UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 20-F

[   ]  REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934 OR

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

For the fiscal year ended December 31, 2013

OR

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

For the transition period from ____ to ______

OR

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

Date of event requiring this shell company report:

Commission file number: 001-33491

 
DEJOUR ENERGY INC.
(Exact name of Registrant as specified in its charter)

Province of British Columbia, Canada
(Jurisdiction of incorporation or organization)

598 - 999 Canada Place
Vancouver, British Columbia V6C 3E1
(Address of principal executive offices)

David N. Matheson
598 - 999 Canada Place
Vancouver, British Columbia V6C 3E1
Tel: (604) 638-5050
Facsimile: (604) 638-5051
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class Name of each exchange on which registered
Common Shares, without par value NYSE Amex Equities

Securities registered pursuant to Section 12(g) of the Act: None


Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

Indicate the number of outstanding shares of each of the Registrant’s classes of capital or common stock as of the close of the period covered by the annual report: 163,753,874 common shares as at April 24, 2014

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

If this report is an annual or transition report, indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
Yes [  ]     No [X]

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [X]     No [  ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes [X]      No [   ]

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one)

Large accelerated filer     [  ]       Accelerated filer    [  ]       Non-accelerated filer [X]

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP [   ] International Financial Reporting Standards as issued Other [X]
by the International Accounting Standards Board [   ]

If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow:
Item 17 [  ]      Item 18 [  ]  

If this is an annual report, indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [  ]    No [X]


TABLE OF CONTENTS

GENERAL INFORMATION 4
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS 4
CURRENCY AND EXCHANGE RATES 6
ABBREVIATIONS 6
PART I 8
ITEM 1.      IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS. 8
ITEM 2.      OFFER STATISTICS AND EXPECTED TIMETABLE 8
ITEM 3.      KEY INFORMATION 8
ITEM 4.      INFORMATION ON THE COMPANY 20
ITEM 4A.   UNRESOLVED STAFF COMMENTS 40
ITEM 5.      OPERATING AND FINANCIAL REVIEW AND PROSPECTS 40
ITEM 6.      DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES. 50
ITEM 7.      MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS. 64
ITEM 8.      FINANCIAL INFORMATION. 67
ITEM 9.      THE OFFER AND LISTING 68
ITEM 10.    ADDITIONAL INFORMATION 70
ITEM 11.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 87
ITEM 12.    DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES 89
PART II 90
ITEM 13.    DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES 90
ITEM 14.    MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS 90
ITEM 15.    CONTROLS AND PROCEDURES 90
ITEM 16.    [RESERVED] 90
ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT 90
ITEM 16B. CODE OF ETHICS 90
ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES 91
ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES 91
ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS 92
ITEM 16F. CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT 92
ITEM 16G. CORPORATE GOVERNANCE 92
ITEM 16H. MINE SAFETY DISCLOSURE 92
PART III 94
ITEM 17.    FINANCIAL STATEMENTS 94
ITEM 18.    FINANCIAL STATEMENTS 94
ITEM 19.    EXHIBITS 95
SIGNATURES 96


GENERAL INFORMATION

All references in this annual report on Form 20-F to the terms “we”, “our”, “us”, “the Company” and “Dejour” refer to Dejour Energy Inc.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This annual report on Form 20-F and the documents incorporated herein by reference contain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements concern our anticipated results and developments in our operations in future periods, planned exploration and, if warranted, development of our properties, plans related to our business and other matters that may occur in the future. These statements relate to analyses and other information that are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of management.

Any statements that express or involve discussions with respect to predictions, expectations, beliefs, plans, projections, objectives, assumptions or future events or performance (often, but not always, using words or phrases such as “expects” or “does not expect”, “is expected”, “anticipates” or “does not anticipate”, “plans”, “estimates” or “intends”, or stating that certain actions, events or results “may”, “could”, “would”, “might” or “will” be taken, occur or be achieved) are not statements of historical fact and may be forward-looking statements. The forward-looking statements contained in this annual report on Form 20-F concern, among other things:

These statements relate to analyses and other information that are based on forecasts of future results, estimates of amounts not yet determinable and assumptions of our management.

4


Forward-looking statements are subject to a variety of known and unknown risks, uncertainties and other factors that could cause actual events or results to differ from those expressed or implied by the forward-looking statements, including, without limitation:

5


This list is not exhaustive of the factors that may affect any of our forward-looking statements. Some of the important risks and uncertainties that could affect forward-looking statements are described further under the section heading “Item 3. Key Information – D. Risk Factors” below. If one or more of these risks or uncertainties materializes, or if underlying assumptions prove incorrect, our actual results may vary materially from those expected, estimated or projected. Forward-looking statements in this document are not a prediction of future events or circumstances, and those future events or circumstances may not occur. Given these uncertainties, users of the information included herein, including investors and prospective investors are cautioned not to place undue reliance on such forward-looking statements. Investors should consult our quarterly and annual filings with Canadian and U.S. securities commissions for additional information on risks and uncertainties relating to forward-looking statements. We do not assume responsibility for the accuracy and completeness of these statements.

Forward-looking statements are based on our beliefs, opinions and expectations at the time they are made, and we do not assume any obligation to update our forward-looking statements if those beliefs, opinions, or expectations, or other circumstances, should change, except as required by applicable law.

We qualify all the forward-looking statements contained in this annual report on Form 20-F by the foregoing cautionary statements.

CURRENCY AND EXCHANGE RATES

Canadian Dollars Per U.S. Dollar

Unless otherwise indicated, all references in this annual report are to Canadian dollars ("$" or "Cdn$"). Certain numbers in this annual report are rounded to the nearest thousands of Canadian dollars.

The following tables set forth the number of Canadian dollars required to buy one United States dollar (US$) based on the average, high and low nominal noon exchange rate as reported by the Bank of Canada for each of the last five fiscal years and each of the last six months. The average rate means the average of the exchange rates on the last day of each month during the period.

  Canadian Dollars Per One U.S. Dollar
  2013 2012 2011 2010 2009
Average for the period 1.0299 0.9996 0.9891 1.0345 1.1416


March
2014
February
2014
January
2014
December
2013
November
2013
October
2013
High for the period 1.1251 1.1140 1.1171 1.0697 1.0599 1.0456
Low for the period 1.0966 1.0953 1.0614 1.0577 1.0415 1.0284

Exchange rates are based on the Bank of Canada nominal noon exchange rates. The nominal noon exchange rate on April 24, 2014 as reported by the Bank of Canada for the conversion of United States dollars into Canadian dollars was US$1.00 = Cdn$1.1027.

ABBREVIATIONS

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

6



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.

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.

7


PART I

ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

Not applicable.

ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.

ITEM 3. KEY INFORMATION

A.             Selected Financial Data

Our selected financial data and the information in the following tables for the years ended December 31, 2009 - 2013 was derived from our audited consolidated financial statements. These audited consolidated financial statements have been audited by BDO Canada LLP, Chartered Accountants, for the years ended December 31, 2013, 2012, 2011 and 2010, and Dale Matheson Carr-Hilton LaBonte LLP, Chartered Accountants, for the year ended December 31, 2009. Certain prior years’ comparative figures have been reclassified, if necessary.

The information in the following table should be read in conjunction with the information appearing under the heading “Item 5. Operating and Financial Review and Prospects” and our audited consolidated financial statements under the heading "Item 18. Financial Statements".

On January 1, 2011, the Company adopted International Financial Reporting Standards (“IFRS”) for financial reporting purposes, using a transition date of January 1, 2010. The Company’s annual audited Consolidated Financial Statements for the year ended December 31, 2011, including 2010 required comparative information, have been prepared in accordance with IFRS, as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”). Financial statements prior to the fiscal year ended December 31, 2010 were prepared in accordance with pre-changeover Canadian generally accepted accounting principles (“Canadian GAAP”).

Financial information included in this annual report on Form 20-F for the years 2013, 2012, 2011 and 2010 is determined using IFRS, which differ from U.S. GAAP and Canadian GAAP. Unless otherwise indicated, financial information included in this annual report on Form 20-F prior to year 2010 were in accordance with Canadian GAAP.

We have not declared any dividends since incorporation and do not anticipate that we will do so in the foreseeable future. Our present policy is to retain all available funds for use in our operations and the expansion of our business.

8


The following table is a summary of selected audited consolidated financial information of the Company for each of the four most recently completed financial years. The information presented is presented in accordance with IFRS:

(CA$ thousands, except per share data) Years Ended December 31,
  2013 2012   2011     2010
Gross Oil and Gas Revenue $9,317 $6,882 $8,824 $8,086
Net Loss for the Year ($2,577) ($11,753) ($11,043) ($5,124)
Loss Per Share ($0.017) ($0.083) ($0.092) ($0.051)
Dividends Per Share Nil Nil Nil Nil
Weighted Avg. Shares, basic (,000) 148,916 141,056 120,300 99,789
Weighted Avg. Shares, diluted (,000) 148,916 141,056 120,300 99,789
Year-end Shares (,000) 148,916 148,916 126,892 110,181
Working Capital (Deficiency) ($8,908) ($8,557) ($7,756) ($3,264)
Resource properties and equipment $23,667 $25,033 $25,043 $24,432
Long-term Liabilities $6,107 $6,622 $1,383 $738
Share Capital $90,274 $90,274 $85,076 $79,386
Retained Earnings (Deficit) ($90,839) ($88,262) ($76,510) ($65,467)
Total Assets $25,499 $27,573 $29,438 $30,413

The following table is a summary of selected audited consolidated financial information of the Company for the fiscal year ended December 31, 2009. The information presented is presented in accordance with Canadian GAAP and is not comparable to the financial information presented in accordance with IFRS.

(Cdn$ in 000, except per share data) Year Ended December 31, 2009
Revenue (Oil and natural gas) $6,471
Net Loss for the Year ($12,807)
Loss Per Share ($0.162)
Dividends Per Share Nil
Weighted Avg. Shares, basic (,000) 78,926
Weighted Avg. Shares, diluted (,000) 78,926
Year-end Shares (,000) 95,791
Working Capital (Deficiency) ($20)
Resource Properties $41,758
Long-term Liabilities $2,594
Share Capital $72,560
Retained Earnings (Deficit) ($39,386)
Total Assets $45,886

9


Canadian GAAP Adjusted to United States Generally Accepted Accounting Principles

Under U.S. GAAP the following financial information would be adjusted from Canadian GAAP, and certain prior years’ comparative figures have been reclassified or restated, if necessary. The following table is a summary of selected audited consolidated financial information of the Company for the fiscal year ended December 31, 2009. The information presented is in accordance with U.S. GAAP:

(Cdn$ in 000, except per share data) Year Ended December 31, 2009
Net Loss for the Year ($10,270)
Loss Per Share ($0.13)
Resource Properties $31,041
Retained Earnings (Deficit) ($54,785)
Total Assets $35,169

Exchange Rate History

See the disclosure under the heading "Currency and Exchange Rates" above.

Recently Adopted Accounting Policies and Future Accounting Pronouncements

IFRS

On January 1, 2011, we adopted IFRS and the accounting policies have been applied in preparing the consolidated financial statements for the years ended December 31, 2013, 2012 and 2011. The detail accounting policies in accordance with IFRS were disclosed in Note 3 of the Company’s audited consolidated financial statements.

Future Accounting Pronouncements

Certain pronouncements were issued by the International Accounting Standards Board (“IASB”) or the International Financial Reporting Interpretations Committee (“IFRIC”) that are mandatory for accounting periods beginning after January 1, 2014 or later periods.

The following new standards, amendments and interpretations, have not been early adopted in these consolidated annual financial statements. The Company is currently assessing the impact, if any, of this new guidance on the Company’s future results and financial position:

IFRS 9, Financial Instruments is part of the IASB's wider project to replace IAS 39 Financial Instruments: Recognition and Measurement. IFRS 9 retains but simplifies the mixed measurement model and establishes two primary measurement categories for financial assets: amortized cost and fair value. The basis of classification depends on the entity's business model and the contractual cash flow characteristics of the financial asset. The amendments to IFRS 9 will be effective as of January 1, 2018. The Company will continue to monitor the changes to this standard as they arise and will be determined the impact accordingly.

