canada for public companies will converge with International Financial Reporting Standards (“IFRS”) by the end of 2011. The transition date of January 1, 2011 will require the restatement for comparative purposes of amounts reported by the Company for the year ended December 31, 2010.

The Company is currently evaluating the impact of adopting IFRS on its consolidated financial statements. The Company is in the first phase of its transition program, which includes scoping to identify the significant accounting policy differences and their related areas of impact in terms of systems, procedures and financial statement presentation. The Company also is in the assessment phase of the design and work plan to calculate the differences between IFRS and Canadian GAAP, and the impact on its financial statements, disclosures and operations. The Company will address the design, planning, solution development and implementation of the conversion in 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)	Marketable Securities

Marketable securities are designated as available-for-sale and are measured and carried at fair market value. Market value is based on the closing price at the balance sheet date or the closing price on the last day the security traded if there were no trades at the balance sheet date. Changes in fair market value are recognized in comprehensive income.

(c)	Resource Properties

Mineral properties

The Company records its interests in mineral properties at the lower of cost or estimated recoverable value. 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.

NOTE 3 – SUMMARY OF OTHER SIGNIFICANT ACCOUNTING POLICIES (continued)

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 no amounts are presently determinable.

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.

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. 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 charge is included in the provision for depletion and depreciation and the actual restoration expenditures are charged to the accumulated provision accounts as incurred.

The Company evaluates its oil and gas assets on an annual basis using a ceiling test to determine that the costs are recoverable and do not exceed the fair value of the properties. The costs are assessed to be recoverable if the sum of the undiscounted cash flows expected from the production of proved reserves plus unproved properties exceed the carrying value of the oil and gas assets. If the carrying value of the oil and gas assets is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value exceeds the sum of the discounted cash flows expected form the production of proved and probable reserves plus unproved properties that contain no probable reserves. The cash flows are estimated using the future product prices and costs and are discounted using a risk-free rate.

NOTE 3 – SUMMARY OF OTHER SIGNIFICANT ACCOUNTING POLICIES (continued)

(d)

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 and discounted 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.

(e)	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 market values if there is other than a temporary decline in the value of the investment.

(f)	Earnings (Loss) per Share

The Company uses the treasury stock method for the computation and disclosure of 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 monthly average number of shares outstanding during the respective periods. Diluted loss per share figure is equal to that of basic loss per share since the effects of options and warrants have been excluded as they are anti-dilutive.

(g)	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.

(h)	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 market 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.

NOTE 3 – SUMMARY OF OTHER SIGNIFICANT ACCOUNTING POLICIES (continued)

(i)	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, future 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, futures 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.

(j)	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. 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, derivatives, accounts receivable, bank line of credit and bridge loan, accounts payable, and loans from related parties. Management has determined that the fair value of these financial instruments approximates their carrying values.

On adopting these standards, 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. Marketable securities are designated as available for sale which are measured at fair value. Receivables are classified under loans and receivables, which are measured at amortized cost. Accounts payable, loan from joint-venture partner, and loan from related party are classified as other financial liabilities, which are measured at amortized cost.

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, net of tax, with any ineffective portion being recognized in net income. Gains and losses are recovered from other comprehensive income and recognized in net income 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.

NOTE 3 – SUMMARY OF OTHER SIGNIFICANT ACCOUNTING POLICIES (continued)

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. 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.

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.

(i)	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 futures income tax assets and liabilities of a change in tax rates is included in income 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.

(j)	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.

(k)	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 and is 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.

(l)	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 earnings, and for revisions to the estimated future cash flows. Actual costs incurred upon settlement of the obligations are charged against the liability.

NOTE 3 – SUMMARY OF OTHER SIGNIFICANT ACCOUNTING POLICIES (continued)

(m)	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 EIC 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.

(n)	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.

(o)	Comprehensive Income

The Company follows CICA Handbook, Section 1530, Comprehensive Income. Comprehensive income 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, and gains and losses resulting from the translation of self-sustaining foreign operations, in a statement of comprehensive income.

NOTE 4 – EQUIPMENT

	March 31, 2010						December 31, 2009
			Accumulated						Accumulated
	Cost		Amortization		Net		Cost		Amortization		Net
Furniture, fixtures and
equipment	$	136,043	$	74,608	$	61,435	$	135,804	$	71,350	$	64,454
Computer equipment		85,020		68,089		16,931		85,020		66,033		18,987
Software		19,802		18,215		1,587		19,802		17,686		2,116
Leasehold improvements		32,433		4,865		27,568		32,433		3,243		29,190
	$	273,298	$	165,777	$	107,521	$	273,059	$	158,312	$	114,747

NOTE 5 – RESOURCE PROPERTIES

(a)	Uranium Properties

In 2005 and 2006, the Company acquired interests in and staked uranium exploration properties in the Athabasca Basin region of Saskatchewan, Canada and commenced exploration on certain properties. In December 2006, the Company sold a 90% interest in these properties to Titan Uranium Inc. and realized a gain on disposition of $30,177,082. The carrying value of the remaining 10% carried interest and 1% net smelter return was $533,085 as at March 31, 2010 and December 31, 2009.

(b)	Oil and Gas Properties

A continuity summary of capitalized acquisition costs and exploration expenditures in the Company’s oil and gas properties for the three months ended March 31, 2010 and year ended December 31, 2009 are as follows:

				Acquisition Costs			Exploration & Development			Impairment
	Balance Dec. 31, 2008			(Dispositions), Net			(Dispositions), Net			and write-down			Depletion and Other			Balance Dec. 31, 2009

US Oil and Gas Properties:
Colorado / Utah Projects	$	29,325,724		$	193,892		$	332,763		$	(1,403,929	)	$	-		$	28,448,450
Others		167,674			-			-			-			-			167,674
		29,493,398			193,892			332,763			(1,403,929	)		-			28,616,124

Canadian Oil and Gas Properties:
Carson Creek		1,787,878			(265	)		(1,787,613	)					-			-
Drake/Woodrush		19,015,381			(269,491	)		(2,239,573	)					-			16,506,317
Montney (Buick Creek)		977,050			(80,660	)		19,392						-			915,782
Saddle Hills		987,137			1,077			39,778						-			1,027,992
Others		7,957,349			762,790			(837,397	)		-			-			7,882,742
Asset retirement obligations		404,311			-			-			-			(154,160	)		250,151
Property depletion		(3,635,777	)		-			-			-			(6,382,574	)		(10,018,351	)
Impairment		-			-			-			(3,955,854	)		-			(3,955,854	)
		27,493,329			413,451			(4,805,413	)		(3,955,854	)		(6,536,734	)		12,608,779
	$	56,986,727		$	607,343		$	(4,472,650	)	$	(5,359,783	)	$	(6,536,734	)	$	41,224,903

NOTE 5 – RESOURCE PROPERTIES (continued)

								Impairment
	Balance Dec. 31, 2009			Acquisition Costs, Net		Exploration & Development, Net		and write-down		Depletion and Other			Balance Mar. 31, 2010

US Oil and Gas Properties:
Colorado / Utah Projects	$	28,448,450		$	60,533	$	85,760	$	-	$	-		$	28,594,743
Others		167,674			-		-		-		-			167,674
		28,616,124			60,533		85,760		-		-			28,762,417

Canadian Oil and Gas Properties:
Drake/Woodrush		16,506,317			3,035		2,095,159		-		-			18,604,511
Montney (Buick Creek)		915,782			-		7,770		-		-			923,552
Saddle Hills		1,027,992			-		781		-		-			1,028,773
Others		7,882,742			1,971		3,198		-		-			7,887,911
Asset retirement obligations		250,151			-		-		-		-			250,151
Property depletion		(10,018,351	)		-		-		-		(735,001	)		(10,753,352	)
Impairment		(3,955,854	)		-		-		-		-			(3,955,854	)
		12,608,779			5,006		2,106,908		-		(735,001	)		13,985,692
	$	41,224,903		$	65,539	$	2,192,668	$	-	$	(735,001	)	$	42,748,109

NOTE 6 – BANK LINE OF CREDIT AND BRIDGE LOAN

In August 2008, DEAL secured a revolving operating loan facility with a Canadian Bank for up to $7,000,000, subject to certain production targets. This facility, secured by DEAL’s oil and gas assets in Canada, was at an interest rate of Canadian prime plus 1%. In accordance with the terms of the facility, DEAL is 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.

In 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, DEAL was in compliance with the working capital ratio requirement and $850,000 of this facility was utilized. 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. As at December 31, 2009, $850,000 of this facility was utilized. On March 22, 2010, the bank line of credit was paid off in full.

On March 22, 2010, the Company negotiated a credit facility for a bridge loan of up to $5,000,000. This facility is secured by DEAL’s oil and gas assets in Canada. The first $2,000,000 of the facility was used to refinance the Company’s existing bank facility and fund working capital. The remainder of the facility is accessible subject to additional lender review. The facility carries interest rate at 12% per annum, subject to a 1% fee on any amount drawn and a 2% fee on repayment. The Company paid a $50,000 commitment fee. As at March 31, 2010, $1,500,000 of this facility was utilized. The bridge loan is due on September 22, 2010 and can be extended for a period of 2 months.

NOTE 7 – 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 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 (refer to note 6), 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 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 March 31, 2010 and December 31, 2009, a balance of $387,927 remained outstanding.

NOTE 7 – LOANS FROM RELATED PARTIES (continued)

(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.

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. The grant date fair value of the warrants of $169,000 has been recorded in contributed surplus and will be amortized as a finance fee over the life of the note.

12% promissory note	$	2,070,140
Non-cash finance fee		(169,000	)
Accumulated amortization of non-cash finance fees		56,334
Balance as at December 31, 2009		1,957,474
Accumulated amortization of non-cash finance fees		28,167
Balance as at March 31, 2010	$	1,985,641

NOTE 8 – 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 March 31, 2010 to be $482,884. These obligations are expected to be settled by 2029. A credit adjusted risk-free rate of 5% and an inflation rate of 2% was used to calculate the present value of the asset retirement obligations.

Balance at December 31, 2008	$	363,109
Change in estimate		(154,160	)
Accretion expense		12,863
Actual costs incurred		(13,296	)

Balance at December 31, 2009		208,516
Accretion expense		3,376

Balance at March 31, 2010	$	211,892

NOTE 9 – SHARE CAPITAL

Authorized:	Unlimited common shares, no par value
	Unlimited first preferred shares, issuable in series
	Unlimited second preferred shares, issuable in series

	Common
	Shares		Value

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 7)		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		-		147,222

Balance at December 31, 2009		95,791,038		72,559,504

- General share issuance costs		-		(146,005	)
- For cash by private placement, net of share issuance costs		2,907,334		910,281

Balance at March 31, 2010		98,698,372	$	73,323,780

During the three months ended March 31, 2010, the Company completed the following:

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 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 $1,017,567. In connection with this private placement, the Company paid finders’ fees of $54,575 and other related costs of $52,711. The Company also issued 37,423 agent’s warrants, exercisable at $0.45 per share on or before March 3, 2011. The grant date fair values of the warrants and agent’s warrants, estimated to be $47,971 and $1,235 respectively, have been included in share capital on a net basis and accordingly have not been recorded as a separate component of shareholders’ equity.

During the year ended December 31, 2009:

In October 2009, the Company completed a private placement and issued 2,710,332 flow-through shares (“FTS”) at $0.60 per 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.

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 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 $140,790. The Company 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.

NOTE 10 – STOCK OPTIONS AND SHARE PURCHASE WARRANTS

During the three months ended March 31, 2010, the Company granted 3,053,000 (2009 – 1,223,000) options to its officers, directors, consultants, employees and advisors. In addition, 100,000 (2009 – 2,659,750) options were cancelled or expired with a weighted average exercise price of $0.45 (2009 - $1.74).

As at March 31, 2010, there were 7,369,682 options outstanding with a weighted average exercise price of $0.41, of which 1,969,682 were vested. The vested options can be exercised for periods ending up to February 15, 2015 to purchase common shares of the Company at prices ranging from $0.35 to $0.55 per 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 three months ended March 31, 2010 was determined to be $632,160 (2009 - $352,610). 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 4.87 years (2009 – 3.94 years), risk-free interest rate of 2.39% (2009 – 1.66%) and expected volatility of 86.13% (2009 – 100.52%).

During the three months ended March 31, 2010, the Company recognized a total of $164,356 (2009 - $209,959) of stock based compensation relating to the vesting of options.

As at March 31, 2010, there were 5,400,000 unvested options included in the balance of the outstanding options. As of March 31, 2010, there was $1,310,740 of total unrecognized compensation cost related to non-vested stock options. That cost is expected to be recognized over a weighted average period of 4.21 years. The following table summarizes information about stock option transactions:

	Outstanding Options			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life
Balance, December 31, 2008		7,198,380		$	1.22	2.94 years
Options granted		3,312,000			0.46
Options exercised		(631,856	)		0.43
Options cancelled and expired		(5,461,842	)		1.46

Balance, December 31, 2009		4,416,682			0.45	3.54 years
Options granted		3,053,000			0.35
Options exercised		-			-
Options cancelled and expired		(100,000	)		0.45

Balance, March 31, 2010		7,369,682		$	0.41	3.88 years

NOTE 10 – STOCK OPTIONS AND SHARE PURCHASE WARRANTS (continued)

Details of stock options vested and exercisable as at March 31, 2010 are as follows:

Number of Options Outstanding and vested	Exercise Price		Weighted Average Remaining Contractual Life (Years)
1,352,375	$	0.45		2.84
120,000	$	0.50		0.75
78,182	$	0.55		0.75
419,125	$	0.35		4.36

1,969,682	$	0.44		2.95

The following table summarizes information about warrant transactions:

	Outstanding Warrants			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life
Balance, December 31, 2008		2,104,129		$	3.35	0.40 years
Warrants issued		14,736,150			0.47
Warrants expired		(2,104,129	)		3.35

Balance, December 31, 2009		14,736,150			0.47	4.36 years
Warrants issued		1,491,090			0.45

Balance, March 31, 2010		16,227,240		$	0.47	3.82 years

Details of warrants outstanding as at March 31, 2010 are as follows:

Number of Warrants Outstanding	Exercise Price		Weighted Average Remaining Contractual Life (Years)
2,000,000	$	0.50		1.23
4,015,151	$	0.55		4.23
8,075,000	US$	0.40		4.73
645,999	US$	0.46		4.60
1,491,090	$	0.45		0.92

16,227,240

NOTE 11 – CONTRIBUTED SURPLUS

Details of changes in the Company's contributed surplus balance are as follows:

Balance at December 31, 2008	$	5,895,560
Stock compensation on vesting of options		697,467
Value of conversion feature on convertible debenture		(147,222	)
Allocated to share capital on exercise of options		169,000

Balance at December 31, 2009		6,614,805
Stock compensation on vesting of options		164,356

Balance at March 31, 2010	$	6,779,161

NOTE 12 – SUPPLEMENTAL CASH FLOW INFORMATION

	March 31,			March 31,
	2010			2009
Changes in non-cash working capital balances:
Accounts receivable	$	(157,526	)	$	(478,857	)
Prepaids and deposits		(99,443	)		(37,146	)
Accounts payable and accrued liabilities		683,552			311,787
	$	426,583		$	(204,216	)

Other cash flow information:
Cash paid for interest	$	224,279		$	200,008
Cash paid for income taxes		-			-
	$	224,279		$	200,008

Components of cash and cash equivalents
Cash	$	1,185,242		$	179,412
Guaranteed investment certificates		151,207			1,500,000
	$	1,336,449		$	1,679,412

NOTE 13 – RELATED PARTY TRANSACTIONS

During the three months ended March 31, 2010 and 2009, the Company entered into the following transactions with related parties:

(a)	The Company incurred a total of $108,123 (2009 - $108,337) in consulting and professional fees and a total of $Nil (2009 - $34,506) in rent expenses to companies controlled by officers of the Company.

(b)	The Company incurred a total of $63,559 (2009 - $128,294) in interest expense and finance fee to related parties.

(c)	The Company received total rental income of $7,500 (2009 - $7,500) from companies controlled by officers of the Company.

(d)	The Company received total consulting fee income of $Nil (2009 - $57,100) from a related party which owns more than 10% of the Company’s outstanding common shares.

These transactions are in the normal course of operations and are measured at the exchange amount established and agreed to by the related parties.

NOTE 14 – COMMITMENT

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:

2010	$	117,673
2011		73,051
2012		73,051
2013		73,051
2014		48,701
	$	385,527

NOTE 15 – SEGMENTED DISCLOSURE

As at March 31, 2010 and December 31, 2009, the Company’s significant assets, losses and revenue by geographic location were as follows:

	March 31,			December 31,
	2010			2009
Canada
Revenue	$	1,305,056		$	6,785,995
Interest and other income		8,719			302,824
Future income tax recovery		-			1,133,140
Segmented loss		(1,671,220	)		(10,969,741	)
Assets:
Current Assets		2,633,777			3,646,770
Equipment, net		80,168			85,664
Uranium properties		533,085			533,085
Oil and gas properties, net		13,985,692			12,608,779
		17,232,722			16,874,298
U.S.A.
Revenue		-			-
Interest and other income		-			114,200
Segmented loss		(243,754	)		(1,837,177	)
Assets:
Current Assets		240,086			366,372
Equipment, net		27,353			29,083
Oil and gas properties, net		28,762,417			28,616,124
		29,029,856			29,011,578
Total assets	$	46,262,578		$	45,885,876

NOTE 16 – 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.

NOTE 17 – FINANCIAL INSTRUMENTS, RISK MANAGEMENT AND CAPITAL MANAGEMENT STRATEGY

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.

(a)	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 revolving reserve based credit facility (refer to Note 6). The Company also attempts to match its payment cycle with collection of oil and natural gas revenues on the 25 th of each month.

Accounts payable are considered due to suppliers in one year or less while the bank line of credit, which is subject to renewal after a 364-day revolving period, could be potentially due within the next year if the facility is not renewed for a further 364-day period.

(b)	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.

NOTE 17 – FINANCIAL INSTRUMENTS, RISK MANAGEMENT AND CAPITAL MANAGEMENT STRATEGY (continued)

(c)	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 three months ended March 31, 2010.

The Company was exposed to the following foreign currency risk at March 31, 2010:

Expressed in foreign currencies – March 31, 2010	USD
Cash and cash equivalents	$	185,492
Accounts receivable		76,079
Accounts payable and accrued liabilities		(120,949	)
Balance sheet exposure	$	140,622

The following foreign exchange rates applied for the three months ended and as at March 31, 2010:

Year to date average US dollar to Canadian dollar			1.0409
March 31, reporting date rate			1.0158

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 following currencies against the Canadian dollar would result in the decrease of net loss of $14,284 at March 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.