IAS 36, Impairment of Assets was amended in May 2013. This standard reduces the circumstances in which the recoverable amount of CGUs is required to be disclosed and clarify the disclosures required when an impairment loss has been recognized or reversed in the period. The amendments to IAS 36 are effective as of January 1, 2014.

B.             Capitalization and Indebtedness

Not Applicable.

C.             Reasons for the Offer and Use of Proceeds

Not Applicable.

D.             Risk Factors

10


An investment in a company engaged in oil and gas exploration involves an unusually high amount of risk, both unknown and known, present and potential, including, but not limited to the risks enumerated below. An investment in our common shares is highly speculative and subject to a number of known and unknown risks. Only those persons who can bear the risk of the entire loss of their investment should purchase our securities. An investor should carefully consider the risks described below and the other information that we file with the SEC and with Canadian securities regulators before investing in our common shares. The risks described below are not the only ones faced. Additional risks that we are not currently aware of or that we currently believe are immaterial may become important factors that affect our business. The risk factors set forth below and elsewhere in this annual report, and the risks discussed in our other filings with the SEC and Canadian securities regulators, may have a significant impact on our business, financial condition and/or results of operations and could cause actual results to differ materially from those projected in any forward-looking statements. See “Cautionary Note Regarding Forward-Looking Statements”.

Our failure to successfully address the risks and uncertainties described below would have a material adverse effect on our business, financial condition and/or results of operations, and the trading price of our common stock may decline and investors may lose all or part of their investment. We cannot assure you that we will successfully address these risks or other unknown risks that may affect our business.

Risks related to commodity price fluctuations

The marketability and price of oil and natural gas are affected by numerous factors outside of our control. Material fluctuations in oil and natural gas prices could adversely affect our net production revenue and oil and natural gas operations.

Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

  • the domestic and foreign supply of and demand for oil and natural gas;
  • the price and quantity of imports of crude oil and natural gas;
  • overall domestic and global economic conditions;
  • political and economic conditions in other oil and natural gas producing countries, including embargoes and continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage;
  • the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
  • the level of consumer product demand;
  • weather conditions;
  • the impact of the U.S. dollar exchange rates on oil and natural gas prices; and
  • the price and availability of alternative fuels.

Our ability to market our oil and natural gas depends upon our ability to acquire space on pipelines that deliver such commodities to commercial markets. We are also affected by deliverability uncertainties related to the proximity of our reserves to pipelines and processing and storage facilities and operational problems affecting such pipelines and facilities, as well as extensive governmental regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business.

Both oil and natural gas prices are unstable and are subject to fluctuation. Any material decline in prices could result in a reduction of our net production revenue. The economics of producing from some wells may change as a result of lower prices, which could result in reduced production of oil or natural gas and a reduction in the volumes and net present value of our reserves. We might also elect not to produce from certain wells at lower prices. All of these factors could result in a material decrease in our net production revenue and a reduction in our oil and natural gas acquisition, development and exploration activities.

Because world oil and natural gas prices are quoted in U.S. dollars, our production revenues could be adversely affected by an appreciation of the Canadian dollar.

11


World oil and natural gas prices are quoted in U.S. dollars, and the price received by Canadian producers, including us, is therefore affected by the Canadian/U.S. dollar exchange rate, which will fluctuate over time. In recent years, the Canadian dollar has increased materially in value against the U.S. dollar, which may negatively affect our production revenues. Further material increases in the value of the Canadian dollar would exacerbate this potential negative effect and could have a material adverse effect on our financial condition and results of operations. An increase in the exchange rate for the Canadian dollar and future Canadian/U.S. exchange rates could also negatively affect the future value of our reserves as determined by independent petroleum reserve engineers.

Risks related to operating an exploration, development and production company

Our ability to execute projects will depend on certain factors outside of our control. If we are unable to execute projects on time, on budget or at all, we may not be able to effectively market the oil and natural gas that we produce.

We manage a variety of small and large projects in the conduct of our business. Our ability to execute projects and market oil and natural gas will depend upon numerous factors beyond our control, including:

  • the availability of adequate financing;
  • the availability of processing capacity;
  • the availability and proximity of pipeline capacity;
  • the availability of storage capacity;
  • the supply of and demand for oil and natural gas;
  • the availability of alternative fuel sources;
  • the effects of inclement weather;
  • the availability of drilling and related equipment;
  • accidental events;
  • currency fluctuations;
  • changes in governmental regulations; and
  • the availability and productivity of skilled labor.

Because of these factors, we could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil and natural gas that we produce.

Oil and gas exploration has a high degree of risk and our exploration efforts may be unsuccessful, which would have a negative effect on our operations.

There is no certainty that the expenditures to be made by us in the exploration of our current projects, or any additional project interests we may acquire, will result in discoveries of recoverable oil and gas in commercial quantities. An exploration project may not result in the discovery of commercially recoverable reserves and the level of recovery of hydrocarbons from a property may not be a commercially recoverable (or viable) reserve that can be legally and economically exploited. If exploration is unsuccessful and no commercially recoverable reserves are defined, we would be required to evaluate and acquire additional projects that would require additional capital, or we would have to cease operations altogether.

Cumulative unsuccessful exploration efforts could result in us having to cease operations.

The expenditures to be made by us in the exploration of our properties may not result in discoveries of oil and natural gas in commercial quantities. Many exploration projects do not result in the discovery of commercially recoverable oil and gas deposits, and this occurrence could ultimately result in us having to cease operations.

Oil and natural gas operations involve many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, our business, financial condition, results of operations and prospects could be adversely affected.

Our involvement in the oil and natural gas exploration, development and production business subjects us to all of the risks and hazards typically associated with those types of operations, including hazards such as fire, explosion, blowouts, sour gas releases and spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or personal injury. In particular, we may explore for and produce sour natural gas in certain areas. An unintentional leak of sour natural gas could result in personal injury, loss of life or damage to property, and may necessitate an evacuation of populated areas, all of which could result in liability to us. In accordance with industry practice, we are not fully insured against all of these risks. Although we maintain liability insurance in an amount that we consider consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event we could incur significant costs that could have a material adverse effect upon our business, financial condition, results of operations and prospects. In addition, the risks we face are not, in all circumstances, insurable and, in certain circumstances, we may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. For instance, we do not have insurance to protect against the risk from terrorism. Oil and natural gas production operations are also subject to all of the risks typically associated with those operations, including encountering unexpected geologic formations or pressures, premature decline of reservoirs and the invasion of water into producing formations. Losses resulting from the occurrence of any of these risks could have a material adverse effect on our business, financial condition, results of operations and prospects.

12


Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity.

The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns. Oil and natural gas development activities, including seismic and drilling programs in northern Alberta and British Columbia, are restricted to those months of the year when the ground is frozen. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. In addition, certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain, and additional seasonal weather variations will also affect access to these areas. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity during certain parts of the year.

The petroleum industry is highly competitive, and increased competitive pressures could adversely affect our business, financial condition, results of operations and prospects.

The petroleum industry is competitive in all of its phases. We compete with numerous other organizations in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural gas. Our competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than us. Our ability to increase our reserves in the future will depend not only upon our ability to explore and develop our present properties, but also upon our ability to select and acquire other suitable producing properties or prospects for exploratory drilling. Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery and storage.

We do not control all of the assets that are used in the operation of our business and, therefore, cannot ensure that those assets will be operated in a manner favorable to us.

Other companies operate some of the assets in which we have an interest. As a result, we have a limited ability to exercise influence over the operation of those assets or their associated costs, which could adversely affect our financial performance. Our return on assets operated by others will therefore depend upon a number of factors that may be outside of our control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants, the selection of technology and risk management practices.

Our ability to market oil and natural gas depends on our ability to transport our product to market. If we are unable to expand and develop the infrastructure in the areas surrounding certain of our assets, we may not be able to effectively market the oil and natural gas that we produce.

Due to the location of some of our assets, both in Canada and the United States, there is minimal infrastructure currently available to transport oil and natural gas from our existing and future wells to market. As a result, even if we are able to engage in successful exploration and production activities, we may not be able to effectively market the oil and natural gas that we produce, which could adversely affect our business, financial condition, results of operations and prospects.

Demand and competition for drilling equipment could delay our exploration and production activities, which could adversely affect our business, financial condition, results of operations and prospects.

13


Oil and natural gas exploration and development activities depend upon the availability of drilling and related equipment (typically leased from third parties) in the particular areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment to us and may delay exploration and development activities. To the extent we are not the operator of our oil and natural gas properties, we depend upon the operators of the properties for the timing of activities related to the properties and are largely unable to direct or control the activities of the operators.

Title to our oil and natural gas producing properties cannot be guaranteed and may be subject to prior recorded or unrecorded agreements, transfers, claims or other defects.

Although title reviews may be conducted prior to the purchase of oil and natural gas producing properties or the commencement of drilling wells, those reviews do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat our claim. Unregistered agreements or transfers, or native land claims, may affect title. If title is disputed, we will need to defend our ownership through the courts, which would likely be an expensive and protracted process and have a negative effect on our operations and financial condition. In the event of an adverse judgment, we would lose our property rights. A defect in our title to any of our properties may have a material adverse effect on our business, financial condition, results of operations and prospects.

We may be unable to meet all of the obligations necessary to successfully maintain each of the licenses and leases and working interests in licenses and leases related to our properties, which could adversely affect our business, financial condition, results of operations and prospects.

Our properties are held in the form of licenses and leases and working interests in licenses and leases. If we or the holder of the license or lease fails to meet the specific requirement of a license or lease, the license or lease may terminate or expire. None of the obligations required to maintain each license or lease may be met. The termination or expiration of our licenses or leases or the working interests relating to a license or lease may have a material adverse effect on our business, financial condition, results of operations and prospects.

Risks related to financing continuing and future operations

We have a working capital deficiency and will be required to raise capital through financings. We may not be able to obtain capital or financing on satisfactory terms, or at all.

As of December 31, 2013, the Company had a working capital deficiency of approximately $8.9 million. Excluding the non-cash warrant liability of $0.3 million related to the fair value of US$ denominated warrants issued in current and previous equity financings, the non-cash derivative liability of $0.3 million related to the fair value of warrants issued in the loan facility which closed in June 2013 and the non-current portion of financial contract liability of $1.2 million, the working capital deficiency mainly consists of a $2.9 million outstanding demand line of credit (maximum amount of line - $3.5 million) and $2.9 million attributable to the outstanding loan facility. We expect to incur general and administration expenses of approximately $3.0 million over the next twelve months. Our loan facility in the combined amount of $3.5 million is due and payable on December 22, 2014. We cannot assure you that debt or equity financing will be available to us, and even if debt or equity financing is available, it may not be on terms acceptable to us. Our inability to access sufficient capital for our operations would have a material adverse effect on our business, financial condition, results of operations and prospects.

The Company's ability to continue as a going concern is dependent upon attaining profitable operations and obtaining sufficient financing to meet obligations and continue exploration and development activities. Whether and when the Company can attain profitability is uncertain. These uncertainties cast substantial doubt upon the Company’s ability to continue as going concern.

During the year ended December 31, 2013, the Company incurred a loss of $2.6 million and has an accumulated deficit of $90.8 million. Whether and when the Company can attain profitability is uncertain. The Company also has a working capital deficiency of $8.9 million as at December 31, 2013. These uncertainties cast substantial doubt upon the Company’s ability to continue as going concern in the next twelve months, because we will be required to obtain additional capital in the future to continue our operations and there is no assurance that we will be able to obtain such capital, through equity or debt financing, or any combination thereof, or on satisfactory terms or at all. Our independent auditors have included an explanatory paragraph in their report on our consolidated financial statements for the year ended December 31, 2013 that describes uncertainties that cast substantial doubt about our ability to continue as a going concern. Our audited consolidated financial statements have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board applicable to a going concern, which implies we will continue to meet our obligations and continue our operations for the next twelve months. Realization values may be substantially different from carrying values as shown, and our consolidated financial statements do not include any adjustments relating to the recoverability or classification of recorded asset amounts or the amount and classification of liabilities that might be necessary as a result of the going concern uncertainty.