(d)	Interest Rate Risk

Interest rate risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate as a result of changes in market interest rates. Financial instruments that potentially subject the Company to interest rate risk include cash and cash equivalents and bank line of credit. Presently, the Company is exposed to interest rate cash flow risk as it holds cash and cash equivalents with variable interest rates. A change in market interest rates on the average balance of interest-bearing cash and cash equivalents will impact net loss during the period. Based on the average balance of interest-bearing cash and cash equivalents during the three months ended March 31, 2010, an increase or decrease of 25 basis points in interest rates, with all other variables held constant, would not have a significant impact on net loss. The Company is not exposed to any interest rate fluctuations on its credit facility because it bears a fixed rate of interest. The Company had no interest rate swaps or financial contracts in place at or during the three months ended March 31, 2010.

NOTE 17 – FINANCIAL INSTRUMENTS, RISK MANAGEMENT AND CAPITAL MANAGEMENT STRATEGY (continued)

(e)	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. As at December 31, 2009, the Company had outstanding 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 outstanding 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. In March 2010, the Company unwound both the natural gas hedge and the crude oil hedge, resulting in a total realized loss of $42,407. There were no derivative contracts outstanding as at March 31, 2010.

(f)	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 and line of credit, loan from joint-venture partner, loan from related party, 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 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 three months ended March 31, 2010.

NOTE 18 – SUBSEQUENT EVENT

(a)	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 May 7, 2010, 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 barrel
WTI Crude oil put options	August 2010	10,000 barrels per month	US$ 75
WTI Crude oil put options	September 2010	10,000 barrels per month	US$ 75

MANAGEMENT DISCUSSION AND ANALYSIS

For the Three Months Ended March 31, 2010

Date of Report: May 11, 2010

The following is a discussion of the consolidated operating results and financial position of Dejour Enterprises Ltd. (the “Company” or “Dejour”), including all its wholly-owned subsidiaries. It should be read in conjunction with the Company’s audited consolidated financial statements and notes for the year ended December 31, 2009 and the interim unaudited consolidated financial statements for the three months ended March 31, 2010.

All financial information in this Management’s Discussion and Analysis (“MD&A”) is expressed and prepared in accordance with the Canadian generally accepted accounting principles. All references are in Canadian dollars, the Company’s reporting currency, unless otherwise noted. Some numbers in this MD&A have been rounded to the nearest thousand for discussion purposes.

Certain forward-looking statements are discussed in this MD&A with respect to the Company’s 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 Advisory section located at the end of this document, which provides information on Non-GAAP Measures, BOE Presentation and Forward-Looking Statements.

DEJOUR STRATEGY AND BUSINESS ENVIRONMENT

Dejour emerged from 2009 a much stronger Company than it entered. The contraction in the global financial markets and falling commodity prices witnessed in late 2008 and early 2009 created a profound shift in the business environment. This shift, coupled with the royalty regime changes in the Province of Alberta caused the Company to make changes in its business strategy and expectations for near term growth. As 2009 progressed, the Company eliminated all non essential expenses, sold some non strategic assets in Canada and raised equity in an adverse market. These activities were all undertaken to protect the value of the Company’s core assets and allow the Company to proceed with its business plan as commodity prices strengthen.

As 2010 begins, oil prices have stabilized around US$80/barrel and many in the industry are seeing signs that the gas market is returning to a supply demand balance. The Company now believes that this is the time to move forward on the development of our key Piceance Basin acreage. Under moderate commodity prices forecasts of US$80/barrel for oil and US$6/Million BTU’s for natural gas, we believe that our major projects are sufficiently robust to attract competitive financing, allowing us to undertake important investments in the growth of the Company in 2010 and 2011 without significant dilution of the value of the projects.

As we move into 2010, we are witnessing a return to a much more favorable growth environment, perhaps best illustrated by the increase in the Company’s Net Proved and Probable Reserves which climbed from approximately 6 BCFE as at December 31, 2008 to over 217 BCFE as at December 31, 2009. A reserve and value increase for the Company resulting directly from the actions taken to preserve the company core assets in 2009.

In 2010, we anticipate an improving business environment and improving conditions in the financial markets for the Company and its projects. Company growth over the next one to two years will come from exploiting development opportunities at Drake/Woodrush property and from the development of low risk, high value resource plays identified in the Montney in northwestern British Columbia and in select Piceance Basin properties.

The Company's business objective remains the economic development of key projects and growth opportunities, resulting in the enhancement of shareholder value. This will be accomplished through prudent investment in and management of the Company’s portfolio of producing and non producing assets, combined with a limited program of strategic acquisitions and divestitures in our core operating areas.

COMPANY OVERVIEW

The Company’s shares trade on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange AMEX (“NYSE-AMEX”) under the symbol “DEJ”. The Company ceased to trade on the TSX Venture Exchange (“TSX-V”) and graduated to the TSX effective November 20, 2008.

The Company is in the business of acquiring, exploring and developing energy projects with a focus on oil and gas exploration in Canada and the United States. The Company holds approximately 129,000 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 Q2 2008, the Company commenced production and started receiving revenue from its Peace River Arch oil & gas properties, realizing the shift from a pure play exploration company to an exploration and production company.

Q1 2010 HIGHLIGHTS

During the three months ended March 31, 2010, the Company continued its focus on the operational efficiency and asset and debt restructure while maintaining all prospective acreage holdings and positioning for renewed drilling activities as both the business environment and commodity prices improved.

During the current quarter, the Company achieved the following major corporate objectives and also made significant progress on key strategic initiatives that resulted in:

In March, we successfully drilled, completed and tested two additional wells in the Woodrush area, providing the Company with the expectation of positive operating cash flow to be generated in the 2 nd quarter of 2010. The first well was productive in the Gething formation and tested at a rate in excess of 900 MCFD (675 MCFD net to Dejour) of natural gas. The second well was productive in the Halfway formation and tested at a rate in excess of 500 BOPD (375 BOPD net to Dejour) of oil. These two wells will be tied into production in the 2 nd quarter of 2010.

2.	Obtained a credit facility of up to $5 million, allowing the Company to refinance its existing bank facility and funds its working capital.

3.	Raised $1 million in equity under challenging market conditions, allowing the Company to execute its drilling program in the quarter.

OIL AND GAS EXPLORATION AND PRODUCTION

Over the 2008 and 2009 time frame the Company has evolved its 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, the Company’s 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.

US Activities

Gibson Gulch

The Company has moved forward aggressively to begin the process of bringing this low risk development project into production. Dejour’s has 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. The Williams Companies, Inc. (NYSE: WMB) and Bill Barrett Corporation (NYSE: BBG) are developing and producing on adjacent acreage to the east, west and north of the Company’s acreage. An independent reserve evaluator, Gustavson Associates, assigned 90 BCF in proven undeveloped reserves to Dejour’s net acreage at Gibson Gulch as of December 31, 2009.

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 mid 2011 with production to begin later in that year. During Q1 2010, the Company was 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 Dejour and its partner to drill up to 220 wells (158 wells net to Dejour) from a few multi-well drilling pads to optimally exploit the gas reserves in the subsurface.

South Rangely

Over 2009, Dejour developed a plan for evaluation and subsequent exploitation of an oil prospect at South Rangely. During 2010, the Company 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 the Company to revisit plans to evaluate and potentially exploit a 22,000 acre tract at the Company’s North Rangely. 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 Dejour control with Dejour currently holding a 72% working interest of 22,000 acres in North Rangely.

Roan Creek

South and west of Gibson Gulch, Dejour owns 72% of the 1400+ acre Roan Creek evaluation project. This gas prone opportunity is located very close to and sandwiched between existing Williams Fork gas fields operated by Occidental and Chevron. While it is likely that the pay in the Williams Fork at Roan Creek will be somewhat thinner than is found to the east, Roan Creek has potential for pay in the Mancos/Niobrara interval that can be tested via an exploratory tail to a Williams Fork appraisal well. During 2009, the various geologic and commercial studies conducted by the Company highlighted the potential at Roan Creek which provided the driving force for a single well drilling program to be conducted in late 2010 or early 2011. Success at Roan Creek is expected to make some 3,000+ additional acres currently held by the Company prospective.

Future Exploration and Evaluation

Dejour retains a substantial amount of acreage prospective for oil and gas exploitation in other sections of the Piceance and Uinta basins. Dejour’s 109,400 net acre position was sculpted over the 2006-2008 period. Dejour is operator of approximately 130,000 acres and is 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, Dejour has high graded three future development and appraisal projects including:

Plateau - This 7,300 acre (gross) project located south of Roan Creek in the Piceance Basin has Williams Fork potential as evidenced by successful drilling by EnCana Corporation at acreage adjacent to the Company’s holdings.

Greentown - This 15,000 acre (gross) prospect in the Uinta Basin in eastern Utah has oil potential as evidenced by drilling success encountered by Delta Petroleum in 2008. This area remains technically challenging due to issues associated with salt layers overlaying the target zone.

These potential developments will continue to be matured over 2010 with exploration or evaluation drilling scheduled for 2011/2012. Exploitation of these opportunities will in all likelihood proceed only after developments at Gibson Gulch, South Rangely and Roan Creek reach equilibrium stage.

Prospective acreage is located throughout the remainder of Dejour’s land holdings. These positions, which were identified during studies conducted during 2008 and 2009, will be high graded over the years of 2010 to 2012 so that exploration and appraisal drilling programs can be developed for the middle part of the decade. If during further studies, certain acreage is deemed to have potential, it is possible for that acreage to leap the queue and assume a higher priority status than it currently enjoys.

Summary of Capitalized US Oil and Gas Expenditures

A continuity summary of capitalized acquisition costs, exploration expenditures in the Company’s US oil and gas properties for the three months ended March 31, 2010 are as follows:

	December 31,		March 31,
	2009		2010
	Net Book Value		Net Expenditures		Write-off		Net Book Value
US Oil and Gas Properties

Colorado/Utah Projects
Acquisition and lease rental	$	28,115,687	$	60,533	$	-	$	28,176,220
Geological and geophysical		19,186		4,684		-		23,870
Capitalized general and administrative		313,577		81,076		-		394,653
		28,448,450		146,293		-		28,594,743

Others
Acquisition		167,674		-		-		167,674
		167,674		-		-		167,674

Total US Oil and Gas Properties	$	28,616,124	$	146,293	$	-	$	28,762,417

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.

In 2009, production from Dejour operated wells averaged about 456 BOE/D (202 BOPD of oil and natural gas liquids and 1,524 MCFD of gas). At December 31, 2009, gas production was limited due to restrictions imposed by a third party providing compression services. December 2009 production averaged 277 BOE/D (122 BOPD of oil and 930 MCFD of gas). In March 2010, the Company installed gas compression facilities which increased gas production capacity and lowered compression costs. By mid-March 2010, Dejour’s net 75% production had climbed to 465 BOE/D (120 BOPD and 2,100 MCFD). In the second half of March, DEAL drilled, completed and tested two additional wells at Woodrush. The first well was productive in the Gething formation and tested at a rate in excess of gross 900 MCFD (net 675 MCFD) of natural gas. The second well was productive in the Halfway formation and tested at a rate in excess of gross 500 BOPD (net 375 BOPD) of oil. These wells will be tied into production in the 2 nd quarter of 2010.

As at March 31, 2010, DEAL’s holdings totaled 20,247 net acres concentrated in the Peace River Arch and the Montney shale basin.

Production and Development Projects

Woodrush/Drake

After completing a comprehensive study of the Woodrush/Drake area in 2009, Dejour determined that the area presented room for value increase. Based on the recommendations of that study, the Company implemented a five point program that included:

Operating cost reduction

Production increase from existing wells

Acquisition of additional prospective acreage

Seismic data acquisition and analysis

Step-out drilling from existing production based on seismic data.

During the second half of 2009, DEAL made personnel and field management changes to reduce costs. Key to this program was the installation of a more cost effective gas compression system. Production from wells were temporarily shut in due to low gas prices and returned to service when commodity prices improved.

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, the Company 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 the Company’s outstanding bank line of credit. DEAL’s working interest in Woodrush/Drake was 75% as at March 31, 2010.

Buick Creek (Montney Shale Basin)

DEAL acquired 6,352 gross and net acres in the emerging Montney natural gas resource play in northeastern British Columbia during 2008. In early 2009, the Company also acquired an existing wellbore which the Company believes can be used for re-entry and testing of the play.

Saddle Hills

DEAL maintains a 25% working interest in 5,000 acres with two capped gas wells in the Saddle Hills area. The two wells are operated by Zargon Energy Trust, one of the Company’s joint-venture partners. The recent announcement by the Alberta government on the lowering of oil and gas royalties will change the economics of the wells. We are waiting for details of the new royalty regime and will then discuss future development plan with Zargon.

Summary of Capitalized Canadian Oil and Gas Expenditures

A continuity summary of capitalized acquisition costs, exploration expenditures in the Company’s Canadian oil and gas properties for the three months ended March 31, 2010 is as follows:

	December 31,			March 31,
	2009			2010
	Net Book Value			Expenditures (Dispositions), Net		Write-off / Depletion			Net Book Value
Canadian Oil and Gas Properties

Drake/Woodrush
Land acquisition and retention	$	386,110		$	3,035	$	-		$	389,145
Drilling and completion		5,283,495			1,104,430		-			6,387,925
Equipping and facilities		10,114,948			361,802		-			10,476,750
Geological and geophysical		454,956			614,495		-			1,069,451
Capitalized general and administrative		266,808			14,432		-			281,240
		16,506,317			2,098,194		-			18,604,511

Buick Creek (Montney)
Land acquisition and retention		827,073			-		-			827,073
Capitalized interest		80,236			-		-			80,236
Capitalized general and administrative		8,473			7,770					16,243
		915,782			7,770		-			923,552

Saddle Hills
Land acquisition and retention		4,948			-		-			4,948
Drilling and completion		887,902			478		-			888,380
Equipping and facilities		54,571			303		-			54,874
Geological and geophysical		78,407			-		-			78,407
Capitalized general and administrative		2,164			-					2,164
		1,027,992			781		-			1,028,773

Others
Land acquisition and retention		1,623,177			1,971		-			1,625,148
Drilling and completion		4,420,145			3,198		-			4,423,343
Equipping and facilities		484,095			-		-			484,095
Geological and geophysical		952,530			-		-			952,530
Capitalized general and administrative		402,795			-		-			402,795
		7,882,742			5,169		-			7,887,911

Corporate Costs
Assets retirement obligation		250,151			-		-			250,151
Depletion		(10,018,351	)		-		(735,001	)		(10,753,352	)
Impairment		(3,955,854	)		-		-			(3,955,854	)
		(13,724,054	)		-		(735,001	)		(14,459,055	)

Total Canadian Oil and Gas Properties	$	12,608,779		$	2,111,914	$	(735,001	)	$	13,985,692

The following table summarizes the breakdown of capital expenditures net of dispositions by type for the three months ended March 31, 2010 and 2009:

	Three Months		Three Months
	Ended		Ended
	March 31		March 31
	2010		2009

Land acquisition and retention	$	65,539	$	140,973
Drilling and completion		1,108,106		155,944
Equipping and facilities		362,105		99,731
Geological and geophysical		619,179		16,132
Capitalized general and administrative		103,278		176,435
	$	2,258,207	$	589,215

Daily Production

	March 31,		March 31,
	2010		2009
By Product
Natural gas (mcf/d)		1,073		2,362
Natural gas liquids (bbls/d)		7		8
Oil (bbls/d)		131		360
Total (boe/d)		317		762

The production for the three months ended March 31, 2010 (“Q1 2010”) averaged 317 BOE/D, a decrease of 58% compared to the three months ended March 31, 2009 (“Q1 2009”). The decrease in production was the result of disposition of 100% interest in the Carson Creek area and 25% interest in the Woodrush/Drake properties in 2009. In addition, one gas well was shut in during the installation of a new compressor in the first half of Q1 2010. By mid-March, substantially all of the curtailed production was brought back on line and production rate had increased to 465 BOE/D (120 BOPD and 2,100 MCFD). As the two new wells will be tied into production in the 2 nd quarter of 2010, we expect the production rate will increase accordingly.

URANIUM EXPLORATION PROJECTS

As at March 31, 2010, the Company maintained a 10% carried interest and 1% Net Smelter Return on approximately 578,365 acres of uranium exploration claims and leases. During Q1 2010, there was no expiration of claims or leases. The carrying value of the Company’s 10% carried interest and 1% Net Smelter Return was $533,085 as at March 31, 2010 and December 31, 2009.

SHARE CAPITAL

The following is a summary of share transactions for the three months ended March 31, 2010 and for the year ended December 31, 2009:

Authorized:	Unlimited common shares
	Unlimited first preferred shares, issuable in series
	Unlimited second preferred shares, issuable in series

	Common
	Shares		Value
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		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		-		147,222

Balance at December 31, 2009		95,791,038	$	72,559,504

- Share issuance costs related to prior share offerings		-		(146,005	)
- For cash by private placement, net of share issuance costs		2,907,334		910,281

Balance at March 31, 2010		98,698,372	$	73,323,780

As at May 11, 2010, the Company had 98,698,372 issued and outstanding common shares.

STOCK OPTIONS AND SHARE PURCHASE WARRANTS

The following table summarizes information about stock option transactions:

	Outstanding Options			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life

Balance, December 31, 2008		7,198,380		$	1.22	2.94 years
Options granted		3,312,000			0.46
Options exercised		(631,856	)		0.43
Options cancelled and expired		(5,461,842	)		1.46

Balance, December 31, 2009		4,416,682			0.45	3.54 years
Options granted		3,053,000			0.35
Options exercised		-			-
Options cancelled and expired		(100,000	)		0.45

Balance, March 31, 2010		7,369,682		$	0.41	3.88 years

Details of stock options vested and exercisable as at March 31, 2010 are as follows:

Number of Options Outstanding and vested		Exercise Price		Weighted Average Remaining Contractual Life (Years)
	1,352,375	$	0.45		2.84
	120,000	$	0.50		0.75
	78,182	$	0.55		0.75
	419,125	$	0.35		4.36

	1,969,682	$	0.44		2.95

As at March 31, 2010, 419,125 outstanding and vested options were “in the money” (the exercise price was less than the market trading price). If these options were fully exercised, the Company would realize approximately $147,000 in additional capital.

STOCK OPTIONS AND SHARE PURCHASE WARRANTS (continued)

The following table summarizes information about share purchase warrants:

	Outstanding Warrants			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life

Balance, December 31, 2008		2,104,129		$	3.35	0.40 years
Warrants issued		14,736,150			0.47
Warrants expired		(2,104,129	)		3.35

Balance, December 31, 2009		14,736,150			0.47	4.36 years
Warrants issued		1,491,090			0.45

Balance, March 31, 2010		16,227,240		$	0.47	3.82 years

Details of warrants outstanding as at March 31, 2010 are as follows:

Number of Warrants Outstanding		Exercise Price		Weighted Average Remaining Contractual Life (Years)
	2,000,000	$	0.50		1.23
	4,015,151	$	0.55		4.23
	8,075,000	US$	0.40		4.73
	645,999	US$	0.46		4.60
	1,491,090	$	0.45		0.92

	16,227,240

RELATED PARTY TRANSACTIONS

During the three months ended March 31, 2010 and 2009, the Company entered into the following transactions with related parties:

(e)	The Company incurred a total of $108,123 (2009 - $108,337) in consulting and professional fees and a total of $Nil (2009 - $34,506) in rent expenses to the companies controlled by officers of the Company.

(f)	The Company incurred a total of $63,559 (2009 - $128,294) in interest expense and finance fee to related parties.

(g)	The Company received total rental income of $7,500 (2009 - $7,500) from companies controlled by officers of the Company.

(h)	The Company received total consulting fee income of $Nil (2009 - $57,100) from a related party which owns more than 10% of the Company’s outstanding common shares.

These transactions are in the normal course of operations and are measured at the exchange amount established and agreed to by the related parties.

RESULTS OF OPERATIONS – THREE MONTHS ENDED MARCH 31, 2010 AND 2009

Summary of Operational Highlights

DEAL Production and Netback Summary
	Three Months Ended March 31,
	2010		2009
Production Volumes:
Oil (bbls)		11,814		32,400
Gas (mcf)		96,608		212,600
Natural gas liquids (bbls)		621		726
Total (BOE)		28,536		68,559

Average Price Received:
Oil ($/bbls)		71.60		42.04
Gas ($/mcf)		5.04		4.79
Natural gas liquids ($/bbls)		23.58		43.21
Total ($/BOE)		47.22		35.19

Royalties ($/BOE)		7.74		7.68

Operating Expenses – compressor installation ($/BOE)		7.71		-
Other Operating Expenses ($/BOE)		21.82		14.56
Total Operating Expenses ($/BOE)		29.53		14.56

Netbacks ($/BOE)		9.95		12.95

Revenues

	Three Months			Three Months
	Ended			Ended
	March 31			March 31
	2009			2009
Revenue
Natural gas	$	486,983		$	1,018,820
Oil		845,841			1,362,217
Natural gas liquids		14,639			31,389
Total oil and gas revenue		1,347,463			2,412,426
Realized financial instrument gain		(42,407	)		289,561
Total revenue	$	1,305,056		$	2,701,987

For Q1 2010, the Company recorded $860,000 in crude oil and natural gas liquids sales and $487,000 in natural gas sales as compared to $1,394,000 in crude oil and natural gas liquids sales and $1,019,000 in natural gas sales for Q1 2009. The decrease was mainly the result of disposition of 100% interest in the Carson Creek area and 25% interest in the Woodrush/Drake properties in 2009. In addition, one gas well was shut in during the installation of a new compressor in the first half of Q1 2010. By mid-March, substantially all of the curtailed production was brought back on line and production rate had increased to 465 BOE/D (120 BOPD and 2,100 MCFD). As the two new wells will be tied into production in the 2 nd quarter of 2010, we expect the production rate will increase accordingly.

The following table summarizes the commodity prices realized by the Company and the crude oil and natural gas benchmark prices for the three months ended March 31, 2010 and March 31, 2009:

	Three Months		Three Months
	Ended		Ended
	March 31		March 31
	2010		2009
Dejour Average Prices
Natural gas ($/mcf)	$	5.04	$	4.79
Oil ($/bbl)		71.60		42.04
Total average price ($/boe)	$	47.22	$	35.19

Benchmark Pricing
Western Canadian Select (WCS) ($/bbl)	$	72.53	$	49.66
Natural gas - AECO-C Spot ($ per mcf)	$	5.36	$	4.92

Both the average natural gas sales prices and AECO-C daily spot prices for Q1 2010 were comparable to the prices received for Q1 2009. Oil prices received for Q1 2010 increased to $71.60 per barrel (“bbl”), compared to $42.04 per bbl for Q1 2009.

Royalties

	Three Months			Three Months
	Ended			Ended
	March 31			March 31
	2010			2009
Royalties
Crown	$	197,736		$	352,882
Freehold and GORR		23,213			173,474
Total royalties	$	220,949		$	526,356

$ per boe		7.74			7.68
As a percentage of oil and gas revenue		16	%		22	%

Royalties for Q1 2010 were $221,000 or $7.74 per BOE as compared to $526,000 or $7.68 per BOE for Q1 2009. The decrease in royalties was mainly due to the disposition of 100% interest in the Carson Creek area in 2009. Carson Creek is located in the province of Alberta and is subject to higher GORR and Crown royalty rates.

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 and rental, workovers, fuel and power. Operating and transportation expenses for Q1 2010 were $843,000 or $29.53 per BOE as compared to $998,000 or $14.56 per BOE for Q1 2009. On a per BOE basis, operating and transportation expenses are higher than the prior year’s quarter for the following reasons:

·	In January 2010, the Company incurred approximately net $220,000 for the installation of a rental compressor in the Woodrush field, resulting in higher per unit costs for the current quarter, when compared to the prior year’s quarter.

Delays in completing the installation of the compressor and other operational disruptions during the installation process resulted in the curtailed gas production in the first half of Q1 2010. As the majority of the operating expenses are fixed costs, therefore they are spread over a lower production base, resulting in higher per unit costs for Q1 2010.

Excluding the non-recurring installation cost of the compressor and the production delays and shut-in, the operating costs per BOE for Q1 2010 would have been comparable to the prior year’s quarter. However, the installation of the compressor will benefit the Company by allowing us to increase gas production while at the same time reduce ongoing compression costs and operating costs.

Operating Netbacks

Operating netbacks for the current quarter were $9.95 per BOE as compared to $12.95 per BOE for Q1 2009. The netbacks were impaired by $7.71 per BOE being the costs associated with the installation of the compressor. Excluding these non-recurring costs, the resultant netbacks for Q1 2010 were actually $17.66 per BOE, a 36% improvement over the prior year’s quarter of $12.95 per BOE.

General and Administrative Expenses

General and administrative expenses increased to $987,000 for Q1 2010 from $938,000 for Q1 2009. The increase was primarily due to the legal fees associated with the settlement of termination claim litigation from a former officer and director.

Interest and Finance Fees

For Q1 2010, the Company recorded interest and finance fees of $252,000, compared to $200,000 for Q1 2009. The increase was mainly due to the loan fees for setting up a credit facility of up to $5 million with Toscana Capital Corporation. The facility was obtained from Toscana in March 2010 to refinance the Company’s existing bank facility and fund working capital.

Amortization, Depletion and Accretion

For Q1 2010, amortization and depletion of property and equipment and accretion of asset retirement obligations was $746,000 compared to $2,710,000 for Q1 2009. The decrease was due to the lower production level for the current quarter.

Stock Based Compensation

For Q1 2010, the Company recorded non-cash stock based compensation expense of $164,000 compared to $210,000 for Q1 2009. The decrease was because many of the stock options previously granted had been fully vested.

Income Taxes, Foreign Exchange Loss and Other Items

Future income tax recovery for Q1 2010 was $Nil, as compared to future income tax recovery of $779,000 for Q1 2009. As at March 31, 2010, the Company did not have recognized future income tax assets associated with the potential income tax benefits because their realization is uncertain. Therefore, no future income tax recovery is recorded for the current quarter. The balance of future income tax liability as at March 31, 2009, which arose because the accounting net book value assigned to the oil and gas properties was in excess of the value of the tax pools, was lower than the balance as at December 31, 2008, resulting in future income tax recovery for Q1 2009.

Foreign exchange loss was decreased by $136,000 to $16,000 for Q1 2010 from $152,000 for Q1 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 loss in Q1 2009 due to the increase in the value of US dollars. In June 2009, the loan was converted into a Canadian dollar denominated loan and no foreign currency revaluation was necessary in Q1 2010.

The decrease in interest and other income was because no management fee income was received from a related party in Q1 2010. In Q1 2009, management fee income was received for financial advisory and project management services provided to the related party.

Net Loss

The Company’s net loss for Q1 2010 was $1,915,000 or $0.02 per share, compared to a net loss of $2,449,000, or $0.03 per share for Q1 2009. In Q1 2009, the Company had a loss on disposition of its investment in common shares of Titan Uranium Inc. of $311,000 and a non-cash equity loss from Titan of $142,000. The equity loss from Titan relates to the Company’s proportionate share of Titan’s loss in the current period.

SUMMARY OF QUARTERLY RESULTS

The following summary for the eight most recently completed financial quarters ending March 31, 2010 details pertinent financial and corporate information, which is unaudited and prepared by Management of the Company. For more detailed information, refer to related consolidated financial statements.

	1 st Quarter ended March 31, 2010 $			4 th Quarter ended December 31, 2009 $			3 rd Quarter ended September 30, 2009 $			2 nd Quarter ended June 30, 2009 $			1 st Quarter ended March 31, 2009 $			4 th Quarter ended December 31, 2008 $			3 rd Quarter ended September 30, 2008 $			2 nd Quarter ended June 30, 2008 $
Revenues		1,305,056			1,345,501			1,056,312			1,682,195			2,701,987			1,853,482			1,677,513			2,234,560
Net loss for the period		(1,914,974	)		(7,048,949	)		(2,528,039	)		(780,872	)		(2,449,058	)		(15,151,051	)		(3,038,792	)		(1,143,679	)
Basic and diluted net loss per common share		(0.02	)		(0.08	)		(0.03	)		(0.01	)		(0.03	)		(0.21	)		(0.04	)		(0.02	)

The substantial loss for the quarter ending December 31, 2009, when compared with the other quarters, was the result of the recognition of an impairment loss of oil and gas properties of $5,360,000 in the quarter. In addition, the substantial loss for the quarter ending December 31, 2008, when compared with the other quarters, was due to the recognition of an impairment loss of $12,990,343 for the investment in Titan in the quarter.

FINANCIAL INSTRUMENTS

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, bank line of credit, accounts payable, and loans from related parties. Management has determined that the fair value of these financial instruments approximates their carrying values due to their immediate or short-term maturity. 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.

From time to time, the Company enters into derivative contracts such as forwards, futures and swaps in an effort to mitigate the effects of volatile commodity prices and protect cash flows to enable funding of its exploration and development programs. Commodity prices can fluctuate due to political events, meteorological conditions, disruptions in supply and changes in demand.

As at December 31, 2009, the Company had outstanding 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 outstanding 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. In March 2010, the Company unwound both the natural gas hedge and the crude oil hedge, resulting in a total realized loss of $42,000. There were no derivative contracts outstanding as at March 31, 2010.

LIQUIDITY AND CAPITAL RESOURCES

Cash Balance and Cash Flow

The Company had cash and cash equivalents of $1,336,000 as at March 31, 2010. In addition to the cash balance, the Company also had accounts receivable of $882,000, most of which related to March 2010 oil and gas sales and had been received subsequent to March 31, 2010.

Our investing activities during Q1 2010 were financed primarily by the $1 million raised from the issuance of flow-through shares and draw down of bridge loan during the quarter.

In 2009, the Company successfully completed a turnaround on its oil & gas operation to reduce operating costs and improve operating netback. Together with the netback from two successful wells drilled in the current quarter, we expect to generate positive operating cash flow commencing the 2 nd quarter of 2010, based on the current oil price of US$80 per barrel and gas price of US$4 per Mcf on NYMEX.

Bank Loan and Bridge Loan Financing

In August 2008, DEAL secured a revolving operating loan facility with a Canadian Bank for up to $7,000,000. In accordance with the terms of the facility, DEAL is 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.

As at December 31, 2009, DEAL was in compliance with the working capital ratio requirement. On March 22, 2010, the bank line of credit was completely paid off.

On March 22, 2010, DEAL acquired a credit facility for a bridge loan of up to $5,000,000. The first 2,000,000 of the facility was used to refinance the DEAL’s existing bank facility and fund its working capital. The remainder of the line is accessible subject to additional lender review of engineering reports on oil and gas reserves being developed or acquired. The facility carries interest rate at 12% per annum, subject to a 1% fee on any amount drawn and a 2% fee on repayment. DEAL also paid a $50,000 commitment fee. As at March 31, 2010, $1,500,000 was drawn under this facility. The proceeds of this bridge loan require lender’s approval before it can be transferred to Dejour. The bridge loan is due on September 22, 2010. Subject to the agreement of the lender, the loan can be extended for a period of maximum 3 months. In addition, the extension will be subject to a 1% extension fee per month on the outstanding loan balance at the beginning of each month.

Working Capital Position

As at March 31, 2010, the Company had a working capital deficit of to $4,337,000. The working capital deficit mainly consisted of loans from related parties and bridge loan drawn during Q1 2010. The Company plans to remedy the deficiency through the following:

·	Once a new engineering evaluation is completed in the summer of 2010, the Company intends to obtain a credit facility with a conventional bank to refinance the existing bridge loan;

The Company expects to generate positive operating cash flow commencing Q2 2010 from its oil and gas production in the Woodrush/Drake property. The Company brought two new wells into production in early May. One new oil well had been producing at an average rate of 750 BOPD (563 BOPD net to the Company). The Company believes this new oil well is a new oil pool and can be exempt from BC Crown royalty for the first 72,000 barrels of oil production. At the current production rate and oil price, this oil well alone is expected to generate an operating netback of $400,000 to $600,000 per month net to Dejour;

·	If necessary and at the right market conditions, the Company may fund its working capital through additional debt or disposal of non-core asset or a combination of both.

Capital Resources

The Company plans to drill at least two wells in Canada during the remainder of 2010. The Company also plans to drill an exploratory well in an oil prospect at South Rangely in the US.

The Company plans to fund the drilling program through a combination of debt, equity or joint ventures.

Contractual Obligations

As of March 31, 2010, and in the normal course of business we have obligations to make future payments, representing contracts and other commitments that are known and committed.

Contractual Obligations
(in thousands of dollars)	2010		2011		2012		2013		2014		Thereafter	Total
	$		$		$		$		$		$	$
Operating Lease Obligations		118		73		73		73		49	Nil		386
Bridge Loan		1,500		-		-		-		-	Nil		1,500
Other Obligations		2,458		-		-		-		-	Nil		2,458
Total		4,076		73		73		73		49	Nil		4,344

OFF-BALANCE SHEET ARRANGEMENTS

The Company has no material undisclosed off-balance sheet arrangements that have or are reasonably likely to have, a current or future effect on our results of operations or financial condition.

TRANSACTION WITH RELATED PARTIES

HEC loan to the Company

In 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. $1,350,000 of the debt was converted into a 12% note due on January 1, 2011 and the Company is 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, both parties were agreed to reduce the loan balance by the purchase price after taxes and adjustments of $911,722. In addition, the loan balance was further reduced by a payment of $50,351. As at March 31, 2010 and December 31, 2009, $387,927 remained outstanding.

Brownstone loan to the Company

In 2008, Brownstone Ventures Inc. (“Brownstone”), a company which 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, provided the Company with a $4,078,800 (US $4,000,000) secured loan, which was used to purchase the additional acreage interests in the Colorado/Utah Projects. During 2008, a repayment of $222,948 (US$220,000) was made and a balance of $4,604,040 (US$3,780,000) was outstanding as at December 31, 2008.

During 2009, the Company entered into agreements with Brownstone in regard to the outstanding debt of $4,604,040 (US$3,780,000). Pursuant to the agreements, 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 US$1,780,000 (C$2,070,140) of the debt was converted into a Canadian dollar denominated 12% note due on January 1, 2011.

LITIGATION

SUBSEQUENT EVENTS

(b)	Production

On May 6, 2010, the Company installed flow lines and connected the new wells to the Woodrush production facility. The Halfway Oil well has been producing at an average rate of 750 BOPD since the commencement of production on May 6, 2010. On May 10, 2010, the Gething gas well commenced production at a rate of 1,120 MCFD.

(c)	Derivative Financial Instruments

As at May 7, 2010, 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 barrel
WTI Crude oil put options	August 2010	10,000 barrels per month	US$75
WTI Crude oil put options	September 2010	10,000 barrels per month	US$75

RECENTLY ADOPTED ACCOUNTING POLICIES AND FUTURE ACCOUNTING PRONOUNCEMENTS

Recently Adopted Accounting Policies

On January 1, 2010, the Company adopted the following Canadian Institute of Chartered Accountants (“CICA”) Handbook sections:

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 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 material impact on the Company’s consolidated financial statements.

Future Accounting Pronouncements

International Financial Reporting Standards (“IFRS”)

In January 2006, the CICA Accounting Standards Board (“AcSB”) adopted a strategic plan for the direction of accounting standards in Canada. As part of that plan, accounting standards in Canada for public companies are expected to converge with International Financial Reporting Standards (“IFRS”) by the end of 2011. The transition date of January 1, 2011 will require the restatement for comparative purposes of amounts reported by the Company for the year ended December 31, 2010.

Expected Accounting Policy Impacts

The Company’s significant areas of impact continue to include property, plant and equipment (“PP&E”), impairment testing. These areas of impact have the greatest potential impact to the Company’s 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, the Company follows 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, the Company will be 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. Currently, the Company capitalizes and depletes pre-exploration costs within the country cost centre. In 2008 and 2009, these costs were not material to the Company.

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, the Company will 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, the Company will continue to capitalize these costs within PP&E on the balance sheet. However, the costs will be depleted on a unit-of-production basis over an area level (unit of account) instead of the country cost centre level currently utilized under Canadian GAAP. The Company has not finalized the areas or the inputs to be utilized in the unit-of-production depletion calculation.

Under IFRS, upstream divestures will generally result in a gain or loss recognized in net earnings. Under Canadian GAAP, proceeds of divestitures are 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 is recorded.

The Company expects to adopt 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 expected to be equal to the Canadian GAAP unproved properties balance and the IFRS development costs are expected to be equal to the full cost pool balance. The Company will allocate this upstream full cost pool over reserves to establish the area level depletion units.

Impairment

Under Canadian GAAP, the Company is 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 is 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, the Company is 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. The Company will group its upstream assets into cash-generating units based on the independence of cash inflows from other assets or other groups of assets.

DISCLOSURE OF INTERNAL CONTROLS

The Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of the Company’s disclosure controls and procedures as at March 31, 2010. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as at March 31, 2010 to provide reasonable assurance that material information relating to the Company, including its consolidated subsidiaries, would be made known to them.

INTERNAL CONTROL OVER FINANCIAL REPORTING

The Chief Executive Officer and Chief Financial Officer are responsible for establishing and maintaining internal control over financial reporting (“ICFR”), as such term is defined in NI 52-109, for the Company. They have, as at March 31, 2010, designed ICFR, or caused it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. The Chief Executive Officer and Chief Financial Officer of the Company are able to certify the design of the Company’s internal control over financial reporting with no significant weaknesses in design of these internal controls that require commenting on in the MD&A.

It should be noted that while the officers believe that the Company’s controls provide a reasonable level of assurance with regard to their effectiveness, they do not expect that the disclosure controls and procedures or internal controls over financial reporting will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

There were no changes in the Company’s internal control over financial reporting that occurred during the three months ended March 31, 2010 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

The Board of Directors, through its Audit Committee, is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control. The Audit Committee is composed of three independent directors who review accounting, auditing, internal controls and financial reporting matters.