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On November 21, 2013, the Company was advised by NYSE Regulation representing NYSE MKT LLC (“NYSE MKT” or “the Exchange”) that a review of the Company’s Form 6K for the period ended September 30, 2013 indicates the Company is not in compliance with three of the Exchange’s continued listing standards relating to minimum stockholders’ equity thresholds, consecutive annual net losses, and general “going concern” issues.

The Company has followed the procedures required by the Exchange to resolve these issues and, on April 17, 2014, NYSE Regulation reported that, in accordance with the NYSE’s Company Guide, the Company has made a reasonable demonstration of its ability to regain compliance with the Exchange’s “going concern” issues. The Company has committed to update NYSE Regulation as to its’ financial progress until full compliance is achieved on or before May 22, 2015, the target date for full compliance established by the Exchange.

We anticipate making substantial capital expenditures for future acquisition, exploration, development and production projects. We may not be able to obtain capital or financing necessary to support these projects on satisfactory terms, or at all.

We anticipate making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. If our revenues or reserves decline, we may not have access to the capital necessary to undertake or complete future drilling programs. Debt or equity financing, or cash generated by operations, may not be available to us or may not be sufficient to meet our requirements for capital expenditures or other corporate purposes. Even if debt or equity financing is available, it may not be on terms acceptable to us. Our inability to access sufficient capital for our operations could have a material adverse effect on our business, financial condition, results of operations and prospects.

Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times, thereby causing us to forfeit our interest in certain properties, miss certain acquisition opportunities and reduce or terminate our operations.

Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times and we are currently utilizing our bank line of credit to fund our working capital deficit. From time to time, we may require additional financing in order to carry out our oil and gas acquisition, exploration and development activities. Failure to obtain such financing on a timely basis could cause us to forfeit its interest in certain properties, not be able to take advantage of certain acquisition opportunities and reduce or terminate our level of operations. If our revenues from our reserves decrease as a result of lower oil and natural gas prices or otherwise, our ability to expend the necessary capital to replace our reserves or to maintain our production will be impaired. If our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or, if available, on favorable terms.

Debt that we incur in the future may limit our ability to obtain financing and to pursue other business opportunities, which could adversely affect our business, financial condition, results of operations and prospects.

From time to time, we may enter into transactions to acquire assets or equity of other organizations. These transactions may be financed in whole or in part with debt, which may increase our debt levels above industry standards for oil and natural gas companies of a similar size. Depending upon future exploration and development plans, we may require additional equity and/or debt financing that may not be available or, if available, may not be available on acceptable terms. None of our organizational documents currently limit the amount of indebtedness that we may incur. The level of our indebtedness from time to time could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.

We may be exposed to the credit risk of third parties through certain of our business arrangements. Non-payment or non-performance by any of these third parties could have an adverse effect on our financial condition and results of operations.

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We may be exposed to third-party credit risk through our contractual arrangements with our current or future joint venture partners, marketers of our petroleum and natural gas production and other parties. In the event those entities fail to meet their contractual obligations to us, those failures could have a material adverse effect on our financial condition and results of operations. In addition, poor credit conditions in the industry and of joint venture partners may affect a joint venture partner's willingness to participate in our ongoing capital program, potentially delaying the program and the results of the program until we find a suitable alternative partner.

Risks related to maintaining reserves and acquiring new sources of oil and natural gas

Our success depends upon our ability to find, acquire, develop and commercially produce oil and natural gas, which depends upon factors outside of our control.

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Our long-term commercial success depends upon our ability to find, acquire, develop and commercially produce oil and natural gas. We have only recently commenced production of oil and natural gas. There is no assurance that our other properties or future properties will achieve commercial production. Without the continual addition of new reserves, our existing reserves and our production will decline over time as our reserves are exploited. A future increase in our reserves will depend not only upon our ability to explore and develop any properties we may have from time to time, but also upon our ability to select and acquire new suitable producing properties or prospects. No assurance can be given that we will be able to locate satisfactory properties for acquisition or participation. Moreover, if acquisitions or participations are identified, we may determine that current market conditions, the terms of any acquisition or participation arrangement, or pricing conditions, may make the acquisitions or participations uneconomical, and further commercial quantities of oil and natural gas may not be produced, discovered or acquired by us, any of which could have a material adverse effect on our business, financial condition, results of operations and prospects.

Properties that we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

Our long-term commercial success depends upon our ability to find, acquire, develop and commercially produce oil and natural gas reserves. However, our review of acquired properties is inherently incomplete, as it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in the reserve estimates or the underlying assumptions may adversely affect the quantities and present value of our reserves.

There are numerous uncertainties inherent in estimating quantities of oil, natural gas reserves and the future cash flows attributed to the reserves. Our reserve and associated cash flow estimates are estimates only. In general, estimates of economically recoverable oil and natural gas reserves and the associated future net cash flows are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results. All estimates are to some degree speculative, and classifications of reserves are only attempts to define the degree of speculation involved. For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. Our actual production, revenues, taxes and development and operating expenditures with respect to our reserves will vary from our estimates of them, and those variations could be material.

Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Recovery factors and drainage areas are estimated by experience and analogy to similar producing pools. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves, and those variations could be material.

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Our future oil and natural gas production may not result in revenue increases and may be adversely affected by operating conditions, production delays, drilling hazards and environmental damages.

Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but also from wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.

Risks related to management of the Company

We may experience difficulty managing our anticipated growth.

We may be subject to growth-related risks including capacity constraints and pressure on our internal systems and controls. Our ability to manage growth effectively will require us to continue to implement and improve our operational and financial systems and to attract and retain qualified management and technical personnel to meet the needs of our anticipated growth. Our inability to deal with this growth could have a material adverse effect on our business, financial condition, results of operations and prospects.

We depend upon key personnel and the absence of any of these individuals could result in us having to cease operations.

Our ability to continue our operation business depends, in large part, upon our ability to attract and maintain qualified key management and technical personnel. Competition for such personnel is intense and we may not be able to attract and retain such personnel.

Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.

Our ability to successfully acquire additional licenses, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements depends on developing and maintaining close working relationships with industry participants and government officials and on our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

We cannot be certain that current expected expenditures and any current or planned completion/testing programs will be realized.

We believe that the costs used to prepare internal budgets are reasonable, however, there are assumptions, uncertainties, and risk that may cause our allocated funds on a per well basis to change as a result of having to alter certain activities from those originally proposed or programmed to reduce and mitigate uncertainties and risks. These assumptions, uncertainties, and risks are inherent in the completion and testing of wells and can include but are not limited to: pipe failure, casing collapse, unusual or unexpected formation pressure, environmental hazards, and other operating or production risk intrinsic in oil and or gas activities. Any of the above may cause a delay in any of our completion/testing programs or our ability to determine reserve potential.

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Risks related to federal, state, local and other laws, controls and regulations

We are subject to complex federal, provincial, state, local and other laws, controls and regulations that could adversely affect the cost, manner and feasibility of conducting our oil and natural gas operations.

Oil and natural gas exploration, production, marketing and transportation activities are subject to extensive controls and regulations imposed by various levels of government, which may be amended from time to time. Governments may regulate or intervene with respect to price, taxes, royalties and the exportation of oil and natural gas. Regulations may be changed from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for crude oil and natural gas and increase our costs, any of which may have a material adverse effect on our business, financial condition, results of operations and prospects. In addition, in order to conduct oil and natural gas operations, we require licenses from various governmental authorities. We cannot assure you that we will be able to obtain all of the licenses and permits that may be required to conduct operations that we may desire to undertake.

There is uncertainty regarding claims of title and rights of the aboriginal people to properties in certain portions of western Canada, and such a claim, if made in respect of our property or assets, could adversely affect our business, financial condition, results of operations and prospects.

Aboriginal peoples have claimed aboriginal title and rights to a substantial portion of western Canada. We are not aware that any claims have been made in respect of its property and assets. However, if a claim arose and was successful it would have an adverse effect on our business, financial condition, results of operations and prospects.

We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities, which could adversely affect our business, financial condition, results of operations and prospects.

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation under a variety of federal, provincial, state and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with legislation can require significant expenditures, and a breach of applicable environmental legislation may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy any discharge. Environmental laws may result in a curtailment of production or a material increase in the costs of production, development or exploration activities, or otherwise adversely affect our business, financial condition, results of operations and prospects.

As a public company, our compliance costs and risks have increased in recent years.

Legal, accounting and other expenses associated with public company reporting requirements have increased significantly in the past few years. We anticipate that general and administrative costs associated with regulatory compliance will continue to increase with on-going compliance requirements under the Sarbanes-Oxley Act of 2002, as well as any new rules implemented by the SEC, Canadian Securities Administrators, the NYSE Amex Equities and the Toronto Stock Exchange in the future. These rules and regulations have significantly increased our legal and financial compliance costs and made some activities more time-consuming and costly. We cannot assure you that we will continue to effectively meet all of the requirements of these regulations, including Section 404 of the Sarbanes-Oxley Act and National Instrument 52-109 of the Canadian Securities Administrators. Any failure to effectively implement internal controls, or to resolve difficulties encountered in their implementation, could harm our operating results, cause us to fail to meet reporting obligations, or result in our principal executive officer and principal financial officer being required to give a qualified assessment of our internal control over financial reporting. Any such result could cause investors to lose confidence in our reported financial information, which could have a material adverse effect on the trading price of our common shares and our ability to raise capital. These rules and regulations have made it more difficult and more expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage in the future. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers.

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Risks Related to Our Being a Foreign Private Issuer

As a foreign private issuer, our shareholders may receive less complete and timely data.

We are a “foreign private issuer” as defined in Rule 3b-4 under the United States Securities Exchange Act of 1934. Our equity securities are accordingly exempt from Sections 14(a), 14(b), 14(c), 14(f) and 16 of the Exchange Act, pursuant to Rule 3a12-3 of the Exchange Act. Therefore, we are not required to file a Schedule 14A proxy statement in relation to our annual meetings of shareholders. The submission of proxy and annual meeting of shareholder information on Form 6-K may result in shareholders having less complete and timely information in connection with shareholder actions. The exemption from Section 16 rules regarding reports of beneficial ownership and purchases and sales of common shares by insiders and restrictions on insider trading in our securities may result in shareholders having less data and there being fewer restrictions on insiders’ activities in our securities.

It may be difficult to enforce judgments or bring actions outside the United States against us and certain of our directors and officers.

It may be difficult to bring and enforce suits against us. We are incorporated in British Columbia, Canada. Many of our directors and officers are not residents of the United States and some of our assets are located outside of the United States. As a result, it may be difficult for U.S. holders of our common shares to effect service of process on these persons within the United States or to enforce judgments obtained in the U.S. based on the civil liability provisions of the U.S. federal securities laws against us or our officers and directors. In addition, a shareholder should not assume that the courts of Canada (i) would enforce judgments of U.S. courts obtained in actions against us or our officers or directors predicated upon the civil liability provisions of the U.S. federal securities laws or other laws of the United States, or (ii) would enforce, in original actions, liabilities against us or our officers or directors predicated upon the U.S. federal securities laws or other laws of the United States.

Risks related to investing in our common shares

We have not paid any dividends on our common shares. Consequently, your only opportunity currently to achieve a return on your investment will be if the market price of our common shares appreciates above the price that you pay for our common shares.

We have not declared or paid any dividends on our common shares since our incorporation. Any decision to pay dividends on our common shares will be made by our board of directors on the basis of our earnings, financial requirements and other conditions existing at such future time. Consequently, your only opportunity to achieve a return on your investment in our securities will be if the market price of our common shares appreciates and you are able to sell your common shares at a profit.

Our common share price has been volatile and your investment in our common shares could suffer a decline in value. Our common shares are traded on the Toronto Stock Exchange and the NYSE Amex Equities. The market price of our common shares may fluctuate significantly in response to a number of factors, some of which are beyond our control. These factors include price fluctuations of precious metals, government regulations, disputes regarding mining claims, broad stock market fluctuations and economic conditions in the United States.

Dilution through officer, director, employee, consultant or agent options could adversely affect our shareholders. Because our success is highly dependent upon our officers, directors, employees, consultants and agents, we have granted to some or all of our key officers, directors, employees, consultants and agents options to purchase common shares as non-cash incentives. To the extent that we grant significant numbers of options and those options are exercised, the interests of our other shareholders may be diluted.