WHISTLEBLOWER POLICY

Effective December 28, 2007, the Company’s Audit Committee adopted resolutions that authorized the establishment of procedures for complaints received regarding accounting, internal controls or auditing matters, and for a confidential, anonymous submission procedure for employees and consultants who have concerns regarding questionable accounting or auditing matters. The implementation of the whistleblower policy is in accordance with the new requirements pursuant to Multilateral Instrument 52-110 Audit Committees, national Policy 58-201 Corporate Governance Guidelines and National Instrument 58-101 Disclosure of Corporate Governance Practices.

NON-GAAP MEASURE

Within the MD&A references are made to terms commonly used in the oil and gas industry.

Operating cash flow, operating profits and operating netbacks are financial terms that are not considered measures under Canadian generally accepted accounting principles (“GAAP”). Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating profits adjusts net income by non-operating items that Management believes reduces the comparability of the Company’s underlying financial performance between periods. Operating netback is calculated as revenue less royalties and operating expenses. These measures are widely used to assess an oil & gas company’s ability to generate cash which is used to internally fund exploration and development activities and to service debt. These measures should not be considered as an alternative to net income, cash flows from operating, investing or financing activities as an indicator of cash flows, or as a measure of liquidity. Dejour’s method of calculating these measures may differ from other companies and, accordingly, they may not be comparable to measures used by other companies.

BOE PRESENTATION

Barrel of oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of gas to one barrel of oil. The term “BOE” may be misleading if used in isolation. A BOE conversion ratio of one barrel of oil to six mcf of gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head.

Total BOEs are calculated by multiplying the daily production by the number of days in the period.

FORWARD LOOKING STATEMENTS

Statements contained in this document which are not historical facts are forward-looking statements that involve risks, uncertainties and other factors that could cause actual results to differ materially from those expressed or implied by such forward looking statements. Factors that could cause such differences include, but not limited to, are volatility and sensitivity to market price for uranium, environmental and safety issues including increased regulatory burdens, possible change in political support for nuclear energy, changes in government regulations and policies, and significant changes in the supply-demand fundamentals for uranium that could negatively affect prices. Although the Company believes that the assumptions inherent in forward looking statements are reasonable we recommend that one should not rely heavily on these statements. The Company disclaims any intention or obligation to update or revise any forward looking statements whether as a result of new information, future events or otherwise.

ABBREVIATIONS

In this MD&A, the following abbreviations commonly used in the oil & gas industry have the meanings indicated:

Oil and Natural Gas Liquids		Natural Gas
bbl	barrel	Mcf	thousand cubic feet
bbls	barrels	MCFD	thousand cubic feet per day
BOPD	barrels per day	MMcf	million cubic feet
Mbbls	thousand barrels	MMcf/d	million cubic feet per day
Mmbtu	million British thermal units	Mcfe	Thousand cubic feet of gas equivalent

Other
AECO		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.
BCF		Billion cubic feet
BCFE		Billion cubic feet equivalent
MBOE		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.

Form 52-109F2

Certification of interim filings - full certificate

I, Robert Hodgkinson, Chief Executive Officer of Dejour Enterprises Ltd., certify the following:

1.	Review: I have reviewed the interim financial statements and interim MD&A (together, the “interim filings”) of Dejour Enterprises Ltd. (the “issuer”) for the interim period ended March 31, 2010.

No misrepresentations: Based on my knowledge, having exercised reasonable diligence, the interim filings do not contain any untrue statement of a material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it was made, with respect to the period covered by the interim filings.

Fair presentation: Based on my knowledge, having exercised reasonable diligence, the interim financial statements together with the other financial information included in the interim filings fairly present in all material respects the financial condition, results of operations and cash flows of the issuer, as of the date of and for the periods presented in the interim filings.

Responsibility: The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as those terms are defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings, for the issuer.

5.	Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

(a)

designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

(i)

material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

(ii)

information required to be disclosed by the issuer in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and

(b)

designed ICFR, or caused it to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the issuer’s GAAP.

5.1 Control framework: The control framework the issuer's other certifying officer(s) and I used to design the issuer's ICFR is the Committee of Sponsoring Organizations of the Treadway Commission

(COSO) framework.

5.2	ICFR – material weakness relating to design: N/A

5.3	Limitation on scope of design: N/A

6.	Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on January 1, 2010 and ended on March 31, 2010 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: May 13, 2010

/*signed*/

Robert Hodgkinson

CEO

Form 52-109F2

Certification of interim filings - full certificate

I, Mathew Wong, Chief Financial Officer of Dejour Enterprises Ltd., certify the following:

1.	Review: I have reviewed the interim financial statements and interim MD&A (together, the “interim filings”) of Dejour Enterprises Ltd. (the “issuer”) for the interim period ended March 31, 2010.

8.	Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

(a)

designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

(i)

material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

(ii)

(b)

5.1 Control framework: The control framework the issuer's other certifying officer(s) and I used to design the issuer's ICFR is the Committee of Sponsoring Organizations of the Treadway Commission

(COSO) framework.

5.2	ICFR – material weakness relating to design: N/A

5.3	Limitation on scope of design: N/A

6.	Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on January 1, 2010 and ended on March 31, 2010 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: May 13, 2010

/*signed*/

Mathew Wong

CFO

Exhibit 99.2

CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

June 30, 2010

These unaudited financial statements have not been reviewed by the Company’s auditor.

DEJOUR ENTERPRISES LTD.

CONSOLIDATED BALANCE SHEETS

(Expressed in Canadian Dollars)

	June 30,			December 31,
	2010			2009
	(Unaudited)			(Audited)

ASSETS
Current
Cash and cash equivalents	$	3,019,692		$	2,732,696
Accounts receivable		1,367,589			724,773
Prepaids and deposits		514,293			555,672
Unrealized financial instrument gain		27,385			-
		4,928,959			4,013,141
Equipment (Note 4)		101,705			114,747
Uranium properties (Note 5 (a))		533,085			533,085
Oil and gas properties (Note 5 (b))		42,977,023			41,224,903
	$	48,540,772		$	45,885,876

LIABILITIES
Current
Bank line of credit and bridge loan (Note 6)	$	3,500,000		$	850,000
Accounts payable and accrued liabilities		3,674,219			2,653,483
Unrealized financial instrument loss		-			99,894
Loans from related parties (Note 7)		2,401,735			-
		9,575,954			3,603,377
Loans from related parties (Note 7)		-			2,345,401
Deferred leasehold inducement		35,810			39,913
Asset retirement obligations (Note 8)		276,884			208,516
		9,888,648			6,197,207

SHAREHOLDERS' EQUITY
Share capital (Note 9)		73,339,520			72,559,504
Contributed surplus (Note 11)		6,929,628			6,614,805
Deficit		(41,644,409	)		(39,385,746	)
Accumulated other comprehensive income (loss)		27,385			(99,894	)
		38,652,124			39,688,669
	$	48,540,772		$	45,885,876

Commitments (Notes 6, 7, 8 and 14)

Subsequent Event (Note 18)

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

DEJOUR ENTERPRISES LTD.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS AND DEFICIT

(Expressed in Canadian Dollars)

	Three Months			Three Months			Six Months			Six Months
	Ended			Ended			Ended			Ended
	June 30			June 30			June 30			June 30
	2010			2009			2010			2009

REVENUES
Oil and natural gas revenue	$	2,675,555		$	1,682,195		$	4,023,018		$	4,094,621
Realized financial instrument gain		92,846			-			50,439			289,561
		2,768,401			1,682,195			4,073,457			4,384,182

EXPENSES
Royalties		550,987			(22,519	)		771,936			503,837
Operating and transportation		659,852			875,449			1,502,431			1,873,567
Amortization, depletion and accretion		726,854			1,264,473			1,472,696			3,974,721
Interest expense and finance fee		275,276			305,612			527,722			506,351
General and administrative		769,275			851,511			1,756,191			1,789,158
Stock based compensation (Note 10)		150,467			106,792			314,823			316,751
		3,132,711			3,381,318			6,345,799			8,964,385

LOSS BEFORE THE FOLLOWING AND INCOME TAXES		(364,310	)		(1,699,123	)		(2,272,342	)		(4,580,203	)
Interest and other income		7,846			105,329			16,565			363,442
Gain (loss) on disposition of investment		-			36,608			-			(274,188	)
Equity loss from Titan		-			-			-			(142,196	)
Foreign exchange gain (loss)		12,775			477,211			(2,886	)		325,001
LOSS BEFORE INCOME TAXES		(343,689	)		(1,079,975	)		(2,258,663	)		(4,308,144	)

FUTURE INCOME TAXES RECOVERY		-			299,103			-			1,078,214

NET LOSS FOR THE PERIOD		(343,689	)		(780,872	)		(2,258,663	)		(3,229,930	)

DEFICIT, BEGINNING OF THE PERIOD		(41,300,720	)		(29,027,886	)		(39,385,746	)		(26,578,828	)

DEFICIT, END OF THE PERIOD	$	(41,644,409	)	$	(29,808,758	)	$	(41,644,409	)	$	(29,808,758	)

NET LOSS PER SHARE - BASIC AND DILUTED	$	(0.003	)	$	(0.011	)	$	(0.023	)	$	(0.044	)

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING - BASIC AND DILUTED		98,698,372			74,343,228			98,220,180			74,034,042

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

DEJOUR ENTERPRISES LTD.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS AND DEFICIT

(Expressed in Canadian Dollars)

	Three Months			Three Months			Six Months			Six Months
	Ended			Ended			Ended			Ended
	June 30			June 30			June 30			June 30
	2010			2009			2010			2009

NET LOSS FOR THE PERIOD	$	(343,689	)	$	(780,872	)	$	(2,258,663	)	$	(3,229,930	)
Unrealized financial instrument gain		27,385			-			27,385			-

COMPREHENSIVE LOSS FOR THE PERIOD	$	(316,304	)	$	(780,872	)	$	(2,231,278	)	$	(3,229,930	)

ACCUMULATED OTHER COMPREHENSIVE INCOME, BEGINNING OF THE PERIOD	$	-		$	-		$	(99,894	)	$	107,768
Unrealized gain arising during the period		27,385			-			27,385			-
Realized (gain) loss during the period		-			-			99,894			(107,768	)

ACCUMULATED OTHER COMPREHENSIVE INCOME, END OF THE PERIOD	$	27,385		$	-		$	27,385		$	-

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

DEJOUR ENTERPRISES LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Expressed in Canadian Dollars)

	Three Months			Three Months			Six Months			Six Months
	Ended			Ended			Ended			Ended
	June 30			June 30			June 30			June 30
	2010			2009			2010			2009

CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES
Net loss for the period	$	(343,689	)	$	(780,872	)	$	(2,258,663	)	$	(3,229,930	)
Adjustment for items not affecting cash:
Amortization, depletion and accretion		726,854			1,264,473			1,472,696			3,974,721
Equity (income) loss from Titan		-			-			-			142,196
Non-cash stock based compensation		150,467			106,792			314,823			316,751
Non-cash finance fees		28,167			-			56,334			-
Unrealized foreign exchange gain		-			(497,574	)		-			(333,900	)
Future income taxes recovery		-			(299,103	)		-			(1,078,214	)
(Gain) loss on disposal of investment		-			(36,608	)		-			274,188
Amortization of deferred leasehold inducement		(2,051	)		-			(4,103	)		-

Changes in non-cash working capital balances		(7,285	)		(905,405	)		419,299			(1,109,621	)
		552,463			(1,148,297	)		386			(1,043,809	)

CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES
Purchase of equipment		(1,729	)		(335	)		(1,969	)		(4,934	)
Proceeds on disposal of investment		-			117,858			-			2,305,491
Proceeds from sales of oil and gas properties		-			4,282,497			-			4,282,497
Resource properties expenditures		(883,231	)		(300,836	)		(3,141,437	)		(795,327	)
		(884,960	)		4,099,184			(3,143,406	)		5,787,727

CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES
Bank line of credit and bridge loan		2,000,000			(3,512,343	)		2,650,000			(3,699,793	)
Loans from related parties		-			(59,358	)		-			(750,000	)
Shares issued for cash		15,740			-			780,016			20,248
		2,015,740			(3,571,701	)		3,430,016			(4,429,545	)

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		1,683,243			(620,814	)		286,996			314,373

CASH AND CASH EQUIVALENTS, BEGINNING OF THE PERIOD		1,336,449			1,679,412			2,732,696			744,225

CASH AND CASH EQUIVALENTS, END OF THE PERIOD	$	3,019,692		$	1,058,598		$	3,019,692		$	1,058,598

Supplemental Cash Flow Information – Note 12

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

NOTE 1 – NATURE OF OPERATIONS AND BASIS OF PRESENTATION

NOTE 2 – RECENTLY ADOPTED ACCOUNTING POLICIES AND FUTURE ACCOUNTING PRONOUNCEMENTS

(c)	Recently Adopted Accounting Policies

On January 1, 2010, the Company adopted the following Canadian Institute of Chartered Accountants (“CICA”) Handbook sections:

NOTE 2 – RECENTLY ADOPTED ACCOUNTING POLICIES AND FUTURE ACCOUNTING PRONOUNCEMENTS (continued)

(d)	Future Accounting Pronouncements

The following accounting pronouncements are applicable to future reporting periods. The Company is currently evaluating the effects of adopting these standards:

(i)

NOTE 3 – SUMMARY OF OTHER SIGNIFICANT ACCOUNTING POLICIES

(k)	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.

(l)	Marketable Securities

(m)	Resource Properties

Mineral properties

NOTE 3 – SUMMARY OF OTHER SIGNIFICANT ACCOUNTING POLICIES (continued)

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.

Oil and gas properties

NOTE 3 – SUMMARY OF OTHER SIGNIFICANT ACCOUNTING POLICIES (continued)

(n)

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

(o)	Investments

(p)	Earnings (Loss) per Share

(q)	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.

(r)	Foreign Currency Translation

NOTE 3 – SUMMARY OF OTHER SIGNIFICANT ACCOUNTING POLICIES (continued)

(s)	Use of Estimates

(t)	Financial Instruments

On adopting these standards, 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. Marketable securities are designated as available for sale which are measured at fair value. Receivables are classified under loans and receivables, which are measured at amortized cost. Accounts payable and loans from related parties are classified as other financial liabilities, which are measured at amortized cost.

NOTE 3 – SUMMARY OF OTHER SIGNIFICANT ACCOUNTING POLICIES (continued)

(m)	Future Income Taxes

(n)	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.

(o)	Stock-Based Compensation

(p)	Asset Retirement Obligations

NOTE 3 – SUMMARY OF OTHER SIGNIFICANT ACCOUNTING POLICIES (continued)

(p)	Flow-Through Shares

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.

(q)	Impairment of Long-lived Assets

(r)	Comprehensive Income

NOTE 4 – EQUIPMENT

	June 30, 2010						December 31, 2009
			Accumulated						Accumulated
	Cost		Amortization		Net		Cost		Amortization		Net
Furniture, fixtures and equipment	$	136,043	$	77,852	$	58,191	$	135,804	$	71,350	$	64,454
Computer equipment		86,749		70,239		16,510		85,020		66,033		18,987
Software		19,802		18,744		1,058		19,802		17,686		2,116
Leasehold improvements		32,433		6,487		25,946		32,433		3,243		29,190
	$	275,027	$	173,322	$	101,705	$	273,059	$	158,312	$	114,747

NOTE 5 – RESOURCE PROPERTIES

(c)	Uranium Properties

(d)	Oil and Gas Properties

A continuity summary of capitalized acquisition costs and exploration expenditures in the Company’s oil and gas properties for the six months ended June 30, 2010 and year ended December 31, 2009 are as follows:

				Acquisition Costs			Exploration & Development			Impairment
	Balance Dec. 31, 2008			(Dispositions), Net			(Dispositions), Net			and write-down			Depletion and Other			Balance Dec. 31, 2009

US Oil and Gas Properties:

Colorado / Utah Projects	$	29,325,724		$	193,892		$	332,763		$	(1,403,929	)	$	-		$	28,448,450
Others		167,674			-			-			-			-			167,674
		29,493,398			193,892			332,763			(1,403,929	)		-			28,616,124

Canadian Oil and Gas Properties:
Carson Creek		1,787,878			(265	)		(1,787,613	)					-			-
Drake/Woodrush		19,015,381			(269,491	)		(2,239,573	)					-			16,506,317
Montney (Buick Creek)		977,050			(80,660	)		19,392						-			915,782
Saddle Hills		987,137			1,077			39,778						-			1,027,992
Others		7,957,349			762,790			(837,397	)		-			-			7,882,742
Asset retirement obligations		404,311			-			-			-			(154,160	)		250,151
Property depletion		(3,635,777	)		-			-			-			(6,382,574	)		(10,018,351	)
Impairment		-			-			-			(3,955,854	)		-			(3,955,854	)
		27,493,329			413,451			(4,805,413	)		(3,955,854	)		(6,536,734	)		12,608,779
	$	56,986,727		$	607,343		$	(4,472,650	)	$	(5,359,783	)	$	(6,536,734	)	$	41,224,903

NOTE 5 – RESOURCE PROPERTIES (continued)

	Balance Dec. 31, 2009			Acquisition Costs, Net		Exploration & Development, Net			Impairment and write-down		Depletion and Other			Balance Jun. 30, 2010

US Oil and Gas Properties:
Colorado / Utah Projects	$	28,448,450		$	150,974	$	237,658		$	-	$	-		$	28,837,082
Others		167,674			-		-			-		-			167,674
		28,616,124			150,974		237,658			-		-			29,004,756

Canadian Oil and Gas Properties:
Drake/Woodrush		16,506,317			7,777		2,815,531			-		-			19,329,625
Montney (Buick Creek)		915,782			2,665		20,415			-		-			938,862
Saddle Hills		1,027,992			403		781			-		-			1,029,176
Others		7,882,742			7,398		(102,164	)		-		-			7,787,976
Asset retirement obligations		250,151			-		-			-		60,112			310,263
Property depletion		(10,018,351	)		-		-			-		(1,449,430	)		(11,467,781	)
Impairment		(3,955,854	)		-		-			-		-			(3,955,854	)
		12,608,779			18,243		2,734,563			-		(1,389,318	)		13,972,267
	$	41,224,903		$	169,217	$	2,972,221		$	-	$	(1,389,318	)	$	42,977,023

NOTE 6 – BANK LINE OF CREDIT AND BRIDGE LOAN

In 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, DEAL was in compliance with the working capital ratio requirement and $850,000 of this facility was utilized. 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. On March 22, 2010, the bank line of credit was paid off in full.

On March 22, 2010, the Company negotiated a credit facility for a bridge loan of up to $5,000,000. This facility is secured by DEAL’s oil and gas assets in Canada. The first $2,000,000 of the facility was available and the Company utilized $1,500,000 to refinance the Company’s existing bank facility and fund working capital. In June 2010, the Company received lender’s approval for the availability of an additional $1,500,000 of the facility. The availability of the remainder of the facility ($1,500,000) is still subject to the lender’s approval. The Company drew additional $2,000,000 to support the development of DEAL’s oil and gas properties in the Woodrush/Drake area. The facility carries interest rate at 12% per annum, subject to a 1% fee on any amount drawn and a 2% fee on repayment. The Company paid a $50,000 commitment fee. As at June 30, 2010, a total of $3,500,000 of this facility was utilized. The bridge loan is due on September 22, 2010 and can be extended for a period of maximum 3 months. The extension will be subject to a 1% extension fee per month on the outstanding loan balance at the beginning of each month.

NOTE 7 – LOANS FROM RELATED PARTIES

(c)	Loan from Hodgkinson Equity Corporation (“HEC”)

HEC loan to DEAL

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. On March 19, 2009, a repayment of $600,000 was made and as at December 31, 2009, no balance remained outstanding.

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 June 30, 2010 and December 31, 2009, a balance of $387,927 remained outstanding.

NOTE 7 – LOANS FROM RELATED PARTIES (continued)

(d)	Loan from Brownstone Ventures Inc. (“Brownstone”)

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. The fair value assigned to the warrants of $169,000 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. It has been recorded in contributed surplus and will be amortized as a finance fee over the life of the note.

12% promissory note	$	2,070,140
Non-cash finance fee		(169,000	)
Accumulated amortization of non-cash finance fees		56,334
Balance as at December 31, 2009		1,957,474
Accumulated amortization of non-cash finance fees		56,334
Balance as at June 30, 2010	$	2,013,808

NOTE 8 – 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 June 30, 2010 to be $576,137. These obligations are expected to be settled by 2029. A credit adjusted risk-free rate of 5% and an inflation rate of 2% was used to calculate the present value of the asset retirement obligations.

Balance at December 31, 2008	$	363,109
Change in estimate		(154,160	)
Accretion expense		12,863
Actual costs incurred		(13,296	)

Balance at December 31, 2009		208,516
Change in estimate		60,112
Accretion expense		8,256

Balance at June 30, 2010	$	276,884

NOTE 9 – SHARE CAPITAL

Authorized:

Unlimited common shares, no par value

Unlimited first preferred shares, issuable in series

Unlimited second preferred shares, issuable in series

	Common
	Shares		Value

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 7)		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		-		147,222

Balance at December 31, 2009		95,791,038		72,559,504

- General share issuance costs		-		(130,157	)
- For cash by private placement, net of share issuance costs		2,907,334		910,173

Balance at June 30, 2010		98,698,372	$	73,339,520

During the six months ended June 30, 2010, the Company completed the following:

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 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 $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 share on or before March 3, 2011. The grant date fair values of the warrants and agent’s warrants, estimated to be $47,971 and $1,235 respectively, have been included in share capital on a net basis and accordingly have not been recorded as a separate component of shareholders’ equity.

During the year ended December 31, 2009:

NOTE 10 – STOCK OPTIONS AND SHARE PURCHASE WARRANTS

During the six months ended June 30, 2010, the Company granted 3,323,000 (2009 – 1,223,000) options to its officers, directors, consultants, employees and advisors. In addition, 100,000 (2009 – 2,659,750) options were cancelled or expired with a weighted average exercise price of $0.45 (2009 - $1.74).

As at June 30, 2010, there were 7,639,682 options outstanding with a weighted average exercise price of $0.41, of which 2,662,557 were vested. The vested options can be exercised for periods ending up to May 31, 2015 to purchase common shares of the Company at prices ranging from $0.35 to $0.55 per 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 six months ended June 30, 2010 was determined to be $684,100 (2009 - $352,610). 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 4.88 years (2009 – 4.02 years), risk-free interest rate of 2.41% (2009 – 1.55%) and expected volatility of 85.83% (2009 – 100.95%).

During the six months ended June 30, 2010, the Company recognized a total of $314,823 (2009 - $316,751) of stock based compensation relating to the vesting of options.

As at June 30, 2010, there were 4,977,125 unvested options included in the balance of the outstanding options. As of June 30, 2010, there was $1,212,986 of total unrecognized compensation cost related to non-vested stock options. That cost is expected to be recognized over a weighted average period of 4.06 years. The following table summarizes information about stock option transactions:

	Outstanding Options			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life
Balance, December 31, 2008		7,198,380		$	1.22	2.94 years
Options granted		3,312,000			0.46
Options exercised		(631,856	)		0.43
Options cancelled and expired		(5,461,842	)		1.46

Balance, December 31, 2009		4,416,682			0.45	3.54 years
Options granted		3,323,000			0.35
Options exercised		-			-
Options cancelled and expired		(100,000	)		0.45

Balance, June 30, 2010		7,639,682		$	0.41	3.67 years

NOTE 10 – STOCK OPTIONS AND SHARE PURCHASE WARRANTS (continued)

Details of stock options vested and exercisable as at June 30, 2010 are as follows:

Number of Options Outstanding and vested	Exercise Price		Weighted Average Remaining Contractual Life (Years)
1,592,375	$	0.45		2.61
120,000		0.50		0.50
78,182		0.55		0.50
872,000		0.35		4.14

2,662,557	$	0.42		2.96

The following table summarizes information about warrant transactions:

	Outstanding Warrants			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life
Balance, December 31, 2008		2,104,129		$	3.35	0.40 years
Warrants issued		14,736,150			0.47
Warrants expired		(2,104,129	)		3.35

Balance, December 31, 2009		14,736,150			0.47	4.36 years
Warrants issued		1,491,090			0.45

Balance, June 30, 2010		16,227,240		$	0.47	3.57 years

Details of warrants outstanding as at June 30, 2010 are as follows:

Number of Warrants Outstanding	Exercise Price		Weighted Average Remaining Contractual Life (Years)
2,000,000	$	0.50		0.98
4,015,151	$	0.55		3.98
8,075,000	US$	0.40		4.48
645,999	US$	0.46		4.35
1,491,090	$	0.45		0.67

16,227,240

NOTE 11 – CONTRIBUTED SURPLUS

Details of changes in the Company's contributed surplus balance are as follows:

Balance at December 31, 2008	$	5,895,560
Stock compensation on vesting of options		697,467
Allocated to share capital on exercise of options		(147,222	)
Value of warrants issued for settlement of debt		169,000

Balance at December 31, 2009		6,614,805
Stock compensation on vesting of options		314,823

Balance at June 30, 2010	$	6,929,628

NOTE 12 – SUPPLEMENTAL CASH FLOW INFORMATION

	Three Months			Three Months			Six Months			Six Months
	Ended			Ended			Ended			Ended
	June 30,			June 30,			June 30,			June 30,
	2010			2009			2010			2009
Changes in non-cash working capital balances:
Accounts receivable	$	(485,290	)	$	533,786		$	(642,816	)	$	54,929
Prepaids and deposits		140,822			(104,875	)		41,379			(142,021	)
Accounts payable and accrued liabilities		337,183			(1,496,316	)		1,020,736			(1,184,529	)
Deposits received		-			162,000			-			162,000
	$	(7,285	)	$	(905,405	)	$	419,299		$	(1,109,621	)

Other cash flow information:
Cash paid for interest	$	247,109		$	184,829		$	471,388		$	384,837
Cash paid for income taxes		-			-			-			-
	$	247,109		$	184,829		$	471,388		$	384,837

Components of cash and cash equivalents
Cash	$	3,019,692		$	758,598		$	3,019,692		$	758,598
Guaranteed investment certificates		-			300,000			-			300,000
	$	3,019,692		$	1,058,598		$	3,019,692		$	1,058,598

NOTE 13 – RELATED PARTY TRANSACTIONS

During the six months ended June 30, 2010 and 2009, the Company entered into the following transactions with related parties:

(i)	The Company incurred a total of $246,678 (2009 - $234,160) in consulting and professional fees and a total of $Nil (2009 - $69,013) in rent expenses to companies controlled by officers of the Company.

(j)	The Company incurred a total of $137,099 (2009 - $247,626) in interest expense and finance fee to related parties.

(k)	The Company received total rental income of $15,000 (2009 - $15,000) from companies controlled by officers of the Company.

(l)	The Company received total consulting fee income of $Nil (2009 - $114,200) from a related party which owns more than 10% of the Company’s outstanding common shares.

These transactions are in the normal course of operations and are measured at the exchange amount established and agreed to by the related parties.

NOTE 14 – COMMITMENT

2010	$	68,214
2011		73,051
2012		73,051
2013		73,051
2014		48,701
	$	336,068

NOTE 15 – SEGMENTED DISCLOSURE

As at June 30, 2010 and December 31, 2009, the Company’s significant assets, losses and revenue by geographic location were as follows:

	June 30,			December 31,
	2010			2009
Canada
Revenue	$	4,073,457		$	6,785,995
Interest and other income		16,565			302,824
Future income tax recovery		-			1,133,140
Segmented loss		(1,819,618	)		(10,969,741	)
Assets:
Current Assets		4,692,776			3,646,770
Equipment, net		74,432			85,664
Uranium properties		533,085			533,085
Oil and gas properties, net		13,972,267			12,608,779
		19,272,560			16,874,298
U.S.A.
Revenue		-			-
Interest and other income		-			114,200
Segmented loss		(439,045	)		(1,837,177	)
Assets:
Current Assets		236,183			366,372
Equipment, net		27,273			29,083
Oil and gas properties, net		29,004,756			28,616,124
		29,268,212			29,011,578
Total assets	$	48,540,772		$	45,885,876

NOTE 16 – LITIGATION

NOTE 17 – FINANCIAL INSTRUMENTS, RISK MANAGEMENT AND CAPITAL MANAGEMENT STRATEGY

(g)	Fair Value of Financial Instruments

CICA Handbook Section 3862 “Financial Instruments – Disclosures” requires disclosure of a three-level hierarchy for fair value measurements based upon transparency of inputs to the valuation of financial instruments carried on the balance sheet at fair value. The three levels are defined as follows:

1.	Level 1 – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets and liabilities in active markets.

2.	Level 2 – inputs to valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

3.	Level 3 – inputs to the valuation methodology are unobservable and significant to the fair value measurement.

The fair value of cash and cash equivalents, accounts receivable, bridge loan, accounts payable and accrued liabilities, loans from related parties approximate their carrying value due to the relatively short periods to maturity of these instruments.

The following table presents the Company’s fair value hierarchy for those assets and liabilities measured at fair value as of June 30, 2010:

	Level 1		Level 2		Level 3		Total
	$		$		$		$
Cash and cash equivalents		3,019,692		-		-		3,019,692
Accounts receivable		-		-		1,367,589		1,367,589
Bridge loan		-		3,500,000		-		3,500,000
Accounts payable and accrued liabilities		-		-		3,674,219		3,674,219
Loans from related parties		-		-		2,401,735		2,401,735
		3,019,692		3,500,000		7,443,543		13,963,235

NOTE 17 – FINANCIAL INSTRUMENTS, RISK MANAGEMENT AND CAPITAL MANAGEMENT STRATEGY (continued)

(h)	Liquidity Risk

The following are the contractual maturities of financial liabilities due as at June 30, 2010:

Financial liability	< 1 year		1 – 2 years		2 -5 years		Thereafter
	$		$		$		$
Bridge loan		3,500,000		-		-		-
Accounts payable and accrued liabilities		3,674,219		-		-		-
Loans from related parties		2,401,735		-		-		-
Total		9,575,954		-		-		-

(i)	Market Risk

(j)	Foreign Currency Exchange Risk

The Company was exposed to the following foreign currency risk at June 30, 2010:

Expressed in foreign currencies – June 30, 2010	USD
	$
Cash and cash equivalents		172,366
Accounts receivable		66,993
Accounts payable and accrued liabilities		(116,385	)
Balance sheet exposure		122,974

NOTE 17 – FINANCIAL INSTRUMENTS, RISK MANAGEMENT AND CAPITAL MANAGEMENT STRATEGY (continued)

The following foreign exchange rates applied for the six months ended and as at June 30, 2010:

Year to date average US dollar to Canadian dollar			1.0346
June 30, reporting date rate			1.0646

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 following currencies against the Canadian dollar would result in the decrease of net loss of $13,092 at June 30, 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.

(k)	Interest Rate Risk

Interest rate risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate as a result of changes in market interest rates. Financial instruments that potentially subject the Company to interest rate risk include cash and cash equivalents and bank line of credit. Presently, the Company is exposed to interest rate cash flow risk as it holds cash and cash equivalents with variable interest rates. A change in market interest rates on the average balance of interest-bearing cash and cash equivalents will impact net loss during the period. Based on the average balance of interest-bearing cash and cash equivalents during the six months ended June 30, 2010, an increase or decrease of 25 basis points in interest rates, with all other variables held constant, would not have a significant impact on net loss. The Company is not exposed to any interest rate fluctuations on its credit facility because it bears a fixed rate of interest. The Company had no interest rate swaps or financial contracts in place at or during the six months ended June 30, 2010.

(l)	Commodity Price Risk

At June 30, 2010, the Company had the following risk management contract outstanding:

Product		Period		Production		Fixed Price			Index Price
Gas		July 2010 to October 2010		600 GJ/day		$	3.94/GJ		Station 2 Gas Daily Daily Index

For the six months ended June 30, 2010, the Company recognized in income a realized gain of $50,439 on the risk management contracts (2009 - $289,561).

(m)	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, bank line of credit and 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.

NOTE 18 – SUBSEQUENT EVENT

Derivative Financial Instruments

Subsequent to June 30, 2010, the Company purchased 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 barrel
WTI Crude oil put options	September 2010	7,000 barrels per month	US$	70
WTI Crude oil put options	October 2010	7,000 barrels per month	US$	70
WTI Crude oil put options	November 2010	7,000 barrels per month	US$	70
WTI Crude oil put options	December 2010	7,000 barrels per month	US$	70

In addition, the Company sold the following written call options, allowing the purchaser the right, but not the obligation, to buy Western Texas Instrument (“WTI”) crude oil:

Crude oil Contract	Contract Month	Volume	Price per barrel
WTI Crude oil call options	October 2010	5,000 barrels per month	US$	90
WTI Crude oil call options	November 2010	5,000 barrels per month	US$	90
WTI Crude oil call options	December 2010	5,000 barrels per month	US$	90

MANAGEMENT DISCUSSION AND

ANALYSIS

For the Six Months Ended June 30, 2010

Date of Report: August 11, 2010

DEJOUR STRATEGY AND BUSINESS ENVIRONMENT

Dejour Enterprises Ltd. is an independent oil and natural gas company operating multiple exploration and production projects in North America's Piceance / Uinta Basin and Peace River Arch regions. In the first six months of 2010, Dejour was successful in doubling production at the Woodrush/Drake Field in N.E. British Columbia. This production increase was a key objective for Dejour for 2010. Also in the first half of 2010, oil prices strengthened and stabilized around the US$80/barrel level as gas price trended towards $5/MMBTU, allowing Dejour to post record revenues and achieve positive EBITDA in May and June of 2010. During this same period of expansion at Woodrush/Drake Field, the Company continued to move forward on the development of our key Piceance Basin acreage, where drilling is scheduled for 2011. Management believes that the Company’s major Piceance projects are economical at US$80/barrel oil and US$5/Million BTU gas to attract competitive financing, allowing us to undertake important investments in the growth of the Company in 2010 and 2011 without significant dilution of the value of the projects.

As of June 30, 2010, the Company had increased its Proved and Probable reserves at Drake/Woodrush by slightly more than 100%, to 604,000 Barrels of Oil Equivalent (57% oil) from December 31, 2009, according to our independent reserve evaluator, GLJ Petroleum Consultants. Present Value (10%) of the Company’s Proved and Probable reserves at Drake / Woodrush stood at $17 million as at June 30, 2010. A reserve and value increase for the Company resulting directly from the actions taken to preserve the company core assets in 2009.

For the balance of 2010, the Company anticipates an improving business environment and improving conditions in the financial markets. Dejour’s growth over the next one to two years will come from exploiting development opportunities at Drake/Woodrush property and from the development of low risk, high value resource plays identified in select Piceance Basin properties.

Dejour’s business objective remains the economic development of key projects and growth opportunities, resulting in the enhancement of shareholder value. This will be accomplished through prudent investment in and management of the Company’s portfolio of producing and non producing assets, combined with a limited program of strategic acquisitions and divestitures in our core operating areas.

COMPANY OVERVIEW

Dejour shares trade on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange AMEX (“NYSE-AMEX”) under the symbol “DEJ”.

The Company is in the business of acquiring, exploring and developing energy projects with a focus on oil and gas exploration in Canada and the United States and holds approximately 129,000 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 Q2 2008, Dejour commenced production and started receiving revenue from its Peace River Arch oil & gas properties, realizing the shift from a pure play exploration company to an exploration and production company.

Q2 2010 HIGHLIGHTS

In the 2 nd quarter of 2010, Dejour focused on increasing production 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 quarter, the Company achieved the following major corporate objectives and also made significant progress on key strategic initiatives that resulted in:

4.	Successfully brought two new wells onto production, allowing the company to generate positive operating cash flow of $559,000 in Q2.

5.	Increased Proved and Probable producing reserves at Drake / Woodrush to 534,000 Barrels of Oil Equivalent (58% oil), with a Present Value 10% (PV 10) at $15.7 million, an increase of 140% from December 31, 2009 PV 10 value of $6.5 million.

6.	Average production increased to 599 BOE/D (58% oil) in Q2 2010, an 89% increase over Q1 2010.

7.	Operating netback increased to $1.5 million in Q2 2010, a 416% improvement over Q1 2010.

8.	In Q2 2010, EBITDA increased by $1.6 million delivering a positive EBITDA of $658,000, and yielded a positive Adjusted EBITDA of $808,000.

OIL AND GAS EXPLORATION AND PRODUCTION

In 2010, Dejour evolved its 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.

US Activities

Gibson Gulch

Dejour has moved forward aggressively to begin the process of bringing this low risk development project into production. The Company has 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 Niobrara shale bodies. The Williams Companies, Inc. (NYSE: WMB) and Bill Barrett Corporation (NYSE: BBG) are developing and producing on adjacent acreage to the east, west and north of the Company’s acreage. An independent reserve evaluator, Gustavson Associates, assigned 90 BCF in proven undeveloped reserves to Dejour’s net acreage at Gibson Gulch as of December 31, 2009.

South Rangely

Over 2009, Dejour developed a plan for evaluation and subsequent exploitation of an oil prospect at South Rangely. During 2010, the Company 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 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 the Company to revisit plans to evaluate and potentially exploit a 22,000 acre tract at the Company’s North Rangely. 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 Dejour control with Dejour currently holding a 72% working interest of 22,000 acres in North Rangely.