The issuance of additional common shares may negatively affect the trading price of our common shares.

We have issued equity securities in the past and may continue to issue equity securities to finance our activities in the future, including to finance future acquisitions, or as consideration for acquisitions of businesses or assets. In addition, outstanding options and warrants to purchase our common shares may be exercised, resulting in the issuance of additional common shares. The issuance by us of additional common shares would result in dilution to our shareholders, and even the perception that such an issuance may occur could have a negative effect on the trading price of our common shares.

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ITEM 4. INFORMATION ON THE COMPANY

A.             History and Development of the Company

Introduction

Our executive office is located at:

598 – 999 Canada Place
Vancouver, British Columbia, Canada V6C 3E1
Telephone: (604) 638-5050
Facsimile: (604) 638-5051
Website: www.dejour.com
Email: rhodgkinson@dejour.com or dmatheson@dejour.com

The contact person is: Mr. Robert L. Hodgkinson, Co-Chairman and Chief Executive Officer or Mr. David Matheson, Chief Financial Officer.

Our common shares trade on the Toronto Stock Exchange and the NYSE Amex Equities Stock Exchange under the symbol “DEJ”.

Our authorized capital consists of three classes of shares: an unlimited number of common voting shares; an unlimited number of preferred shares designated as First Preferred Shares, issuable in series; and an unlimited number of preferred shares designated as Second Preferred Shares, issuable in series. There are no indentures or agreements limiting the payment of dividends and there are no conversion rights, special liquidation rights, pre-emptive rights or subscription rights.

The First Preferred Shares have priority over the Common Shares and the Second Preferred Shares with respect to the payment of dividends and in the distribution of assets in the event of a winding up of Dejour. The Second Preferred Shares have priority over the Common Shares with respect to dividends and surplus assets in the event of a winding up of Dejour.

As of December 31, 2013, there were 148,916,374 common shares issued and outstanding. As of December 31, 2013, there were no First Preferred Shares and no Second Preferred Shares issued and outstanding.

Incorporation and Name Changes

Dejour Energy Inc. (formerly Dejour Enterprises Ltd.) is incorporated under the laws of British Columbia, Canada. The Company was originally incorporated as “Dejour Mines Limited” on March 29, 1968 under the laws of the Province of Ontario. By articles of amendment dated October 30, 2001, the issued shares were consolidated on the basis of one (1) new for every fifteen (15) old shares and the name of the Company was changed to Dejour Enterprises Ltd. On June 6, 2003, the shareholders approved a resolution to complete a one-for-three-share consolidation, which became effective on October 1, 2003. In 2005, the Company was continued in British Columbia under the Business Corporations Act (British Columbia). On March 9, 2011, the Company changed its name from Dejour Enterprises Ltd. to Dejour Energy Inc.

Financings

We have financed our operations through funds from loans, public/private placements of common shares, common shares issued for property, common shares issued in debt settlements, and shares issued upon exercise of stock options and share purchase warrants. The following table summarizes our financings for the past three fiscal years.

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Fiscal Year Nature of Share Issuance   Number of Shares Gross Proceeds
        (Cdn$)
Fiscal 2012 Private Placement (1)   18,130,305 4,909,133
  Exercise of Warrants   2,968,683 1,110,212
  Exercise of Options   925,000 355,600
         
Fiscal 2011 Public Offering (2)   11,010,000 3,288,641
  Exercise of Warrants   4,551,841 1,688,147
  Exercise of Options   1,150,000 402,500

(1)

In June 2012, we completed a private placement of 18,130,305 units at US $0.26 per unit. Each unit consists of one common share and 3/4 of one common share purchase warrant. Each whole warrant entitles the holder to acquire one additional common share of the Company at US$0.40 per common share beginning 6 months from the date of issuance until June 4, 2017. Gross proceeds raised were Cdn$4,909,133 (US$4,713,879). In connection with this private placement, the Company paid finders’ fees of Cdn$294,655 (US$282,833) in cash and other related costs of Cdn$187,442 in cash.

   
(2)

In February 2011, we completed a public offering of 11,010,000 units at US $0.30 per unit. Each unit consists of one common share and one-half of one common share purchase warrant. Each whole warrant entitles the holder to acquire one additional common share of the Company at US$0.35 per common share on or before February 10, 2012. Gross proceeds raised were Cdn$3,288,641 (US$3,303,000). In connection with this private placement, the Company paid finders’ fees of Cdn$196,694 (US$199,710) in cash and other related costs of Cdn$119,602 in cash.

Past Capital Expenditures

Fiscal Year Cash flows used for equipment and resource properties
   
Fiscal 2013 Cdn$2,041,000 (1)
Fiscal 2012 Cdn$4,485,000 (2)
Fiscal 2011 Cdn$8,360,000 (3)

(1)

$7,000 of these funds was spent on the purchase of corporate and other assets; and $2,034,000 was spent on our resource properties. (For a breakdown on the resource property expenditures, see Notes 5 and 6 to our audited consolidated financial statements for the fiscal year ended December 31, 2013, filed with this annual report on Form 20-F.)

   
(2)

$6,000 of these funds was spent on the purchase of corporate and other assets; and $4,479,000 was spent on our resource properties. (For a breakdown on the resource property expenditures, see Notes 5 and 6 to our audited consolidated financial statements for the fiscal year ended December 31, 2012, filed with this annual report on Form 20-F.)

   
(3)

$29,000 of these funds was spent on the purchase of corporate and other assets; and $8,331,000 was spent on our resource properties. (For a breakdown on the resource property expenditures, see Notes 5 and 6 to our audited consolidated financial statements for the fiscal year ended December 31, 2011, filed with this annual report on Form 20-F.)

Capital Expenditures

Dejour is committed to future growth through its strategy to implement a full-cycle exploration and development program, augmented by strategic acquisitions with exploitation upside.

During the year ended December 31, 2013, the Company drilled three new wells to the Williams Fork formation at Kokopelli, the Company’s core operating area in the Piceance Basin of Colorado. The Company also completed these wells and one other previously drilled well. The operations were primarily funded by a U.S. based drilling fund.

During the year ended December 31, 2012, the Company incurred $2.2 million on drilling and completion operations. Equipment and facility expenditures were $1.4 million. The balance of $0.8 million was mostly related to the capitalization of general and administrative costs and lease rentals on its oil and gas interests.

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Additions to property and equipment and exploration and evaluation assets:

    Year ended December 31, 2013     Year ended December 31, 2012        
(CA$ thousands)   $     % of total     $     % of total     % change  
                               
Land acquisition and retention   118     5.8%     265     5.9%     -55%  
Drilling and completion (1)   1,014     49.7%     2,179     48.6%     -53%  
Facility and pipelines   257     12.6%     1,388     30.9%     -81%  
Capitalized general and administrative   645     31.6%     646     14.4%     0%  
Other assets   7     0.3%     7     0.2%     0%  
    2,041     100.0%     4,485     100.0%     -54%  

(1)   excludes non-cash capital expenditures of $443,000 (US$417,000) related to joint venture financing (see ‘Financial Contract Liability’ section of the MD&A for details)

Daily Production

  Three months ended December 31,       Year ended December 31,  
  2013     2012     2013     2012  
By Product                        
   Oil and natural gas liquids (bbls/d)   167     193     215     198  
   Natural gas (mcf/d)   2,714     755     1,733     1,040  
Total (boe/d)   620     319     504     372  

The decrease in oil production for Q4 2013 was mainly the result of the temporary curtailment of production associated with routine repairs and maintenance at one of the main oil producing well at Woodrush.

The increase in natural gas production for the current year was attributable to the commencement of production from the four new wells at Kokopelli in the eastern portion of Piceance Basin of Colorado in August 2013.

B.             Business Overview

General

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 79,000 net acres of oil and gas leases in the following regions:

The Peace River Arch of northeastern British Columbia and northwestern Alberta, Canada
The Piceance, Paradox and Uinta Basins in the US Rocky Mountains

Summary

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Over the past few years, the Company has continued to develop its Halfway oilfield in northeastern British Columbia, Canada while evaluating its exploration prospects in the Piceance Basin with the intent of developing drillable prospects of merit at the earliest possible opportunity. This process involved several distinct steps:

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 this process, the Company’s assets in Canada and the Piceance basin have moved to a higher weighting of lower risk development projects as opposed to higher risk exploration projects.

Our business objective is to grow our oil and gas production and generate sufficient cash flow to continue to expand company operations and enhance shareholder value.

Specialized Skill and Knowledge: Exploration for and development of petroleum and natural gas resources requires specialized skills and knowledge including in the areas of petroleum engineering, geophysics, geology and title. The Company and its subsidiaries have obtained personnel with the required specialized skills and knowledge to carry out their respective operations. While the current labour market in the industry is highly competitive, the Company expects to be able to attract and maintain appropriately qualified employees for fiscal 2014.

Cycles: All of the Company's operations in Canada are affected by seasonal operating conditions. Dejour Energy (Alberta) Ltd. holds properties in northwestern Alberta and northeastern British Columbia which are accessible to heavy equipment in winter only when the ground is frozen, typically between December to early April. For this reason drilling and pipeline construction ceases over the remainder of the year, limiting growth to winter only. Production operations continue year round in these areas once production is established. The prices that the Company will receive for oil and gas production in the future are weighted to world benchmark prices and may be adversely affected by mild weather conditions. Following a significant increase in oil prices in 2007 and the initial half of 2008, oil prices have been relatively stable in the US$85.00 to US$100.00 range for the past 5 years. In early December 2013, extreme cold weather from the polar vortex has resulted in a sharp increase of about 25% to 30% in the price paid to producers for their production of natural gas. It is expected that natural gas prices will remain relatively firm at this higher level for most of 2014 as US storage facilities are replenished following emergency withdrawals of natural gas to meet cold weather demands.

Commodity price cycles are also affected by world industrial supply and demand, domestic and international commodity transportation systems, and political factors affecting construction of pipelines and exports of controversial commodities like liquid natural gas. See "Risk Factors – Risks related to operating an exploration, development and production company".

Environmental Protection: The Company's operations are subject to environmental regulations (including regular environmental impact assessments and permitting) in the jurisdictions in which it operates. Such regulations cover a wide variety of matters, including, without limitation, emission of greenhouse gases, prevention of waste, pollution and protection of the environment, labour regulations and worker safety. Under such regulations there are preventative obligations, clean-up costs and liabilities for toxic or hazardous substances which may exist on or under any of its properties or which may be produced as a result of its operations. Environmental legislation and legislation relating to exploration and production of oil and natural gas will require stricter standards and enforcement, increased fines and penalties for non-compliance, more stringent environmental assessments of proposed projects and a heightened degree of responsibility for companies and their directors and employees. Such stricter standards could impact the Company's costs and have an adverse effect on results of operations. The Company expects to incur abandonment and site reclamation costs as existing oil and gas properties are abandoned and reclaimed; however, the Company does not anticipate making material expenditures beyond normal compliance with environmental regulations in 2014 and future years.

Employees: The Company had the equivalent of approximately 10 full-time employees and consultants during 2013.

Social or Environmental Policies: The health and safety of employees, contractors and the public, as well as the protection of the environment, is of utmost importance to the Company. The Company endeavors to conduct its operations in a manner that will minimize adverse effects of emergency situations by:

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complying with government regulations and standards;

following industry codes, practices and guidelines;

ensuring prompt, effective response and repair to emergency situations and environmental incidents; and

educating employees and contractors of the importance of compliance with corporate safety and environmental rules and procedures.

The Company believes that all Company personnel have a vital role in achieving excellence in environmental, health and safety performance. This is best achieved through careful planning and the support and active participation of everyone involved.

Competitive Conditions: The Company operates in geographical areas where there is strong competition by other companies for reserve acquisitions, exploration leases, licences and concessions and skilled industry personnel. The Company’s competitors include major integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual producers and operators, many of whom have greater financial and personnel resources than the Company. The Company’s ability to acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers is dependent upon developing and maintaining close working relationships with its current industry partners and joint operators, and its ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.

Three Year History

2013

During the year, the Company continued oil and gas production operations at the Drake/Woodrush oilfield near Ft. St. John, British Columbia, and commenced drilling operations at Kokopelli in the Piceance Basin of Colorado.

The Company achieved the following operational and financial objectives:

1.

Completed the drilling and fracing of four new wells to the Williams Fork formation at Kokopelli in the eastern portion of Piceance Basin of Colorado. These wells are the initial four wells funded in the financing arrangement with a Denver-based drilling fund;

   
2.

Closed a $3.5 million loan facility with a Canadian institutional lender and applied $1.65 million of the net proceeds to repay an amount owing to the Company’s Canadian bank;

   
3.

Extended the Company’s existing $3.5 million revolving operating demand loan with its Canadian bank;

   
4.

Increased production by 94% to 620 BOE/d for the three months ended December 31, 2013 from production of 319 BOE/d for the comparative period of 2012; and

   
5.

Increased gross revenues by 35% from $6.9 million for the year ended December 31, 2012 to $9.3 million for the year ended December 31, 2013.

2012

In 2012, the Company continued its focus on production optimization of the Drake/Woodrush oilfield in northeastern British Columbia, Canada, while preparing for drilling and production activities in the Piceance Basin.

During the year, the Company achieved the following objectives:

1.

Executed a US$6.5 million financial contract with a private U.S. based oil and gas drilling fund whereby the parties agreed to form a partnership to complete the initial well in the Kokopelli Field and drill and complete three additional wells in early 2013. Total program cost was approximately US$10.4 million;

   
2.

Executed a sale and farm-out agreement covering about 7,450 acres of 100% owned western Piceance Basin lands to a listed U.S. oil and natural gas exploration and production company, for certain cash consideration and a commitment to carry the Company through the drilling and completion of three earning wells, with certain performance provisions;

24



3.

Successfully tied in production at South Rangely from a discovery well drilled in 2011;

   
4.

Successfully raised gross proceeds of US$4.7 million in equity, allowing the Company to support exploration, development and acquisition activities of its oil and gas properties and provide for additional working capital;

   
5.

Added about 31,000 net acres to the Company’s current landholdings in northwestern Colorado through a restructuring of its exploration joint venture with Brownstone Energy Inc., a joint venture partner;

   
6.

Successfully completed construction of the first drilling pad and drilled the initial well in the Kokopelli area of the Piceance Basin;

   
7.

Formation of a federal unit containing the leases adjacent to the lease on which the discovery well at South Rangely leasehold was drilled in 2011 in the Company’s Piceance Basin area of operations; and

   
8.

Successfully completed and tied into production the 3rd oil well at the Company’s Woodrush property, north of Fort St. John, British Columbia.

2011

In 2011, the Company optimized production at the Drake/Woodrush property, and completed pre-drilling and lease curing activities at Kokopelli. The Company also drilled a successful discovery well at South Rangely.

Key achievements were:

1.

Successful implementation and expansion of the Halfway “E” oil pool waterflood on the Company’s Woodrush property;

   
2.

Obtained a $7 million line of credit from a Canadian bank to refinance the bridge loan and to provide funds for general corporate purposes;

   
3.

Generated positive operating cash flow for the second half of the year;

   
4.

Completed all requirements for drilling on the Company’s federal leases at Gibson Gulch, Piceance Basin, Colorado, resulting in the first drilling permits being issued in the fourth quarter of the year; and

   
5.

Completed and tested a discovery well at South Rangely. After the well was successfully fractured and stimulated, the well flowed rich gas from the Mancos "B" Sand in commercial quantities.

United States vs. Foreign Sales/Assets

Gross Revenue for fiscal year ended: Canada United States
(Cdn$ in 000) $ $
12/31/2011 8,824 --
12/31/2012 6,882 --
12/31/2013 7,386 1,931

Asset Location as of: Canada United States
(Cdn$ in 000) $ $
12/31/2011 20,622 8,816
12/31/2012 12,118 15,455
12/31/2013 7,695 17,804

Commodity Price Environment

Generally, the demand for, and the price of, natural gas increases during the colder winter months and decreases during the warmer summer months. Pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Crude oil and the demand for heating oil are also impacted by seasonal factors, with generally higher prices in the winter. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations.

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Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. The market for oil and natural gas is beyond our control and prices are difficult to predict. (See also ‘Trend Information’ under item 5 ‘Operating and Financial Review and Prospects’)

Forward Contracts

The Company is not bound by an agreement (including any transportation agreement) directly or through an aggregator, under which it may be precluded from fully realizing, or may be protected from the full effect of, future market prices for oil and gas. The Company had no commodity contracts in place at December 31, 2013.

Additional Information Concerning Abandonment and Reclamation Costs

For the Company’s Canadian and US oil and gas interests, the well abandonment costs for all wells with reserves have been included at the property level. The Company estimated the total undiscounted amount of the cash flows required to settle the decommissioning liabilities as at December 31, 2013 to be approximately $1,856,000. These obligations are expected to be settled over the next 15 years with the majority of costs incurred between 2016 and 2028. Additional abandonment costs associated with non-reserves wells, lease reclamation costs and facility abandonment and reclamation expenses have not been included.

Government Regulations

Our oil and natural gas exploration, production and related operations, when developed, are subject to extensive laws and regulations promulgated by federal, state, tribal and local authorities and agencies. These laws and regulations often require permits for drilling operations, drilling bonds and reports concerning operations, and impose other requirements relating to the exploration for and production of oil and natural gas. Many of the laws and regulations govern the location of wells, the method of drilling and casing wells, the plugging and abandoning of wells, the restoration of properties upon which wells are drilled, temporary storage tank operations, air emissions from flaring, compression, the construction and use of access roads, sour gas management and the disposal of fluids used in connection with operations.

Our operations are subject to environmental regulations (including regular environmental impact assessments and permitting) in the jurisdictions in which it operates. Such regulations cover a wide variety of matters, including, without limitation, emission of greenhouse gases, prevention of waste, pollution and protection of the environment, labour regulations and worker safety. Under such regulations there are preventative obligations, clean-up costs and liabilities for toxic or hazardous substances which may exist on or under any of its properties or which may be produced as a result of its operations. Environmental legislation and legislation relating to exploration and production of oil and natural gas will require stricter standards and enforcement, increased fines and penalties for non-compliance, more stringent environmental assessments of proposed projects and a heightened degree of responsibility for companies and their directors and employees. Such stricter standards could impact our costs and have an adverse effect on results of operations.

The Comprehensive Environmental, Response, Compensation, and Liability Act, or CERCLA, and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of "hazardous substances" found at such sites. It is not uncommon for the government to file claims requiring cleanup actions, demands for reimbursement for government-incurred cleanup costs, or natural resource damages, or for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize the imposition of substantial fines and penalties for noncompliance, as well as requirements for corrective actions. Although CERCLA currently excludes petroleum from its definition of "hazardous substance," state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum-related products. In addition, although RCRA classifies certain oil field wastes as "non-hazardous," such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements. CERCLA, RCRA and comparable state statutes can impose liability for clean-up of sites and disposal of substances found on drilling and production sites long after operations on such sites have been completed. Other statutes relating to the storage and handling of pollutants include the Oil Pollution Act of 1990, or OPA, which requires certain owners and operators of facilities that store or otherwise handle oil to prepare and implement spill response plans relating to the potential discharge of oil into surface waters. The OPA, contains numerous requirements relating to prevention of, reporting of, and response to oil spills into waters of the United States. State laws mandate oil cleanup programs with respect to contaminated soil. A failure to comply with OPA's requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions.

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The Endangered Species Act, or ESA, seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, or destroy or modify the critical habitat of such species. Under the ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. The ESA has been used to prevent or delay drilling activities and provides for criminal penalties for willful violations of its provisions. Other statutes that provide protection to animal and plant species and that may apply to our operations include, without limitation, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act. Although we believe that our operations are in substantial compliance with these statutes, any change in these statutes or any reclassification of a species as threatened or endangered or re-determination of the extent of "critical habit" could subject us to significant expenses to modify our operations or could force us to discontinue some operations altogether.

The National Environmental Policy Act, or NEPA, requires a thorough review of the environmental impacts of "major federal actions" and a determination of whether proposed actions on federal and certain Indian lands would result in "significant impact." For purposes of NEPA, "major federal action" can be something as basic as issuance of a required permit. For oil and gas operations on federal and certain Indian lands or requiring federal permits, NEPA review can increase the time for obtaining approval and impose additional regulatory burdens on the natural gas and oil industry, thereby increasing our costs of doing business and our profitability.

The Clean Water Act, or CWA, and comparable state statutes, impose restrictions and controls on the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the Environmental Protection Agency (EPA) or an analogous state agency. The CWA regulates storm water run-off from oil and natural gas facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.

The Safe Drinking Water Act, or SDWA, and the Underground Injection Control (UIC) program promulgated thereunder, regulate the drilling and operation of subsurface injection wells. EPA directly administers the UIC program in some states and in others the responsibility for the program has been delegated to the state. The program requires that a permit be obtained before drilling a disposal well. Violation of these regulations and/or contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SWDA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.

The Clean Air Act, as amended, restricts the emission of air pollutants from many sources, including oil and gas operations. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to remain in compliance. In addition, the EPA has promulgated more stringent regulations governing emissions of toxic air pollutants from sources in the oil and gas industry, and these regulations may increase the costs of compliance for some facilities.

Significant studies and research have been devoted to climate change and global warming, and climate change has developed into a major political issue in the United States and globally. Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment. Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural gas exploration and production. Many state governments have enacted legislation directed at controlling greenhouse gas emissions, and future state and federal legislation and regulation could impose additional restrictions or requirements in connection with our operations and favor use of alternative energy sources, which could increase operating costs and demand for oil products. As such, our business could be materially adversely affected by domestic and international legislation targeted at controlling climate change.

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We expect to incur abandonment and site reclamation costs as existing oil and gas properties are abandoned and reclaimed; however, we do not anticipate making material expenditures beyond normal compliance with environmental regulations in 2014 and future years.

The health and safety of employees, contractors and the public, as well as the protection of the environment, is of utmost importance to us. We endeavour to conduct our operations in a manner that will minimize adverse effects of emergency situations by:

  • complying with government regulations and standards;
  • following industry codes, practices and guidelines;
  • ensuring prompt, effective response and repair to emergency situations and environmental incidents; and
  • educating employees and contractors of the importance of compliance with corporate safety and environmental rules and procedures.

We believe that all of our personnel have a vital role in achieving excellence in environmental, health and safety performance. This is best achieved through careful planning and the support and active participation of everyone involved.

Competition

We operate in geographical areas where there is strong competition by other companies for reserve acquisitions, exploration leases, licences and concessions and skilled industry personnel. Our competitors include major integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual producers and operators, many of whom have greater financial and personnel resources than us. Our ability to acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers is dependent upon developing and maintaining close working relationships with its current industry partners and joint operators, and its ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.

We compete with many companies possessing greater financial resources and technical facilities for the acquisition of oil and gas properties, exploration and production equipment, as well as for the recruitment and retention of qualified employees.

Seasonality

All of our operations in Canada are affected by seasonal operating conditions. Dejour Energy (Alberta) Ltd., our wholly owned subsidiary, holds properties in northwestern Alberta and northeastern British Columbia which are accessible to heavy equipment in winter only when the ground is frozen, typically between December to early April. For this reason drilling and pipeline construction ceases over the remainder of the year, limiting growth to winter only. Production operations continue year round in these areas once production is established. The prices that we will receive for oil and gas production in the future are weighted to world benchmark prices and may be adversely affected by mild weather conditions.

C.             Organizational Structure

Dejour Energy Inc. (formerly Dejour Enterprises Ltd.) is incorporated under the laws of British Columbia, Canada. The Company was originally incorporated as “Dejour Mines Limited” on March 29, 1968 under the laws of the Province of Ontario. By articles of amendment dated October 30, 2001, the issued shares were consolidated on the basis of one (1) new for every fifteen (15) old shares and the name of the Company was changed to Dejour Enterprises Ltd. On June 6, 2003, the shareholders approved a resolution to complete a one-for-three-share consolidation, which became effective on October 1, 2003. In 2005, the Company was continued in British Columbia under the Business Corporations Act (British Columbia). On March 9, 2011, the Company changed its name from Dejour Enterprises Ltd. to Dejour Energy Inc.