Roan Creek

Future Exploration and Evaluation

Dejour retains a substantial amount of acreage prospective for oil and gas exploitation in other sections of the Piceance and Uinta basins with a 109,400 net acre position, sculpted over the 2006-2008 period. The Company is operator of approximately 130,000 acres and is 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, Dejour has high graded three future development and appraisal projects including:

Summary of Capitalized US Oil and Gas Expenditures

A continuity summary of capitalized acquisition costs, exploration expenditures in the Company’s US oil and gas properties for the six months ended June 30, 2010 are as follows:

	December 31,			June 30,
	2009		2010

	Net Book Value			Net Expenditures		Write-off		Net Book Value
US Oil and Gas Properties

Colorado/Utah Projects
Acquisition and lease rental	$	28,115,687		$	150,974	$	-	$	28,266,661
Geological and geophysical		19,186			5,205		-		24,391
Capitalized general and administrative		313,577			232,453		-		546,030
		28,448,450			388,632		-		28,837,082
Others
Acquisition		167,674			-		-		167,674
		167,674			-		-		167,674

Total US Oil and Gas Properties	$	28,616,124		$	388,632	$	-	$	29,004,756

Canadian Activities

Dejour’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.

As at June 30, 2010, DEAL’s holdings totaled 20,247 net acres concentrated in the Peace River Arch and the Montney shale basin.

Production and Development Projects

Woodrush/Drake

Operating cost reduction

Production increase from existing wells

Acquisition of additional prospective acreage

Seismic data acquisition and analysis

Step-out drilling from existing production based on seismic data.

In January 2010, Dejour installed gas compression facilities which increased gas production capacity and lowered compression costs. In the second half of March, DEAL drilled, completed and tested two additional wells at Woodrush. The first well was productive in the Gething formation and tested at a rate in excess of gross 900 MCFD (net 675 MCFD) of natural gas. The second well was productive in the Halfway formation and tested at a rate in excess of gross 500 BOPD (net 375 BOPD) of oil. In May 2010, DEAL successfully brought these two wells into production.

In 2010 Q2, with the tie-in of an additional oil well, Dejour successfully increased its daily production to 599 BOE/D from 317 BOE/D in 2010 Q1 and increased the oil component of production to 58% oil from 41% in 2010 Q1. The Company was able to generate positive EBITDA of $658,000 and operating cash flow of $559,000 in 2010 Q2, an important milestone.

The Company conducted a 3-D seismic survey designed to investigate the northern portion of the Woodrush lease and the southern portion of the newly acquired acreage and identified at least two additional development locations, targeting half-way oil pool.

Dejour plans to drill these locations in the reminder of 2010. If the Company is successful in the remainder of 2010 drilling program, then it intends to implement a secondary recovery project to improve reserves and production.

Buick Creek (Montney Shale Basin)

DEAL acquired 6,352 gross and net acres in the emerging Montney natural gas resource play in northeastern British Columbia during 2008. In early 2009, Dejour also acquired an existing wellbore which the Company believes can be used for re-entry and testing of the play.

Saddle Hills

Summary of Capitalized Canadian Oil and Gas Expenditures

A continuity summary of capitalized acquisition costs, exploration expenditures in the Company’s Canadian oil and gas properties for the six months ended June 30, 2010 is as follows:

	December 31,			June 30,
	2009			2010

	Net Book Value			Expenditures (Dispositions), Net			Write-off / Depletion			Net Book Value
Canadian Oil and Gas Properties

Drake/Woodrush
Land acquisition and retention	$	386,110		$	7,777		$	-		$	393,887
Drilling and completion		5,283,495			1,161,793			-			6,445,288
Equipping and facilities		10,114,948			1,004,756			-			11,119,704
Geological and geophysical		454,956			614,494			-			1,069,450
Capitalized general and administrative		266,808			34,488			-			301,296
		16,506,317			2,823,308			-			19,329,625

Buick Creek (Montney)
Land acquisition and retention		827,073			2,665			-			829,738
Capitalized interest		80,236			-			-			80,236
Capitalized general and administrative		8,473			20,415						28,888
		915,782			23,080			-			938,862

Saddle Hills
Land acquisition and retention		4,948			403			-			5,351
Drilling and completion		887,902			478			-			888,380
Equipping and facilities		54,571			303			-			54,874
Geological and geophysical		78,407			-			-			78,407
Capitalized general and administrative		2,164			-						2,164
		1,027,992			1,184			-			1,029,176

Others
Land acquisition and retention		1,623,177			7,398			-			1,630,575
Drilling and completion		4,420,145			(46,580	)		-			4,373,565
Equipping and facilities		484,095			(55,584	)		-			428,511
Geological and geophysical		952,530			-			-			952,530
Capitalized general and administrative		402,795			-			-			402,795
		7,882,742			(94,766	)		-			7,787,976

Corporate Costs
Assets retirement obligation		250,151			-			60,112			310,263
Depletion		(10,018,351	)		-			(1,449,430	)		(11,467,781	)
Impairment		(3,955,854	)		-			-			(3,955,854	)
		(13,724,054	)		-			(1,389,318	)		(15,113,372	)

Total Canadian Oil and Gas Properties	$	12,608,779		$	2,752,806		$	(1,389,318	)	$	13,972,267

The following table summarizes the breakdown of capital expenditures net of dispositions by type for the three and six months ended June 30, 2010 and 2009:

	Three Months		Three Months			Six Months		Six Months
	Ended		Ended			Ended		Ended
	June 30		June 30			June 30		June 30
	2010		2009			2010		2009

Land acquisition and retention	$	103,678	$	(1,055,789	)	$	169,217	$	(914,816	)
Drilling and completion		7,585		(1,699,093	)		1,115,691		(1,543,149	)
Equipping and facilities		587,370		(1,515,973	)		949,475		(1,416,242	)
Geological and geophysical		520		11,331			619,699		27,463
Capitalized general and administrative		184,078		(144,081	)		287,356		32,354
	$	883,231	$	(4,403,605	)	$	3,141,438	$	(3,814,390	)

Daily Production

	Three Months		Three Months		Six Months		Six Months
	Ended		Ended		Ended		Ended
	June 30		June 30		June 30		June 30
	2010		2009		2010		2009
By Product
Natural gas (mcf/d)		1,500		2,283		1,288		2,322
Natural gas liquids (bbls/d)		3		7		5		8
Oil (bbls/d)		346		166		239		262
Total (boe/d)		599		554		459		657

The production for the three months ended June 30, 2010 (“Q2 2010”) averaged 599 BOE/D, an increase of 8% compared to the three months ended June 30, 2009 (“Q2 2009”). The increase was mainly due to the two new wells commenced production in May 2010. The production for the six months ended June 30, 2010 averaged 459 BOE/D, a decrease of 30% compared to the six months ended June 30, 2009. The decrease was the result of disposition of 100% interest in the Carson Creek area and 25% interest in the Woodrush/Drake properties in 2009. However, this was partly offset by production from the two successful wells which came on production in May 2010.

URANIUM EXPLORATION PROJECTS

As at June 30, 2010, the Company maintained a 10% carried interest and 1% Net Smelter Return on approximately 578,365 acres of uranium exploration claims and leases. During the six months ended June 30, 2010, there was no expiration of claims or leases. The carrying value of the Company’s 10% carried interest and 1% Net Smelter Return was $533,085 as at June 30, 2010 and December 31, 2009.

SHARE CAPITAL

The following is a summary of share transactions for the six months ended June 30, 2010 and for the year ended December 31, 2009:

Authorized:

Unlimited common shares

Unlimited first preferred shares, issuable in series

Unlimited second preferred shares, issuable in series

	Common
	Shares		Value
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		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		-		147,222

Balance at December 31, 2009		95,791,038	$	72,559,504

- Share issuance costs related to prior share offerings		-		(130,157	)
- For cash by private placement, net of share issuance costs		2,907,334		910,173

Balance at June 30, 2010		98,698,372	$	73,339,520

As at August 11, 2010, the Company had 98,698,372 issued and outstanding common shares.

STOCK OPTIONS AND SHARE PURCHASE WARRANTS

The following table summarizes information about stock option transactions:

	Outstanding Options			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life
Balance, December 31, 2008		7,198,380		$	1.22	2.94 years
Options granted		3,312,000			0.46
Options exercised		(631,856	)		0.43
Options cancelled and expired		(5,461,842	)		1.46

Balance, December 31, 2009		4,416,682			0.45	3.54 years
Options granted		3,323,000			0.35
Options exercised		-			-
Options cancelled and expired		(100,000	)		0.45

Balance, June 30, 2010		7,639,682		$	0.41	3.67 years

Details of stock options vested and exercisable as at June 30, 2010 are as follows:

Number of Options Outstanding and vested	Exercise Price		Weighted Average Remaining Contractual Life (Years)
1,592,375	$	0.45		2.61
120,000	$	0.50		0.50
78,182	$	0.55		0.50
872,000	$	0.35		4.14

2,662,557	$	0.42		2.96

As at June 30, 2010, no outstanding and vested options were “in the money” (the exercise price was less than the market trading price).

STOCK OPTIONS AND SHARE PURCHASE WARRANTS (continued)

The following table summarizes information about share purchase warrants:

	Outstanding Warrants			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life
Balance, December 31, 2008		2,104,129		$	3.35	0.40 years
Warrants issued		14,736,150			0.47
Warrants expired		(2,104,129	)		3.35

Balance, December 31, 2009		14,736,150			0.47	4.36 years
Warrants issued		1,491,090			0.45

Balance, June 30, 2010		16,227,240		$	0.47	3.57 years

Details of warrants outstanding as at June 30, 2010 are as follows:

Number of Warrants Outstanding	Exercise Price		Weighted Average Remaining Contractual Life (Years)
2,000,000	$	0.50		0.98
4,015,151	$	0.55		3.98
8,075,000	US$	0.40		4.48
645,999	US$	0.46		4.35
1,491,090	$	0.45		0.67

16,227,240

RELATED PARTY TRANSACTIONS

During the six months ended June 30, 2010 and 2009, the Company entered into the following transactions with related parties:

(m)	The Company incurred a total of $246,678 (2009 - $234,160) in consulting and professional fees and a total of $Nil (2009 - $69,013) in rent expenses to companies controlled by officers of the Company.

(n)	The Company incurred a total of $137,099 (2009 - $247,626) in interest expense and finance fee to related parties.

(o)	The Company received total rental income of $15,000 (2009 - $15,000) from companies controlled by officers of the Company.

(p)	The Company received total consulting fee income of $Nil (2009 - $114,200) from a related party which owns more than 10% of the Company’s outstanding common shares.

These transactions are in the normal course of operations and are measured at the exchange amount established and agreed to by the related parties.

SELECTED FINANCIAL HIGHLIGHTS

Operating Cash Flow

	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
	$			$			$			$
Operating Cash Flow – Non-GAAP		559,000			(243,000	)		(419,000	)		66,000
Changes in non-cash working capital		(7,000	)		(905,000	)		419,000			(1,110,000	)
Cash provided by operating activities - GAAP		552,000			(1,148,000	)		-			(1,044,000	)

Operating Cash Flow is a non-GAAP measure defined as net cash provided by operating activities before changes in assets and liabilities.

Operating Netback

	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
	$			$			$			$
Revenues		2,675,000			1,682,000			4,023,000			4,095,000
Less: Royalties		(551,000	)		23,000			(772,000	)		(504,000	)
Less: Operating and transportation expenses		(660,000	)		(875,000	)		(1,502,000	)		(1,874,000	)
Operating Netback		1,464,000			830,000			1,749,000			1,717,000

Operating Netback is a non-GAAP measure defined as revenues less royalties and operating and transportation expenses.

EBITDA

	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
	$			$			$			$
Net loss		(344,000	)		(781,000	)		(2,259,000	)		(3,230,000	)
Future income taxes recovery		-			(299,000	)		-			(1,078,000	)
Interest expense and finance fee		275,000			306,000			528,000			506,000
Amortization, depletion and accretion		727,000			1,264,000			1,473,000			3,975,000
EBITDA		658,000			490,000			(258,000	)		173,000

EBITDA is a non-GAAP measure defined as net income (loss) before income tax expense, interest expense and finance fee, and amortization, depletion and accretion.

Adjusted EBITDA

	Three months ended June 30,					Six months ended June 30,
	2010		2009			2010			2009
	$		$			$			$
EBITDA		658,000		490,000			(258,000	)		173,000
Adjustments:
Non-cash stock-based compensation		150,000		107,000			315,000			317,000
(Gain) loss on disposition of investment		-		(37,000	)		-			274,000
Equity loss from Titan		-		-			-			142,000
Adjusted EBITDA		808,000		560,000			57,000			906,000

Adjusted EBITDA excludes certain items that management believes affect the comparability of operating results. Items excluded generally are non-cash items, one-time items or items whose timing or amount cannot be reasonably estimated.

RESULTS OF OPERATIONS – THREE MONTHS ENDED JUNE 30, 2010 AND 2009

Summary of Operational Highlights

DEAL Production and Netback Summary
	Three Months Ended June 30,
	2010		2009
Production Volumes:
Oil and natural gas liquids (bbls)		31,753		15,777
Gas (mcf)		136,538		207,748
Total (BOE)		54,509		50,402

Average Price Received:
Oil and natural gas liquids ($/bbls)		65.79		59.43
Gas ($/mcf)		4.29		3.88
Total ($/BOE)		49.08		34.61

Royalties ($/BOE)		10.11		(0.45	)

Operating Expenses ($/BOE)		12.11		18.60

Netbacks ($/BOE)		26.87		16.45

Revenues

	Three Months		Three Months
	Ended		Ended
	June 30,		June 30,
	2010		2009
Revenue
Natural gas	$	586,000	$	744,000
Oil and natural gas liquids		2,089,000		938,000
Total oil and gas revenue		2,675,000		1,682,000
Realized financial instrument gain		93,000		-
Total revenue	$	2,768,000	$	1,682,000

For Q2 2010, the Company recorded $2,089,000 in crude oil and natural gas liquids sales and $586,000 in natural gas sales as compared to $938,000 in crude oil and natural gas liquids sales and $744,000 in natural gas sales for Q2 2009. The increase in revenues was mainly attributable to the result of the two new wells commenced production in May 2010.

The following table summarizes the commodity prices realized by the Company and the crude oil and natural gas benchmark prices for the three months ended June 30, 2010 and 2009:

	Three Months		Three Months
	Ended		Ended
	June 30,		June 30,
	2010		2009
Dejour Average Prices
Natural gas ($/mcf)	$	4.29	$	3.88
Oil ($/bbl)		65.33		59.88
Total average price ($/boe)	$	49.08	$	34.61

Average Benchmark Prices
Western Canadian Select (WCS) ($/bbl)	$	65.63	$	60.66
Natural gas - AECO-C Spot ($/mcf)	$	3.86	$	3.62

Both the average natural gas sales prices and AECO-C daily spot prices for Q2 2010 were comparable to the prices received for Q2 2009. Oil prices received for Q2 2010 increased to $65.33 per barrel (“bbl”), compared to $59.88 per bbl for Q2 2009. The increase was due to the gradual recovery of the global economic market; leading to higher commodity prices.

Royalties

	Three Months			Three Months
	Ended			Ended
	June 30,			June 30,
	2010			2009
Royalties
Crown	$	540,000		$	(126,000	)
Freehold and GORR		11,000			103,000
Total royalties	$	551,000		$	(23,000	)

$ per boe	$	10.11		$	(0.45	)
As a percentage of oil and gas revenue		21	%		-1	%

Royalties for Q2 2010 increased substantially over Q2 2009 consistent with higher revenues generated. In Q2 2009, the British Columbia government approved a royalty holiday for the first 72,000 barrels of oil production on one of the Company’s oil well. The Company received a royalty credit of $280,000 from the BC provincial government, resulting in a net royalty recovery for the quarter. This 72,000 barrels royalty holiday was used up in 2009 and the Company is subject to a regular royalty rate in 2010.

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 and rental, workovers, fuel and power. Operating and transportation expenses for Q2 2010 decreased to $660,000 or $12.11 per BOE from $875,000 or $18.60 per BOE for Q2 2009 despite higher revenues. The installation of the compressor in January 2010 resulted in minimal compression costs, which accounted for the reduction in operating and transportation expenses for the current quarter.

Operating Netbacks

Operating netbacks for the current quarter increased to $1,464,000 or $26.87 per BOE from $830,000 or $16.45 per BOE for Q2 2009. The increase was mainly due to higher revenues and lower operating and transportation expenses. This was partially offset by increased royalties for Q2 2010.

General and Administrative Expenses

General and administrative expenses decreased to $769,000 for Q2 2010 from $852,000 for Q2 2009. The decrease was primarily due to the lower professional fees and other general overhead for the current quarter compared to the same period in 2009.

Interest and Finance Fees

For Q2 2010, the Company recorded interest and finance fees of $275,000, compared to $306,000 for Q2 2009. The decrease was mainly the result of the revolving operating loan facility paid off in March 2010. However, this was partly offset by the loan fees for setting up a credit facility of up to $5 million with Toscana Capital Corporation in March 2010 and the interest expenses associated with the utilization of the facility and the fees related to the search for future financings.

Amortization, Depletion and Accretion

For Q2 2010, amortization and depletion of property and equipment and accretion of asset retirement obligations was $727,000 compared to $1,264,000 for Q2 2009. The decrease was due to the positive drilling results in Mar 2010, which increased reserves in the Drake/Woodrush area at the end of June 30, 2010. This was partly offset by the increase in production for the current quarter.

Stock Based Compensation

For Q2 2010, the Company recorded non-cash stock based compensation expense of $150,000 compared to $107,000 for Q2 2009. The increase was mainly attributable to the initial grant of stock options during the six months ended June 30, 2010.

Income Taxes, Foreign Exchange Gain and Other Items

Future income tax recovery for Q2 2010 was $Nil, as compared to future income tax recovery of $299,000 for Q2 2009. As at June 30, 2010, the Company did not have recognized future income tax assets associated with the potential income tax benefits because their realization is uncertain. Therefore, no future income tax recovery is recorded for the current quarter. The balance of future income tax liability as at June 30, 2009, which arose because the accounting net book value assigned to the oil and gas properties was in excess of the value of the tax pools, was lower than the balance as at March 31, 2009, resulting in future income tax recovery for Q2 2009.

100

Foreign exchange gain was decreased by $464,000 to $13,000 for Q2 2010 from $477,000 for Q2 2009. At the end of Q2 2009, the Company had a US dollar denominated loan of $3.8 million from a related party and recorded a foreign exchange gain in Q2 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 in Q2 2010.

The decrease in interest and other income was because no management fee income was received from a related party in Q2 2010. In Q2 2009, management fee income was received for financial advisory and project management services provided to the related party.

Net Loss

The Company’s net loss for Q2 2010 was $344,000 or $0.003 per share, compared to a net loss of $781,000, or $0.011 per share for Q2 2009. The decrease in net loss was mostly attributable to increased revenues and decreased operating and transportation and depletion expenses, partially offset by increased royalties.

Operating Cash Flow

The Company generated a positive operating cash flow of $559,000 for Q2 2010 compared to a negative operating cash flow of $243,000 for Q2 2009. It was primarily the result of the two new wells commenced production in May 2010.