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Intercorporate Relationships

We have four 100% owned subsidiaries:

  • Dejour Energy (USA) Corp. (“Dejour USA”), a Nevada corporation, holds Dejour's United States oil and gas interests,
  • Dejour Energy (Alberta) Ltd. (“DEAL”), an Alberta corporation, holds its Canadian oil and gas interests in northwestern Alberta and northeastern British Columbia;
  • Wild Horse Energy Ltd. (“Wild Horse”), an inactive Alberta corporation, and
  • 0855524 B.C. Ltd. (“0855524 ”) , a British Columbia Corporation, which is currently inactive.

D.             Property, Plant and Equipment

Our executive offices are located in rented premises of approximately 2,519 sq. ft. at 598 – 999 Canada Place, Vancouver, British Columbia, V6C 3E1. We began occupying these facilities on July 1, 2009.

Resource Properties

Our current focus is on oil and gas properties located in the United States and Canada and currently have oil and gas leases in the following regions:

  • The Piceance, Paradox and Uinta Basins in the US Rocky Mountains.
  • The Peace River Arch of northeastern British Columbia and northwestern Alberta, Canada.

US Oil and Gas Interests

Kokopelli, Piceance Basin

During 2012, the Company drilled an initial well into the Willams Fork natural gas formation at Kokopelli to hold its 2,200 gross acres (1,571 net) of leasehold interests. The Company also entered into a financial contract with an industry Drilling Fund to complete and tie-in the initial well and drill, complete, and tie-in an additional 3 wells. The Drilling Fund’s investment of US$7,000,000 (an initial investment of US$6,500,000 supplemented with an additional US$500,000 for a total of US$7,000,000) represents about 67% of the total program cost of US$10,400,000. The primary producing geological horizons are the Williams Fork and Niobrara/Mancos zones at depths ranging from 9,000 to 10,500 ft. respectively.

The Company’s 4-well drilling and completion program at Kokopelli focused strictly on the Williams Fork formation and was completed in September, 2013.

Dejour has a 72% working interest in 139 proved undeveloped locations at the Kokopelli project. To date, the Company has delineated all proved undeveloped (“PUD”) drilling locations on 10-acre spacing in the Williams Fork. As at December 31, 2013, the total proved reserves, net to the Company’s working interest, are 18.6 million BOE having an NPV before tax, discounted at 10% of $90 million. WPX Energy, Rocky Mountain LLC, Inc. and Bill Barrett Corporation are developing and producing the Williams Fork on adjacent acreage to the east, west and north of the Company’s acreage. Dejour has worked closely with important constituents including local citizenry and the Bureau of Land Management (“BLM”) in the US and the Colorado Division of Wildlife (“Dept. of Wildlife”) to develop a mutually acceptable development plan for this environmentally sensitive area.

The Company will base its future development plans for Kokopelli for 2014 and 2015 on an assessment of (a) the NYMEX futures market for natural gas, (b) the natural gas liquids markets at the Mt. Belvieu, Texas and Conway, Kansas sales points, and (c) the ability to secure a joint venture financing arrangement with a partner capable of financing up to a 75% working interest in a 30-well Williams Fork development (“Phase 1”) followed closely by a minimum of 20 wells in a Phase 2 program.

Roan Creek, Piceance Basin

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On November 5, 2012, the Company entered into a “Lease Purchase and Farmout Agreement” (“the Agreement”) with a US exploration and production (“E&P”) company with respect to its Roan Creek acreage. Approximately 2,300 acres were sold for cash while the remaining 5,200 acres were included in a Farmout Agreement (“the Agreement”) with the following terms and conditions:

a)

The US E&P company will drill three (3) separate Test Wells on the three (3) lease tracts comprising the 5,200 acres and earn a 100% working interest before payout after which Dejour will earn the right to back-in for a 20% working interest on a well-by-well basis;

   
b)

The wells must be drilled prior to the end of the expiration date of each lease which range from June 30, 2014 to September 30, 2014, and

   
c)

Future development of the separate tracts, if any, will be based upon the after-payout working interest earned by each party to the Agreement.

During the third quarter of 2013, the Company was informed by the E&P company that it would not drill the test wells and, per the Agreement, would pay the Company a US$275,000 cash penalty on or before June 30, 2014. The penalty payment addresses the relinquishment of 3,240 of the 5,200 acres covered by the Agreement back to the Bureau of Land Management.

The Company is seeking joint venture partners to further explore the remaining Roan Creek acreage of 1,960 acres.

Canadian Oil and Gas Interests

Drake/Woodrush, Ft. St. John, British Columbia

The Company’s Drake/Woodrush oilfield is located about 110 km. north of Ft. St. John, British Columbia, Canada. During 2013, the Company produced approximately 75,000 BOE and 249,000 MMcf of natural gas from the 3 oil wells and 5 natural gas wells producing from the Halfway geological formation.

The Company owns a 75% working interest in the Drake/Woodrush oilfield and is the contractual “Operator” of the wells and related production facilities and pipelines.

The Drake/Woodrush oilfield production is being enhanced by a system of waterflood pressure maintenance which currently injects approximately 2,400 BOWD into the formation to maintain reservoir pressure. The Company re-cycles the produced water and re-injects the water volumes back into the reservoir.

The Company plans to further develop the natural gas potential of the Drake/Woodrush oilfield via recompletions of existing wells and the drilling of at least one new well. This program is dependent upon continued stronger prices for natural gas in the Peace Arch area of northeastern British Columbia.

30


Summary of Operational Highlights

Year-to-date 2013 vs. Year-to-date 2012   Year Ended December 31        
(CA$ thousands, except as otherwise noted)   2013     2012     % change  
Production Volumes:                  
Oil and natural gas liquids (bbls/d)   215     198     9%  
Natural gas (mcf/d)   1,733     1,040     67%  
Total (BOE/d)   504     372     35%  
                   
Average realized prices:                  
Oil and natural gas liquids ($/bbl)   86.21     81.37     6%  
Natural gas ($/mcf)   4.06     2.57     58%  
Total ($/BOE)   50.79     50.59     0%  
                   
Revenue, before royalties:                  
Oil and natural gas liquids   6,768     5,905     15%  
Natural gas   2,549     977     161%  
Total   9,317     6,882     35%  

For the year ended December 31, 2013 (“fiscal 2013”), total revenue, before royalties, increased by $2,435,000 or, 35%, was due to a 35% increase in oil and gas production over the year ended December 31, 2012 (“fiscal 2012”).

The increase in natural gas production for the current year was attributable to the commencement of production from the four new wells at Kokopelli in the eastern portion of Piceance Basin of Colorado in August 2013.

Oil Operations

The average price received for oil sales in fiscal 2013 increased in line with the Edmonton Par oil prices which averaged $93.24 per barrel in fiscal 2013, compared to $86.53 per barrel received in fiscal 2012.

Average oil royalties paid for the year ended December 31, 2013 were consistent with those paid in the year ended December 31, 2012.

Operating and transportation expenses averaged $26.75 per barrel in fiscal 2013. This represents a decrease of 29% from $37.57 per barrel in fiscal 2012. The decrease in per unit operating and transportation expenses in fiscal 2013 resulted from the non-recurring costs of major workovers on one of the oil producing wells at Woodrush in 2012 and the allocation of fixed operating costs over a higher oil production volume.

Natural Gas Operations

The average price received for gas sales increased by 58% for fiscal 2013, relative to the corresponding period of the prior year. The increase in Dejour’s average realized gas price for the current year reflected higher benchmark prices.

Average gas royalties for fiscal 2013 were higher compared to the corresponding period of the prior year. Initiation of gas production from the four new wells at Kokopelli contributed to the increase in royalties in both periods as the effective rate in Colorado is approximately 50% higher than the lower royalty rates for marginal gas production in British Columbia. Additionally, lower gas royalty rates in 2012 are a result of lower gas prices and gas cost allowance credits under the province of British Columbia royalty framework.

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Operating and transportation expenses averaged $2.06 per mcf in fiscal 2013. This represents a decrease of 24% from $2.72 per mcf in fiscal 2012. The decrease in per unit operating and transportation expenses is due to the increase in lower-cost Colorado gas production as a percent of the Company’s total gas production.

Reserve Data

The standards of the SEC require that proved reserves be estimated using existing economic conditions (constant pricing). Based on this methodology, the Company’s results have been calculated utilizing the 12-month average price for each of the years presented.

The Company reports in Canadian currency and therefore the Reserves Data set forth in the tables below has been converted to Canadian dollars at the prevailing conversion rate at December 31, 2013. The conversion rate used per Bank of Canada is 1.0636.

In 2013, GLJ Petroleum Consultants (“GLJ”), independent petroleum engineering consultants based in Calgary, Alberta was retained by the Company to evaluate the Canadian properties of the Company. Their report, titled “Third Party Report on Reserves, Dejour Energy (Alberta) Ltd.”, is dated February 19, 2014 and has an effective date of December 31, 2013.

Gustavson Associates (“Gustavson”), an independent petroleum engineering consultants based in Denver, Colorado were retained by the Company to evaluate the US properties of the Company. Their report, titled “Reserve Estimate and Financial Forecast as to Dejour’s Interests in the Kokopelli Field Area, Garfield County, Colorado” is dated March 14, 2014 and has an effective date of January 1, 2014.

The reserves data set forth below (the " Reserves Data "), derived from GLJ and Gustavson’s reports, summarizes our oil, liquids and natural gas reserves.

The GLJ and Gustavson reports are based on certain factual data supplied by the Company, and GLJ and Gustavson's opinion of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to the Company’s petroleum properties and contracts (except for certain information residing in the public domain) were supplied by the Company to GLJ and Gustavson and accepted without any further investigation. GLJ and Gustavson accepted this data as presented and neither title searches nor field inspections were conducted. All statements relating to the activities of the Company for the year ended December 31, 2013 include a full year of operating data on the properties of the Company.

The reserve estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas liquids and natural gas reserves may be greater than or less than the estimates provided herein.

Controls Over Reserve Report Preparation

Our reserve estimates reports as of December 31, 2013 are prepared by our independent qualified reserve evaluators, GLJ and Gustavson. To ensure accuracy and completeness of the data prior to disclosure of reserve estimates to the public, our reserves committee does the following: (1) reviews our procedures for providing information to the independent qualified reserve evaluators, (2) meets with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the qualified reserves evaluators to report without reservation, (3) reviews the reserves data with management and the independent qualified reserves evaluator. If the reserve committee is satisfied with results of its evaluation it will approve the content of our reserve disclosure. If any concerns arise in the reserve committee’s evaluation, the reserve committee will work with our management and the independent qualified reserves evaluators to resolve the issues before disclosure of reserves is made public.

As of December 31, 2013, the Company’s reserve committee was composed of: Craig Sturrock, Ross Gorrell and Ronnie Bozzer. Please see “Item 6. Directors, Senior Management and Employees, A. Directors and Senior Management” for biographical information on the members of the reserve committee.

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Summary of Oil and Gas Reserves as of Fiscal Year-End Based on Average Fiscal Year Prices

  Net Reserves
Proved Reserves Category

Oil
(Mbbl)
Condensate
(MBO)
Natural Gas
(Mmcf)
Natural Gas
Liquids
(Mbbl)
Developed        
   Canada 114 - 466 2
   United States - 3 367 15
Undeveloped        
   Canada - - - -
   United States - 587 86,243 3,580
TOTAL PROVED 114 590 87,076 3,597

Given acceptable commodity prices, 100% of the Company’s undeveloped reserves are scheduled to be developed within the next four years.

Canada – Increase in Total Proved Natural Gas Reserves of 551 MMcf:

During the year ended December 31, 2013, an expected increase in natural gas reserves as there are more favorable decline curves and additional solution gas from the proved undeveloped location. GLJ increased, by way of a technical revision, the Company’s total proved natural gas reserves by 551 MMcf.

United States – Increase in Total Proved Natural Gas Liquids Reserves of 1,726 Mbbls and Natural Gas Reserves of 41,571 MMcf:

During the year ended December 31, 2013, an expected increase in the natural gas reserves and natural gas liquids reserves as this resulted from a successful 2013 drilling program which converted 47 “probable” drilling locations at December 31, 2012 to “proven” as at December 31, 2013. Gustavson increased, by way of an extension, the Company’s total proved natural gas and natural gas liquids by 41,571 MMcf and 1,726 Mbbls, respectively.

Total Proved Reserves

The table below compares our estimated proved reserves and associated present value (discounted at an annual rate of 10%) of the estimated future revenue before income tax.

  December 31, 2013
Canada (Proved Developed and Undeveloped Reserves) Natural Gas Oil Natural Gas Liquids Total PV-10 (2)


(Mmcf)

(Mbbl)

(Mbbl)

(Mmcfe)
(in thousands
Cdn$)

2012 12-month average prices (SEC) (1)

466

114

2

1,162

$3,648

  December 31, 2013
United States (Proved Developed and Undeveloped Reserves) Natural Gas Condensate Natural Gas Liquids Total PV-10 (2)


(Mmcf)

(Mbbl)

(Mbbl)

(Mmcfe)
(in thousands
Cdn$)

2013 12-month average prices (SEC) (1)

86,610

590

3,595

111,720

$90,042

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  December 31, 2013

Total (Proved Developed and
Undeveloped Reserves)


Natural Gas


Oil


Condensate
Natural
Gas
Liquids


Total


PV-10 (2)


(Mmcf)

(Mbbl)

(Mbbl)

(Mbbl)

(Mmcfe)
(in thousands
Cdn$)
2013 12-month average prices (SEC) (1) 87,076 114 590 3,597 112,882 $93,690

Reconciliation to Standardized Measure

As at December 31, 2013                  
(in thousands of Canadian dollars)   Canada     USA     Total  
Present value of estimated future net cash flows before income taxes $  3,648   $  90,042   $  93,690  
Income taxes - discounted   -     (29,123 )   (29,123 )
Standardized measure of discounted future net cash flow $  3,648   $  60,919   $  64,567  

Notes:

(1)

The 12-month average prices (SEC) are calculated based on an average of market prices posted at or near the first of each month from January to December 2013, adjusted for pipeline transportation costs from the wellhead to the interstate pipeline prevailing at December 31, 2013. The 12-month average prices (SEC) used for Canadian properties were Cdn$86.12 per barrel of oil and Cdn$3.55 per Mcf of natural gas. The 12-month average prices (SEC) used for US properties were US$86.58 per barrel of condensate, US$4.09 per Mcf of natural gas, and US$68.84 per barrel of NGLs.

   
(2)

Present value of estimated future net cash flows before income taxes (PV-10) is considered a non-GAAP financial measure as defined by the SEC. We believe that our PV-10 presentation is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account the related deferred income taxes, as such taxes may differ among various companies because of differences in the amounts and timing of deductible basis, net operating loss carryforwards and other factors. We believe investors and creditors use our PV-10, before tax, as a basis for comparison of the relative size and value of our proved reserves to the reserve estimates of other companies. PV-10 is not a measure of financial or operating performance under GAAP and is not intended to represent the current market value of our estimated oil and natural gas reserves. PV-10, before tax, should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

   
(3)

US dollars are converted into Canadian dollars using the closing exchange rate on December 31, 2013, which is US$1.00 = Cdn$1.0636.

Oil and Gas Production, Production Prices and Production Costs

The following is our total net oil and gas production for the fiscal years ended December 31, 2013, 2012 and 2011. Production came from our Canadian and United States properties. Production from our United States properties commenced in the fiscal year ended December 31, 2013.

  Production   
Fiscal Year Ended

Oil and Natural Gas
Liquids
(bbls)
Natural Gas
(Mcf)
Total (BOE)

December 31, 2013 78,566 632,467 183,977
December 31, 2012 72,567 380,780 136,031
December 31, 2011 81,468 432,199 153,501

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The following table includes the average prices the Company received for its production for the fiscal years ended December 31, 2013, 2012 and 2011.

  Average Sales Prices   
Fiscal Year Ended Oil and Natural Gas
Liquids
($/bbls)
Natural Gas
($/Mcf)
Total
($/BOE)
December 31, 2013 86.21 4.06 50.79
December 31, 2012 81.37 2.57 50.59
December 31, 2011 88.98 3.64 57.49

The following table includes the average production cost, not including ad valorem and severance taxes, per unit of production for the fiscal years ended December 31, 2013, 2012 and 2011.

Average Production Costs
Fiscal Year Ended

Oil and Natural Gas
Liquids
($/bbls)
Natural Gas
($/Mcf)
Total
($/BOE)
December 31, 2013                                    42.91 2.83                      28.03
December 31, 2012                                    36.64 2.80                      27.36
December 31, 2011                                    16.62 2.60                      16.15

Drilling and Other Exploratory and Development Activities

During the fiscal year ended December 31, 2013, no wells were drilled in Canada and we drilled the following wells in the United States:

  Net Exploratory Wells Net Development Wells
U.S.A Productive Dry Productive Dry
Natural Gas   - - 0.67                  -
Total Wells   - - 0.67                  -

During the fiscal year ended December 31, 2012, no wells were drilled in Canada and we drilled the following wells in the United States:

  Net Exploratory Wells Net Development Wells
U.S.A Productive Dry Productive Dry
Natural Gas   - - 0.20                  -
Total Wells   - - 0.20                  -

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During the fiscal year ended December 31, 2011, we drilled the following wells:

  Net Exploratory Wells Net Development Wells   
Canada Productive Dry Productive   Dry
         
Oil -   - 0.75                    -
Service Wells 1.50   - 2.25                    -
         
Total Wells 1.50   - 3.00                    -

  Net Exploratory Wells   Net Development Wells
U.S.A Productive                      Dry  Productive Dry
Natural Gas   - - 0.50                  -
Total Wells   - - 0.50                    -

Delivery Commitments

We have no current delivery commitments for either oil or natural gas.

Oil and Gas Properties and Wells

As of December 31, 2013, we had 11 gross (7.46 net) producing or shut-in oil or natural gas wells.

  Oil Natural Gas
Canada Gross Net Gross Net
         
Producing 3 2.25 5                  3.63
Shut-In - - 1                  0.75
TOTAL 3 2.25 6                   4.38

  Oil   Natural Gas
U.S.A Gross Net Gross     Net
         
Producing                            -   - 4 0.83
TOTAL                             -   - 4 0.83

As of December 31, 2012, we had 11 gross (7.33 net) producing or shut-in oil or natural gas wells.

  Oil Natural Gas
Canada Gross Net Gross Net
         
Producing 3 2.25 5                  3.63
Shut-In - - 1                  0.75
TOTAL 3 2.25 6                   4.38

  Oil Natural Gas
U.S.A Gross Net   Gross   Net
         
Shut-In                            - -        2 0.70

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TOTAL  - - 2 0.70

As of December 31, 2011, we had 10 gross (7.13 net) producing or shut-in oil or natural gas wells.

  Oil Natural Gas
Canada Gross Net Gross Net
         
Producing 3 2.25 5                  3.63
Shut-In - - 1                  0.75
TOTAL 3 2.25 6                   4.38

  Oil Natural Gas
U.S.A Gross Net Gross Net
         
Shut-In                            - 1 0.50
TOTAL                             - 1 0.50

Interest in Oil and Gas Properties

The following table sets forth information for our interest in oil and gas properties as of December 31, 2013 relating to our leasehold acreage. Developed acres are acres spaced or assigned to productive wells including undrilled acreage held-byproduction under the terms of a lease. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of gas or oil, regardless of whether such acreage contains proved reserves. Gross acres are the total number of acres in which a working interest is owned. Net acres are the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

As at December 31, 2013, the Company’s developed and undeveloped acres are as follows:

  Developed Acreage Undeveloped Acreage Total
  Gross Net Gross Net Gross Net
Canada 9,640    6,324 4,780 1,024 14,420 7,348
U.S.A 2,240    1,611 90,580 70,064 92,820 71,675
TOTAL 11,880    7,935 95,360 71,088 107,240 79,023

The Company’s net undeveloped acres as of December 31, 2013, together with expiries for the period from 2014 to 2016 and thereafter is as follows.

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  Undeveloped Acreage

As of December 31, 2013

Net

2014 Expirations

2015 Expirations

2016 and thereafter
Expirations
Canada:        
Manning 1,024 - - 1,024
         
U.S.A:        
Ashley 480 -   480
Book Cliffs 4,002 3,682 320 -
Dinosaur 34,407 7,765 18,971 7,670
Gunnison 753     753
North Rangely 19,822 14,912 2,350 2,560
Pinyon Ridge 2,237 63   2,174
Plateau 3,014 -   3,014
Roan Creek 5,180 5,160 20 -
San Juan 169 169   -
Subtotal: 70,064 31,751 21,661 16,651
TOTAL: 71,088 31,751 21,661 17,675

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ITEM 4A. UNRESOLVED STAFF COMMENTS

Not Applicable.

ITEM 5.    OPERATING AND FINANCIAL REVIEW AND PROSPECTS

The following is a discussion of our consolidated operating results and financial position, including all our wholly-owned subsidiaries. It should be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2013 and related notes included therein under the heading "Item 18. Financial Statements" below.

The financial statements of the Company for the years ended December 31, 2013, 2012 and 2011 are prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”) and interpretations of the International Financial Reporting Interpretations Committee (“IFRIC”).

Certain forward-looking statements are discussed in this Item 5 with respect to our activities and future financial results. These are subject to risks and uncertainties that may cause projected results or events to differ materially from actual results or events. Readers should also read the "Cautionary Note Regarding Forward-Looking Statements" above and “Item 3. Key Information - Risk Factors.”

CRITICAL ACCOUNTING ESTIMATES

The Company makes estimates and assumptions about the future that affect the reported amounts of assets and liabilities. Estimates and judgments are continually evaluated based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. In the future, actual experience may differ from these estimates and assumptions.

The effect of a change in an accounting estimate is recognized prospectively by including it in profit or loss in the period of the change, if the change affects that period only; or in the period of the change and future periods, if the change affects both.

Information about critical judgments in applying accounting policies that have the most significant risk of causing material adjustment to the carrying amounts of assets and liabilities recognized in the consolidated annual financial statements within the next financial year are discussed below:

Decommissioning liability

Decommissioning liabilities have been recognized based on the Company’s internal estimates. Assumptions, based on the current economic environment, have been made which management believes are a reasonable basis upon which to estimate the future liability. These estimates take into account any material changes to the assumptions that occur when reviewed regularly by management. Estimates are reviewed at least annually and are based on current regulatory requirements. Significant changes in estimates of contamination and restoration techniques will result in changes to provisions from period to period. Actual decommissioning costs will ultimately depend on future market prices for the decommissioning costs which will reflect the market conditions at the time the decommissioning costs are actually incurred. The final cost of the currently recognized decommissioning provisions may be higher or lower than currently provided for.

Exploration and evaluation expenditure

The application of the Company’s accounting policy for exploration and evaluation expenditure requires judgment in determining whether it is likely that future economic benefits will flow to the Company, which is based on assumptions about future events or circumstances. Estimates and assumptions made may change if new information becomes available. If, after the expenditure is capitalized, information becomes available suggesting that the recovery of the expenditure is unlikely, the amount capitalized is written off in profit or loss in the period the new information becomes available.

Income taxes

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The Company recognizes the net future tax benefit related to deferred tax assets to the extent that it is probable that the deductible temporary differences will reverse in the foreseeable future. Assessing the recoverability of deferred tax assets requires the Company to make significant estimates related to expectations of future taxable income. Estimates of future taxable income are based on forecast cash flows from operations and the application of existing tax laws in each jurisdiction. To the extent that future cash flows and taxable income differ significantly from estimates, the ability of the Company to realize the net deferred tax assets recorded at the reporting date could be impacted. Additionally, future changes in tax laws in the jurisdictions in which the Company operates could limit the ability of the Company to obtain tax deductions in future periods. All tax filings are subject to audit and potential reassessment. Accordingly, the actual income tax liability may differ significantly from the estimated and recorded amounts.