EBITDA and Adjusted EBITDA

EBITDA for Q2 2010 increased to $658,000 from $490,000 for Q2 2009. The increase was mainly attributable to lower net loss, partially offset by lower depletion expenses. In Q2 2009, the add-back of future income tax recovery of $299,000 also contributed to the increase in EBITDA.

Adjusted EBITDA for Q2 2010 increased to $808,000 from $560,000 for Q2 2009. The increase was primarily attributable to higher EBITDA and stock-based compensation expenses.

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RESULTS OF OPERATIONS – SIX MONTHS ENDED JUNE 30, 2010 AND 2009

Summary of Operational Highlights

DEAL Production and Netback Summary
	Six Months Ended June 30,
	2010		2009
Production Volumes:
Oil and natural gas liquids (bbls)		44,188		48,902
Gas (mcf)		233,146		420,347
Total (BOE)		83,045		118,961

Average Price Received:
Oil and natural gas liquids ($/bbls)		66.75		47.67
Gas ($/mcf)		4.60		4.34
Total ($/BOE)		48.44		34.94

Royalties ($/BOE)		9.30		4.24

Operating Expenses – compressor installation ($/BOE)		2.65		-
Other Operating Expenses ($/BOE)		15.44		16.86
Total Operating Expenses ($/BOE)		18.09		16.86

Netbacks ($/BOE)		21.06		14.44

Revenues

	Six Months		Six Months
	Ended		Ended
	June 30,		June 30,
	2010		2009
Revenue
Natural gas	$	1,073,000	$	1,763,000
Oil and nautral gas liquids		2,950,000		2,331,000
Total oil and gas revenue		4,023,000		4,094,000
Realized financial instrument gain		50,000		290,000
Total revenue	$	4,073,000	$	4,384,000

For the six months ended June 30, 2010, the Company recorded $2,950,000 in crude oil and natural gas liquids sales and $1,073,000 in natural gas sales as compared to $2,331,000 in crude oil and natural gas liquids sales and $1,763,000 in natural gas sales for the six months ended June 30, 2009. The decrease in revenues was mainly the result of disposition of 100% interest in the Carson Creek area and 25% interest in the Woodrush/Drake properties in 2009. This was partly offset by production from the two new wells which tied into production in May 2010.

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The following table summarizes the commodity prices realized by the Company and the crude oil and natural gas benchmark prices for the six months ended June 30, 2010 and 2009:

	Six Months		Six Months
	Ended		Ended
	June 30,		June 30,
	2010		2009
Dejour Average Prices
Natural gas ($/mcf)	$	4.60	$	4.34
Oil ($/bbl)		67.04		47.72
Total average price ($/boe)	$	48.44	$	34.94

Average Benchmark Prices
Western Canadian Select (WCS) ($/bbl)	$	69.08	$	51.64
Natural gas - AECO-C Spot ($ per mcf)	$	4.61	$	4.27

Both the average natural gas sales prices and AECO-C daily spot prices for the six months ended June 30, 2010 were comparable to the prices received for the same period in 2009. Oil prices received for the six months ended June 30, 2010 increased to $67.04 per barrel (“bbl”), compared to $47.72 per bbl for the same period in 2009. The increase was due to the gradual recovery of the global economic market; leading to higher commodity prices.

Royalties

	Six Months			Six Months
	Ended			Ended
	June 30,			June 30,
	2010			2009
Royalties
Crown	$	738,000		$	227,000
Freehold and GORR		34,000			277,000
Total royalties	$	772,000		$	504,000

$ per boe	$	9.30		$	4.24
As a percentage of oil and gas revenue		19	%		12	%

103

Royalties for the six months ended June 30, 2010 increased 40% over the same period in 2009 despite lower revenues. In Q2 2009, the British Columbia government approved a royalty holiday for the first 72,000 barrels of oil production on one of the Company’s oil well. The Company received a royalty credit of $280,000 from the BC provincial government, resulting in a low royalty rate in the first six months of 2009. This 72,000 barrels royalty holiday was used up in 2009 and the Company is subject to a regular royalty rate in 2010.

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 and rental, workovers, fuel and power. Operating and transportation expenses for the six months ended June 30, 2010 were $1,502,000 or $18.09 per BOE as compared to $1,874,000 or $16.86 per BOE for the six months ended June 30, 2009. On a per BOE basis, operating and transportation expenses are higher than the same period in the prior year for the following reasons:

·	In January 2010, the Company incurred approximately net $220,000 for the installation of a rental compressor in the Woodrush field, resulting in higher per unit costs for the six months ended June 30, 2010, compared to the same period in 2009.

Delays in completing the installation of the compressor and other operational disruptions during the installation process resulted in the curtailed gas production in the first half of 1 st quarter of 2010. As the majority of the operating expenses are fixed costs, therefore they are spread over a lower production base, resulting in higher per unit costs for the six months ended June 30, 2010.

Excluding the non-recurring installation cost of the compressor and the production delays and shut-in, the operating costs per BOE for the six months ended June 30, 2010 would have been lower compared to the same period in 2009. This reflects the positive impact to the Company’s operations as a result of the installation of the compressor, which had increased the gas production and lowered the ongoing compression costs and operating costs.

Operating Netbacks

Operating netbacks for the six months ended June 30, 2010 were $1,749,000 or $21.06 per BOE as compared to $1,717,000 or $14.44 per BOE for the same period in 2009. The netbacks were impaired by $2.65 per BOE being the costs associated with the installation of the compressor. Excluding these non-recurring costs, the resultant netbacks for the six months ended June 30, 2010 were actually $23.71 per BOE, a 64% improvement over the same period in the prior year.

General and Administrative Expenses

General and administrative expenses for the six months ended June 30, 2010 were consistent with the same period in 2009.

104

Interest and Finance Fees

Interest and finance fees for the six months ended June 30, 2010 were consistent with the same period in 2009.

Amortization, Depletion and Accretion

For the six months ended June 30, 2010, amortization and depletion of property and equipment and accretion of asset retirement obligations was $1,473,000 compared to $3,975,000 for the six months ended June 30, 2009. The decrease was due to the positive drilling results in Mar 2010, which increased reserves in the Drake/Woodrush area at the end of June 30, 2010. This was partly offset by the increase in production.

Stock Based Compensation

Non-cash stock based compensation expense recorded for the six months ended June 30, 2010 was consistent with the same period in 2009.

Income Taxes, Foreign Exchange Loss and Other Items

Future income tax recovery for the six months ended June 30, 2010 was $Nil, as compared to future income tax recovery of $1,078,000 for the six months ended June 30, 2009. As at June 30, 2010, the Company did not have recognized future income tax assets associated with the potential income tax benefits because their realization is uncertain. Therefore, no future income tax recovery is recorded for the six months ended June 30, 2010. The balance of future income tax liability as at June 30, 2009, which arose because the accounting net book value assigned to the oil and gas properties was in excess of the value of the tax pools, was lower than the balance as at December 31, 2008, resulting in future income tax recovery for the six months ended June 30, 2009.

Foreign exchange gain for the six months ended June 30, 2010 was decreased by $328,000 compared to the same period in 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 for the six months ended June 30, 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 six months ended June 30, 2010.

The decrease in interest and other income was because no management fee income was received from a related party for the six months ended June 30, 2010. During the six months ended June 30, 2009, management fee income was received for financial advisory and project management services provided to the related party.

Net Loss

The Company’s net loss for the six months ended June 30, 2010 was $2,259,000 or $0.023 per share, compared to a net loss of $3,230,000, or $0.044 per share for the same period in 2009. The decrease in net loss was mostly attributable to the decreased operating and transportation and depletion expenses, partially offset by lower revenues and higher royalties.

105

Operating Cash Flow

For the six months ended June 30, 2010, operating cash flow was $485,000 lower than the six months ended June 30, 2009. It was mainly due to lower revenues.

EBITDA and Adjusted EBITDA

For the six months ended June 30, 2010, EBITDA was $431,000 lower than the six months ended June 30, 2009. It was mainly due to lower depletion expenses more than offsetting lower net loss and the add-back of future income tax recovery of $1,078,000 during the six months ended June 30, 2009.

For the six months ended June 30, 2010, Adjusted EBITDA was $849,000 lower than the six months ended June 30, 2009. It was primarily due to negative EBITDA for the six months ended June 30, 2010. During the six months ended June 30, 2009, the add-back of loss on disposition of investment of $274,000 and equity loss from Titan of $142,000 also resulted in a higher Adjusted EBITDA for the period.

SUMMARY OF QUARTERLY RESULTS

The following summary for the eight most recently completed financial quarters ending June 30, 2010 details pertinent financial and corporate information, which is unaudited and prepared by Management of the Company. For more detailed information, refer to related consolidated financial statements.

	2 nd Quarter ended June 30, 2010 $			1 st Quarter ended March 31, 2010 $			4 th Quarter ended December 31, 2009 $			3 rd Quarter ended September 30, 2009 $			2 nd Quarter ended June 30, 2009 $			1 st Quarter ended March 31, 2009 $			4 th Quarter ended December 31, 2008 $			3 rd Quarter ended September 30, 2008 $
Revenues		2,768,000			1,305,000			1,346,000			1,056,000			1,682,000			2,702,000			1,853,000			1,678,000
Net loss for the period		(344,000	)		(1,915,000	)		(7,049,000	)		(2,528,000	)		(781,000	)		(2,449,000	)		(15,151,000	)		(3,039,000	)
Basic and diluted net loss per common share		(0.003	)		(0.02	)		(0.08	)		(0.03	)		(0.011	)		(0.03	)		(0.21	)		(0.04	)

The significant reduction in net loss for the current quarter was primarily attributable to the increase in revenues and decrease in operating and transportation and depletion expenses, partly offset by the increase in royalties.

106

FINANCIAL INSTRUMENTS

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, bridge loan, accounts payable, and loans from related parties. Management has determined that the fair value of these financial instruments approximates their carrying values due to their immediate or short-term maturity. 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.

At June 30, 2010, the Company had the following risk management contract outstanding:

Product		Period		Production		Fixed Price			Index Price
Gas		July 2010 to October 2010		600 GJ/day		$	3.94/GJ		Station 2 Gas Daily Daily Index

For the six months ended June 30, 2010, the Company recognized in income a realized gain of $50,439 on the risk management contracts (2009 - $289,561).

LIQUIDITY AND CAPITAL RESOURCES

Cash Balance and Cash Flow

The Company had cash and cash equivalents of $3,020,000 as of June 30, 2010. In addition to the cash balance, the Company also had accounts receivable of $1,368,000, most of which was related to June 2010 oil and gas sales that had been received subsequent to June 30, 2010.

107

Our investing activities during the six months ended June 30, 2010 were financed primarily by the $1 million raised from the issuance of flow-through shares and draw down of bridge loan during the period.

In 2009, the Company successfully completed a turnaround on its oil & gas operation to reduce operating costs and improve operating netback. Together with the netback from two successful wells drilled in May 2010, we generated positive operating cash flow of $559,000 commencing the 2 nd quarter of 2010. Based on current production forecast and NYMEX oil price of US$80 per barrel and gas price of US$4.50 per Mcf, the Company is expected to generate sufficient operating netback from its oil & gas operations to pay for the general & administration expenses of the Company.

Bank Loan and Bridge Loan Financing

As at December 31, 2009, DEAL was in compliance with the working capital ratio requirement. On March 22, 2010, the bank line of credit was completely paid off.

On March 22, 2010, DEAL negotiated a credit facility for a bridge loan of up to $5,000,000. This facility is secured by DEAL’s oil and gas assets in Canada. The first $2,000,000 of the facility was available and DEAL utilized $1,500,000 to refinance its existing bank facility and fund the working capital. In June 2010, DEAL received lender’s approval for the availability of an additional $1,500,000 of the facility. The availability of the remainder of the facility ($1,500,000) is still subject to the lender’s approval. DEAL drew additional $2,000,000 to support the development of its oil and gas properties in the Drake/Woodrush area. The facility carries interest rate at 12% per annum, subject to a 1% fee on any amount drawn and a 2% fee on repayment. DEAL also paid a $50,000 commitment fee.

As of June 30, 2010, a total of $3,500,000 of this facility was utilized. The bridge loan is due on September 22, 2010 and can be extended for a period of maximum 3 months. The extension will be subject to a 1% extension fee per month on the outstanding loan balance at the beginning of each month.

Working Capital Position

As at June 30, 2010, the Company had a working capital deficit of to $4,647,000. The working capital deficit mainly consisted of loans from related parties and bridge loan drawn during the six months ended June 30, 2010. The Company plans to remedy the deficiency through the following:

·	Since a new engineering evaluation is completed in July 2010, the Company intends to obtain a credit facility with a conventional bank to refinance the existing bridge loan. Also, the Company is in discussions with the bridge loan lender to extend and increase the existing credit facility.

108

In May 2010, the Company successfully brought two new wells into production and generated positive operating cash flow from its oil and gas production in the Woodrush/Drake property. Average production increased to 599 BOE/D in Q2 2010 from 317 BOE/D in Q1 2010. At the current production rate and oil price, we expect to generate an operating netback of approximately $400,000 per month for at least the remainder of 2010, which would be sufficient to fund general overhead expenses.


·	If necessary and at the right market conditions, the Company may fund its working capital through additional debt or disposal of non-core asset or a combination of both.

Capital Resources

The Company plans to drill at least two wells in Canada during the remainder of 2010. The Company also plans to drill an exploratory well in an oil prospect at South Rangely in the US.

The Company plans to fund the drilling program through a combination of debt, equity or joint ventures.

Contractual Obligations

As of June 30, 2010, and in the normal course of business we have obligations to make future payments, representing contracts and other commitments that are known and committed.

Contractual Obligations
(in thousands of dollars)	2010		2011		2012		2013		2014		Thereafter	Total
	$		$		$		$		$		$	$
Operating Lease Obligations		68		73		73		73		49	Nil		336
Bridge Loan		3,500		-		-		-		-	Nil		3,500
Other Obligations		2,458		-		-		-		-	Nil		2,458
Total		6,026		73		73		73		49	Nil		6,294

OFF-BALANCE SHEET ARRANGEMENTS

The Company has no material undisclosed off-balance sheet arrangements that have or are reasonably likely to have, a current or future effect on our results of operations or financial condition.

TRANSACTION WITH RELATED PARTIES

HEC loan to the Company

In 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. $1,350,000 of the debt was converted into a 12% note due on January 1, 2011 and the Company is 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, both parties were agreed to reduce the loan balance by the purchase price after taxes and adjustments of $911,722. In addition, the loan balance was further reduced by a payment of $50,351. As at June 30, 2010 and December 31, 2009, $387,927 remained outstanding.

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Brownstone loan to the Company

LITIGATION

SUBSEQUENT EVENT

Derivative Financial Instruments

Subsequent to June 30, 2010, the Company purchased 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 barrel
WTI Crude oil put options	September 2010	7,000 barrels per month	US$	70
WTI Crude oil put options	October 2010	7,000 barrels per month	US$	70
WTI Crude oil put options	November 2010	7,000 barrels per month	US$	70
WTI Crude oil put options	December 2010	7,000 barrels per month	US$	70

In addition, the Company sold the following written call options, allowing the purchaser the right, but not the obligation, to buy Western Texas Instrument (“WTI”) crude oil:

Crude oil Contract	Contract Month	Volume	Price per barrel
WTI Crude oil call options	October 2010	5,000 barrels per month	US$	90
WTI Crude oil call options	November 2010	5,000 barrels per month	US$	90
WTI Crude oil call options	December 2010	5,000 barrels per month	US$	90

110

RECENTLY ADOPTED ACCOUNTING POLICIES AND FUTURE ACCOUNTING PRONOUNCEMENTS

Recently Adopted Accounting Policies

On January 1, 2010, the Company adopted the following Canadian Institute of Chartered Accountants (“CICA”) Handbook sections:

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 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 material impact on the Company’s 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.

The Company commenced its IFRS project in 2009. This project consists of four phases: diagnostic; design and planning; solution development; and integration. The Company has completed the diagnostic phase, which involved a high-level review of the major differences between current GAAP and IFRS. The Company has determined that the areas of accounting differences with the highest potential impact to the Company are accounting for the exploration and evaluation of oil and gas resources, as well as accounting for property, plant and equipment, asset impairment testing, and income taxes.

In 2010 Q3 and Q4, the Company continues to work through 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, the Company will also assess the impact the changeover will have on current policies and procedures, information technology and accounting systems, as well as internal controls.

111

Additionally, in 2010, the Company will address 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 the Company to track and report the financial information required to prepare financial statements under IFRS.

The Company will continue to monitor the development of guidance on how to apply IFRS to oil and gas exploration and development activities, as well as the IFRS adoption efforts of its peers, and will update its plans as necessary.

Expected Accounting Policy Impacts

Property, Plant and Equipment

112

Impairment

DISCLOSURE OF INTERNAL CONTROLS

The Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of the Company’s disclosure controls and procedures as at June 30, 2010. Based on that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as at June 30, 2010 to provide reasonable assurance that material information relating to the Company, including its consolidated subsidiaries, would be made known to them.

INTERNAL CONTROL OVER FINANCIAL REPORTING

The Chief Executive Officer and Chief Financial Officer are responsible for establishing and maintaining internal control over financial reporting (“ICFR”), as such term is defined in NI 52-109, for the Company. They have, as at June 30, 2010, designed ICFR, or caused it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with Canadian GAAP. The Chief Executive Officer and Chief Financial Officer of the Company are able to certify the design of the Company’s internal control over financial reporting with no significant weaknesses in design of these internal controls that require commenting on in the MD&A.

113

There were no changes in the Company’s internal control over financial reporting that occurred during the three months ended June 30, 2010 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

WHISTLEBLOWER POLICY

NON-GAAP MEASURE

Within the MD&A references are made to terms commonly used in the oil and gas industry.

Operating Cash Flow is a non-GAAP measure defined as net cash provided by operating activities before changes in assets and liabilities.

Operating Netback is a non-GAAP measure defined as revenues less royalties and operating and transportation expenses.

EBITDA is a non-GAAP measure defined as net income (loss) before income tax expense, interest expense and finance fee, and amortization, depletion and accretion.

Certain measures in this document do not have any standardized meaning as prescribed by Canadian GAAP such as Operating Cash Flow, Operating Netback, EBITDA and Adjusted EBITDA and therefore are considered non-GAAP measures. These measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in this document in order to provide shareholders and potential investors with additional information regarding our liquidity and our ability to generate funds to finance our operations.

114

BOE PRESENTATION

Total BOEs are calculated by multiplying the daily production by the number of days in the period.

FORWARD LOOKING STATEMENTS

ABBREVIATIONS

In this MD&A, the following abbreviations commonly used in the oil & gas industry have the meanings indicated:

Oil and Natural Gas Liquids		Natural Gas
bbl	barrel	Mcf	thousand cubic feet
bbls	barrels	MCFD	thousand cubic feet per day
BOPD	barrels per day	MMcf	million cubic feet
Mbbls	thousand barrels	MMcf/d	million cubic feet per day
Mmbtu	million British thermal units	Mcfe	Thousand cubic feet of gas equivalent

Other
AECO	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.
BCF	Billion cubic feet
BCFE	Billion cubic feet equivalent
MBOE	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.

115

Form 52-109F2

Certification of interim filings - full certificate

I, Robert Hodgkinson, Chief Executive Officer of Dejour Enterprises Ltd., certify the following:

1.	Review: I have reviewed the interim financial statements and interim MD&A (together, the “interim filings”) of Dejour Enterprises Ltd. (the “issuer”) for the interim period ended June 30, 2010.

10.

11.	Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

(a)

designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

(i)

material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

(ii)

(b)

5.1	Control framework: The control framework the issuer's other certifying officer(s) and I used to design the issuer's ICFR is the Committee of Sponsoring Organizations of the Treadway Commission

(COSO) framework.

5.2	ICFR – material weakness relating to design: N/A

5.3	Limitation on scope of design: N/A

116

6.	Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on April 1, 2010 and ended on June 30, 2010 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: August 16, 2010

/*signed*/

Robert Hodgkinson

CEO

Form 52-109F2

Certification of interim filings - full certificate

I, Mathew Wong, Chief Financial Officer of Dejour Enterprises Ltd., certify the following:

1.	Review: I have reviewed the interim financial statements and interim MD&A (together, the “interim filings”) of Dejour Enterprises Ltd. (the “issuer”) for the interim period ended June 30, 2010.

12.

13.

14.	Design: Subject to the limitations, if any, described in paragraphs 5.2 and 5.3, the issuer’s other certifying officer(s) and I have, as at the end of the period covered by the interim filings

(a)

designed DC&P, or caused it to be designed under our supervision, to provide reasonable assurance that

(i)

material information relating to the issuer is made known to us by others, particularly during the period in which the interim filings are being prepared; and

117

(ii)

(b)

5.1 Control framework: The control framework the issuer's other certifying officer(s) and I used to design the issuer's ICFR is the Committee of Sponsoring Organizations of the Treadway Commission

(COSO) framework.

5.2	ICFR – material weakness relating to design: N/A

5.3	Limitation on scope of design: N/A

6.	Reporting changes in ICFR: The issuer has disclosed in its interim MD&A any change in the issuer’s ICFR that occurred during the period beginning on April 1, 2010 and ended on June 30, 2010 that has materially affected, or is reasonably likely to materially affect, the issuer’s ICFR.

Date: August 16, 2010

/*signed*/

Mathew Wong

CFO

118

EXHIBIT 99.3

U.S. GAAP RECONCILIATION NOTE FOR THE PERIOD ENDED JUNE 30, 2010

119

D EJOUR ENTERPRISES LTD.

RECONCILIATION BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED

ACCOUNTING PRINCIPLES (“US GAAP”)

For the Six Months Ended June 30, 2010

Unaudited – Prepared by management and have not been reviewed by the Company’s auditor

The Company’s interim consolidated financial statements for the six months ended June 30, 2010 have been prepared in accordance with generally accepted accounting principles in Canada (“Canadian GAAP”) which differ in certain respects with accounting principles generally accepted in the United States and from practices prescribed by the Securities and Exchange Commission (collectively “US GAAP”). Material differences to these financial statements are as follows:

(a)	Interest in unproven mineral properties

Under US GAAP, the Company classified its mineral rights as tangible assets and accordingly acquisition costs are capitalized as mineral property costs. US GAAP requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In performing the review for recoverability, the Company is to estimate the future cash flows expected to result from the use of the asset and its eventual disposition. If the sum of the undiscounted expected future cash flows is less than the carrying amount of the asset, an impairment loss is recognized. Mineral exploration costs are expensed as incurred until commercially mineable deposits are determined to exist within a particular property. Accordingly, for all periods presented, the Company has capitalized all mineral exploration costs for US GAAP purposes unless the costs relate to unproven mineral properties. In addition, under Canadian GAAP, cash flows relating to unproven mineral property costs are reported as investing activities. For US GAAP, these costs are classified as operating activities.

(b)	Stock-based compensation

The Company has granted stock options to certain directors, employees and consultants. Under Canadian GAAP, prior to 2003, no compensation expense was recorded in connection with the granting of stock options. Under previous US GAAP, the Company accounted for stock-based compensation in respect of stock options granted to directors and employees using the intrinsic value based method. Stock options granted to non-employees were accounted for by applying the fair value method using the Black-Scholes option pricing model. Commencing January 1, 2003, under Canadian GAAP the Company expenses the fair value of all stock options granted and under US GAAP prospectively changed its accounting policy to account for all stock options granted in accordance with Accounting Standards Codification (“ASC”) 718. As a result, effective January 1, 2003, there is no material difference between the Company’s accounting for stock options under US GAAP versus Canadian GAAP.

(c)	Income taxes

Under US GAAP, the effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Under Canadian GAAP, the effect of a change in tax rates is recognized in the period of substantive enactment. The application of this difference under US GAAP does not result in a material difference between future income taxes as recorded under Canadian GAAP.

(d)	Flow-through share premiums

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 difference and is reversed when 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 earnings 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, except to the extent that the Company has unrecorded loss carryforwards and tax pools in excess of book value available for deduction against which a valuation allowance has been provided.

120

DEJOUR ENTERPRISES LTD.

RECONCILIATION BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED

ACCOUNTING PRINCIPLES (“US GAAP”)

For the Six Months Ended June 30, 2010

Unaudited – Prepared by management and have not been reviewed by the Company’s auditor

(e)	Reporting comprehensive income

ASC 220 “Comprehensive Income” establishes standards for the reporting and display of comprehensive income and its components in a full set of general purpose financial statements. Comprehensive income equals net income for the year as adjusted for all other non-owner changes in shareholders’ equity. ASC 220 requires that all items that are required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement. Effective January 1, 2007, the Company adopted new Canadian GAAP accounting standards issued by the CICA relating to comprehensive income. The new standard has been adopted on a prospective basis with no restatement to prior period financial statements. The new standard substantially harmonizes Canadian GAAP with US GAAP with respect to reporting comprehensive income and loss.

(f)	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.

(g)	Recent accounting pronouncements

During 2009, the Company adopted the Financial Accounting Standards Board ("FASB") Accounting Standards Update, "Amendments Based on Statement of Financial Accounting Standards No. 168 – The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles" (the "Codification"). The Codification became the single source of authoritative GAAP in the United States, other than rules and interpretive releases issued by the United States Securities and Exchange Commission ("SEC"). The Codification reorganized GAAP into a topical format that eliminates the previous GAAP hierarchy and instead established two levels of guidance – authoritative and nonauthoritative. All non-grandfathered, non-SEC accounting literature that was not included in the Codification became nonauthoritative. The adoption of the Codification did not change previous GAAP, but rather simplified user access to all authoritative literature related to a particular accounting topic in one place. Accordingly, the adoption had no impact on the Company’s consolidated financial position or results of operations. All prior references to previous GAAP in the Company’s consolidated financial statements were updated for the new references under the Codification.

In June 2009, the FASB issued general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before the financial statements are issued or are available to be issued (codified within ASC 855). The update sets forth: (a) the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements; (b) the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and (c) the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. The adoption of this standard had no impact on the Company’s financial position, results of operations or cash flows.

On July 1, 2009, the Company adopted authoritative guidance issued by the FASB on business combinations. The guidance retains the fundamental requirements that the acquisition method of accounting (previously referred to as the purchase method of accounting) be used for all business combinations, but requires a number of changes, including changes in the way assets and liabilities are recognized and measured as a result of business combinations. It also requires the capitalization of in-process research and development at fair value and requires the expensing of acquisition-related costs as incurred. Adoption of the new guidance had no impact on the Company’s financial statements.

On July 1, 2009, the Company adopted the authoritative guidance issued by the FASB that changes the accounting and reporting for non-controlling interests. Non-controlling interests are to be reported as a component of equity separate from the parent’s equity, and purchases or sales of equity interests that do not result in a change in control are to be accounted for as equity transactions. In addition, net income attributable to a non-controlling interest is to be included in net income and, upon a loss of control, the interest sold, as well as any interest retained, is to be recorded at fair value with any gain or loss recognized in net income. Adoption of the new guidance had no impact on the Company’s financial statement.

121

DEJOUR ENTERPRISES LTD.

RECONCILIATION BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED

ACCOUNTING PRINCIPLES (“US GAAP”)

For the Six Months Ended June 30, 2010

Unaudited – Prepared by management and have not been reviewed by the Company’s auditor

(g)	Recent accounting pronouncements (continued)

On July 1, 2009, the Company adopted the authoritative guidance on fair value measurement for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Adoption of the new guidance had no impact on the Company’s financial statements.

(h)	Recent Accounting Guidance Not Yet Adopted

In June 2009, the FASB issued authoritative guidance on the consolidation of variable interest entities, which is effective for the Company beginning July 1, 2010. The new guidance requires revised evaluations of whether entities represent variable interest entities, ongoing assessments of control over such entities, and additional disclosures for variable interests. The Company believes adoption of this new guidance will have no impact on the Company’s financial statements.

(i)	Reconciliation

The effect of the differences between Canadian GAAP and US GAAP (including practices prescribed by the SEC) on the balance sheets, statements of operations and cash flows are summarized as follows:

122

DEJOUR ENTERPRISES LTD.

RECONCILIATION BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED

ACCOUNTING PRINCIPLES (“US GAAP”)

For the Six Months Ended June 30, 2010

Unaudited – Prepared by management and have not been reviewed by the Company’s auditor

1. Assets

	June 30,			December 31,
	2010			2009

Total assets, under Canadian GAAP	$	48,540,772		$	45,885,876
Exploration costs - unproven resource properties		(481,714	)		(481,714	)
Add: Resource properties accumulated depletion under Canadian GAAP		11,467,781			10,018,351
Add: Resource properties impairment under Canadian GAAP		3,955,854			3,955,854
Less: Resource properties accumulated depletion under US GAAP		(10,835,701	)		(8,782,402	)
Less: Resource properties impairment under US GAAP		(15,807,960	)		(15,807,960	)

Total assets, under US GAAP	$	36,839,032		$	34,788,005

2. Liabilities

	June 30,		December 31,
	2010		2009

Total liabilities, under Canadian GAAP	$	9,888,648	$	6,197,207
Add: flow through issue cost liability under US GAAP		285,570		271,033

Total liabilities, under US GAAP	$	10,174,218	$	6,468,240

3. Share Capital


	June 30,			December 31,
	2010			2009

Total share capital, under Canadian GAAP	$	73,339,520		$	72,559,504
Add: flow through issue cost under Canadian GAAP		4,669,883			4,669,883
Less: flow through issue cost under US GAAP		(470,570	)		(456,033	)

Total share capital, under US GAAP	$	77,538,833		$	76,773,354

123

DEJOUR ENTERPRISES LTD.

RECONCILIATION BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED

ACCOUNTING PRINCIPLES (“US GAAP”)

For the Six Months Ended June 30, 2010

Unaudited – Prepared by management and have not been reviewed by the Company’s auditor

4. Deficit

	June 30,			December 31,
	2010			2009

Deficit, under Canadian GAAP	$	(41,644,409	)	$	(39,385,746	)
Add: gain on disposal of uranium properties		5,652,166			5,652,166
Less: exploration costs - unproven resource property expenditures		(6,265,184	)		(6,265,184	)
Add: Uranium properties impairment under Canadian GAAP		148,906			148,906
Less: Uranium properties impairment under US GAAP		(17,602	)		(17,602	)
Less: flow through share future tax recovery under Canadian GAAP		(4,669,883	)		(4,669,883	)
Add: flow through share future tax recovery under US GAAP		185,000			185,000
Add: Resource properties depletion under Canadian GAAP		11,467,781			10,018,351
Add: Resource properties impairment under Canadian GAAP		3,955,854			3,955,854
Less: Resource properties depletion under US GAAP		(10,835,701	)		(8,782,402	)
Less: Resource properties impairment under US GAAP		(15,807,960	)		(15,807,960	)

Deficit, under US GAAP	$	(57,831,032	)	$	(54,968,500	)

5. Net loss for the period

	For the six months ended June 30,
	2010			2009			2008

Net loss for the period, under Canadian GAAP	$	(2,258,663	)	$	(3,229,930	)	$	(2,700,910	)
Less: flow through share future tax recovery under Canadian GAAP		-			-			(536,900	)
Add: flow through share future tax recovery under US GAAP		-			-			70,000
Add: Resource properties depletion under Canadian GAAP		1,449,430			3,949,839			187,335
Less: Resource properties depletion under US GAAP		(2,053,299	)		(4,471,822	)		(317,576	)

Net loss for the period, under US GAAP	$	(2,862,532	)	$	(3,751,913	)	$	(3,298,051	)

124

DEJOUR ENTERPRISES LTD.

RECONCILIATION BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED

ACCOUNTING PRINCIPLES (“US GAAP”)

For the Six Months Ended June 30, 2010

Unaudited – Prepared by management and have not been reviewed by the Company’s auditor

The application of US GAAP would have the following effects on reported net income:

6. Reported Net Loss

	For the six months ended June 30,
	2010			2009			2008

Net loss for the period, under Canadian GAAP	$	(2,258,663	)	$	(3,229,930	)	$	(2,700,910	)
Adjustments:
Less: flow through share future tax recovery under Canadian GAAP (note 21(d))		-			-			(536,900	)
Add: flow through share future tax recovery under US GAAP (note 21(d))		-			-			70,000
Add: Resource properties depletion under Canadian GAAP		1,449,430			3,949,839			187,335
Less: Resource properties depletion under US GAAP (note 21(a))		(2,053,299	)		(4,471,822	)		(317,576	)

Net loss for the period, under US GAAP	$	(2,862,532	)	$	(3,751,913	)	$	(3,298,051	)

Net loss per share - Basic	$	(0.03	)	$	(0.47	)	$	(0.44	)

Net loss per share - Diluted	$	(0.03	)	$	(0.47	)	$	(0.44	)

Weighted Average Number of Common Shares Outstanding - Basic		98,220,180			74,034,042			70,825,257

Weighted Average Number of Common Shares Outstanding - Diluted		98,220,180			74,034,042			70,825,257

Deficit, beginning of the period, under US GAAP	$	(54,968,500	)	$	(44,514,964	)	$	(10,334,076	)
Net loss, under US GAAP		(2,862,532	)		(3,751,913	)		(3,298,051	)

Deficit, end of the period, under US GAAP	$	(57,831,032	)	$	(48,266,877	)	$	(13,632,127	)

125

DEJOUR ENTERPRISES LTD.

RECONCILIATION BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED

ACCOUNTING PRINCIPLES (“US GAAP”)

For the Six Months Ended June 30, 2010

Unaudited – Prepared by management and have not been reviewed by the Company’s auditor

7. Balance Sheets

June 30, 2010	Canadian GAAP			Unproved Properties			Depletion and Depreciation and Impairment			Flow-through Shares			US GAAP

ASSETS
Current
Cash and cash equivalents	$	3,019,692		$	-		$	-		$	-		$	3,019,692
Accounts receivable		1,367,589			-			-			-			1,367,589
Prepaids and deposits		514,293			-			-			-			514,293
Unrealized financial instrument gain		27,385			-			-			-			27,385

		4,928,959			-			-			-			4,928,959
Equipment		101,705			-			-			-			101,705
Uranium properties		533,085			(481,714	)		-			-			51,371
Oil and gas properties		42,977,023			-			(11,220,026	)		-			31,756,997

	$	48,540,772		$	(481,714	)	$	(11,220,026	)	$	-		$	36,839,032

LIABILITIES
Current
Bank line of credit and bridge loan	$	3,500,000		$	-		$	-		$	-		$	3,500,000
Accounts payable and accrued liabilities		3,674,219			-			-			-			3,674,219
Loans from related parties		2,401,735			-			-			-			2,401,735

		9,575,954			-			-			-			9,575,954
Deferred leasehold inducement		35,810			-			-			-			35,810
Asset retirement obligations		276,884			-			-			-			276,884
Future income tax liabilities		-			-			-			285,570			285,570

		9,888,648			-			-			285,570			10,174,218

SHAREHOLDERS' EQUITY
Share capital		73,339,520			-			-			4,199,313			77,538,833
Contributed surplus		6,929,628			-			-			-			6,929,628
Deficit		(41,644,409	)		(481,714	)		(11,220,026	)		(4,484,883	)		(57,831,032	)
Accumulated other comprehensive income		27,385			-			-			-			27,385

		38,652,124			(481,714	)		(11,220,026	)		(285,570	)		26,664,814

	$	48,540,772		$	(481,714	)	$	(11,220,026	)	$	-		$	36,839,032

126

DEJOUR ENTERPRISES LTD.

RECONCILIATION BETWEEN CANADIAN AND UNITED STATES GENERALLY ACCEPTED

ACCOUNTING PRINCIPLES (“US GAAP”)

For the Six Months Ended June 30, 2010

Unaudited – Prepared by management and have not been reviewed by the Company’s auditor

7. Balance Sheets

December 31, 2009	Canadian GAAP			Unproved Properties			Depletion and Depreciation and Impairment			Flow-through Shares				US GAAP

ASSETS
Current
Cash and cash equivalents	$	2,732,696		$	-		$	-			$	-			$	2,732,696
Accounts receivable		724,773			-			-				-				724,773
Prepaids and deposits		555,672			-			-				-				555,672

		4,013,141			-			-				-				4,013,141

Property and equipment		114,747			-			-				-				114,747
Uranium properties		533,085			(481,714	)		-				-				51,371
Oil and gas properties		41,224,903			-			(10,616,157	)			-				30,608,746

	$	45,885,876		$	(481,714	)	$	(10,616,157	)		$	-			$	34,788,005

LIABILITIES
Current
Bank indebtedness and line of credit	$	850,000		$	-		$	-			$	-			$	850,000
Accounts payable and accrued liabilities		2,653,483			-			-				271,033				2,924,516
Unrealized financial instrument loss		99,894			-			-				-				99,894

		3,603,377			-			-				271,033				3,874,410
Loans from related parties		2,345,401			-			-				-				2,345,401
Deferred leasehold inducement		39,913			-			-				-				39,913
Asset retirement obligations		208,516			-			-				-				208,516

		6,197,207			-			-				271,033				6,468,240

SHAREHOLDERS' EQUITY
Share capital		72,559,504			-			-				4,213,850				76,773,354
Contributed surplus		6,614,805			-			-				-				6,614,805
Deficit		(39,385,746	)		(481,714	)		(10,616,157	)			(4,484,883	)			(54,968,500	)
Accumulated other comprehensive income		(99,894	)		-			-				-				(99,894	)

		39,688,669			(481,714	)		(10,616,157	)			(271,033	)			28,319,765

	$	45,885,876		$	(481,714	)	$	(10,616,157	)		$	(0	)		$	34,788,005

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DXIEF DXI Capital Corporation (CE)