Share-based payment transactions

The Company measures the cost of equity-settled transactions with employees by reference to the fair value of the equity instruments at the date at which they are granted. Estimating fair value for share-based payment transactions requires determining the most appropriate valuation model, which is dependent on the terms and conditions of the grant. This estimate also requires determining the most appropriate inputs to the valuation model including the expected life of the share option, volatility and dividend yield.

Financial contract liability

The application of the Company’s accounting policy for financial liabilities requires the Company to adjust the carrying amounts of the financial liabilities in the event it revises its payments or receipts to reflect actual and revised estimated cash flows. The Company’s financial contract liability was originally recognized at fair value using the effective interest method which ensures that any interest expense over the period of repayment is at a constant rate on the balance of the liability carried in the balance sheet.

At December 31, 2013, the balance of the financial contract liability was revised to reflect actual and revised estimated cash flows resulting in a gain in financial contract liability of $1,268,000. The revisions to the actual and revised cash flows resulted from i) downward revisions in estimated future net revenue from the 2013 sale of ethane in Dejour USA due to poor market conditions; ii) delays in the commencement of 2013 drilling operations in Dejour USA, and iii) an industry-standard, interim natural gas marketing contract in Dejour USA which failed to credit the Company with full natural gas liquids recoveries for 2013.

Despite the reduction in the carrying value of the financial contract liability at December 31, 2013, the corresponding asset on the Company’s balance sheet required no related charge for impairment. This resulted from a successful 2013 drilling program which converted 47 “probable” drilling locations at December 31, 2012 to “proven” as at December 31, 2013.

Impairment

A CGU is defined as the lowest grouping of integrated assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The allocation of assets into CGUs requires significant judgment and interpretations with respect to the integration between assets, the existence of active markets, similar exposure to market risks, shared infrastructures, and the way in which management monitors the operations. The recoverable amounts of CGUs and individual assets have been determined based on the higher of fair value less costs to sell or value-in-use calculations. The key assumptions the Company uses in estimating future cash flows for recoverable amounts are anticipated future commodity prices, expected production volumes and future operating and development costs. Changes to these assumptions will affect the recoverable amounts of CGUs and individual assets and may then require a material adjustment to their related carrying value. At December 31, 2013, the Company has two CGUs in Canada (Drake/Woodrush and Saddle Hills) and one CGU in the United States (Kokopelli).

Financial instrument

When estimating the fair value of financial instruments, the Company uses third-party models and valuation methodologies that utilize observable market data. In addition to market information, the Company incorporates transaction specific details that market participants would utilize in a fair value measurement, including the impact of non-performance risk.

40


Reserves

The estimate of reserves is used in forecasting the recoverability and economic viability of the Company’s oil and gas properties, and in the depletion and impairment calculations. The process of estimating reserves is complex and requires significant interpretation and judgment. It is affected by economic conditions, production, operating and development activities, and is performed using available geological, geophysical, engineering, and economic data. Reserves are evaluated at least annually by the Company’s independent reserve evaluators and updates to those reserves, if any, are estimated internally. Future development costs are estimated using assumptions as to the number of wells required to produce the commercial reserves, the cost of such wells and associated production facilities and other capital costs.

FUTURE ACCOUNTING PRONOUNCEMENTS

Certain pronouncements were issued by the International Accounting Standards Board (“IASB”) or the International Financial Reporting Interpretations Committee (“IFRIC”) that are mandatory for accounting periods beginning after January 1, 2014 or later periods.

The following new standards, amendments and interpretations, have not been early adopted in these consolidated annual financial statements. The Company is currently assessing the impact, if any, of this new guidance on the Company’s future results and financial position:

IFRS 9, Financial Instruments is part of the IASB's wider project to replace IAS 39 Financial Instruments: Recognition and Measurement. IFRS 9 retains but simplifies the mixed measurement model and establishes two primary measurement categories for financial assets: amortized cost and fair value. The basis of classification depends on the entity's business model and the contractual cash flow characteristics of the financial asset. The amendments to IFRS 9 will be effective as of January 1, 2018. The Company will continue to monitor the changes to this standard as they arise and will determine the impact accordingly.

IAS 36, Impairment of Assets was amended in May 2013. This standard reduces the circumstances in which the recoverable amount of CGUs is required to be disclosed and clarify the disclosures required when an impairment loss has been recognized or reversed in the period. The amendments to IAS 36 are effective as of January 1, 2014.

A.             Operating Results

The Company’s annual audited Consolidated Financial Statements for the year ended December 31, 2013, including 2012 and 2011 required comparative information, have been prepared in accordance with IFRS.

All financial information is stated in Canadian dollars, the Company’s presentation currency, unless otherwise noted.

Year ended December 31, 2013 compared to the year ended December 31, 2012

1.             Revenues

For the year ended December 31, 2013, total revenue, before royalties, increased by $2,435,000 or, 35%, due to a 35% increase in oil and gas production over the year ended December 31, 2012.

2.             Oil Operations

The average price received for oil sales in fiscal 2013 increased in line with the Edmonton Par oil prices which averaged $93.24 per barrel in fiscal 2013, compared to $86.53 per barrel received in fiscal 2012.

Average oil royalties paid for the year ended December 31, 2013 were consistent on a percentage basis with those paid in the year ended December 31, 2012.

41


Operating and transportation expenses averaged $26.75 per barrel in fiscal 2013. This represents a decrease of 29% from $37.57 per barrel in fiscal 2012. The decrease in per unit operating and transportation expenses in fiscal 2013 resulted from the non-recurring costs of major workovers on one of the oil producing wells at Woodrush in 2012 and the allocation of fixed operating costs over a higher oil production volume.

3.             Natural Gas Operations

The average price received for gas sales increased by 58% for fiscal 2013, relative to the corresponding period of the prior year. The increase in Dejour’s average realized gas price for the current year reflected higher benchmark prices.

Average gas royalties for fiscal 2013 were higher compared to the corresponding period of the prior year. Initiation of gas production from the four new wells at Kokopelli contributed to the increase in royalties in both periods as the effective rate in Colorado is approximately 50% higher than the lower royalty rates for marginal gas production in British Columbia. Additionally, lower gas royalty rates in 2012 are a result of lower gas prices and gas cost allowance credits under the Province of British Columbia royalty framework.

Operating and transportation expenses averaged $2.06 per mcf in fiscal 2013. This represents a decrease of 24% from $2.72 per mcf in fiscal 2012. The decrease in per unit operating and transportation expenses is due to the increase in lower-cost Colorado gas production as a percent of the Company’s total gas production.

4.             General and Administrative Expenses

G&A expenses in fiscal 2013 were consistent with the amount recorded for fiscal 2012. 2013 G&A includes the cost of a non-recurring severance payment of approximately $280,000 to a former senior officer of the Company. Adjusting for this payment results in a 12% reduction in G&A from the year ended December 31, 2012 to the year ended December 31, 2013.

Year ended December 31, 2012 compared to the year ended December 31, 2011

1.             Revenues

For the year ended December 31, 2012 (“fiscal 2012”), the Company recorded $6,882,000 in oil and natural gas sales as compared to $8,824,000 in oil and natural gas sales for the year ended December 31, 2011 (“fiscal 2011”). The decrease in gross revenues was due to lower realized oil and gas prices and lower oil and gas production.

2.             Oil Operations

The average price received for oil sales in fiscal 2012 decreased in line with the Edmonton Par oil prices which averaged $86.53 per barrel in fiscal 2012, compared to $97.87 per barrel received in fiscal 2011.

Average oil royalties paid for the year ended December 31, 2012 were consistent on a percentage basis with those paid in the year ended December 31, 2011.

Operating and transportation expenses averaged $37.57 per barrel in fiscal 2012. This represents an increase of 103% from $18.49 per barrel in fiscal 2012. The increase in per unit operating and transportation expenses in fiscal 2012 resulted from the non-recurring costs of major workovers on one of the oil producing wells at Woodrush in 2012 and higher waterflood implementation expenses.

3.             Natural Gas Operations

The average price received for gas sales decreased by 29% for fiscal 2012, relative to the corresponding period of the prior year. The decrease in Dejour’s average realized gas price for the current year reflected lower benchmark prices.

Average gas royalties for fiscal 2012 were lower compared to the corresponding period of the prior year. Substantial reduction in natural gas prices in 2012 resulted in lower gas royalties.

42


Operating and transportation expenses averaged $2.72 per mcf in fiscal 2012. This represents an increase of 20% from $2.26 per mcf in fiscal 2011. The increase in per unit operating and transportation expenses is due to the allocation of fixed operating costs over a lower gas production volume.

4.             General and Administrative Expenses

General and administrative expenses for fiscal 2012 decreased to $3,433,000 from $4,042,000 for fiscal 2011. The Board and management’s decision to not pay a bonus to employees for the year ended December 31, 2012 and the inclusion of such a bonus in 2011 accounted for much of the difference. Further, 2011 included non-recurring professional fees associated with the required conversion to the International Financial Reporting Standards (IFRS).

Financial Instruments and Risk Management

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, bank line of credit, loan facility and accounts payable and accrued liabilities. 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.

The primary risks and how the Company mitigates them are disclosed in Item 11 – Quantitative and Qualitative Disclosures About Market Risk, below.

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B.             Liquidity and Capital Resources

Going Concern, Bank Credit Facility and Loan Facility

The financial statements were prepared on a going concern basis. The going concern basis assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities and commitments in the normal course of business. As at December 31, 2013, the Company has a working capital deficiency of $8.9 million and accumulated deficit of $90.8 million. Of the $8.9 million deficiency, only $1.24 million is represented by obligations due within one year in the normal course of business. See WORKING CAPITAL POSITION herein.

On March 28, 2013, DEAL signed a new “Commitment Letter” with the Bank to renew its $5.95 million (December 31, 2012 - $6.0 million) revolving operating demand loan under the following terms and conditions:

(a)

“Credit Facility A” – Revolving Operating Demand Loan - $3.7 million, to be used for general corporate purposes, ongoing operations, capital expenditures, and acquisition of additional petroleum and natural gas assets. Interest on “Credit Facility A” is at Prime + 1% payable monthly and all amounts outstanding are payable on demand any time, and

   
(b)

“Credit Facility B” – Non-Revolving Demand Loan - $2.25 million. Interest on “Credit Facility B” was at Prime +3 1/2% payable monthly. Monthly principal payments of $200,000 were due and payable commencing March 26, 2013 with all amounts outstanding under “Credit Facility B” ($1.45 million) due and payable in full on June 30, 2013.

Collateral for Credit Facilities “A” and “B” (the “Credit Facilities”) is provided by a $10.0 million first floating charge over all the assets of DEAL, a general assignment of DEAL’s book debts, a $10.0 million debenture with a first floating charge over all the assets of the Company and an unlimited guarantee provided by Dejour USA. On June 5, 2013, DEAL renewed the Credit Facilities with the Bank and the maximum amount of Credit Facility “A” was reduced to $3.5 million. On June 19, 2013, Credit Facility “B” was repaid in full. Further, on December 16, 2013 and February 18, 2014, DEAL renewed the Credit Facility “A” with the Bank and contracted to utilize $600,000 of the $3.5 million to fund the proposed acquisition of certain producing natural gas properties in Canada until March 31, 2014. The acquisition closed on March 26, 2014. Effective March 1, 2014, the Credit Facility reduces by $100,000 per month. The next annual review is scheduled on or before May 1, 2014.

Under the terms of the Credit Facilities, DEAL is required to maintain a working capital ratio of greater than 1:1 at all times. The working capital ratio is defined as the ratio of (i) current assets (including any undrawn and authorized availability under the Credit Facilities) less unrealized hedging gains to (ii) current liabilities (excluding the current portion of outstanding balances of the facility) less unrealized hedging losses. As at December 31, 2013, DEAL was in compliance with its working capital ratio requirement.

On June 19, 2013, the Company borrowed $3.5 million (“Loan Facility”) from a Canadian institutional lender (“Lender”). The Loan Facility bears interest at 14%, payable monthly, and matures on December 14, 2014. The principal is repayable any time after December 18, 2013 without penalty. Security for the Loan Facility is comprised of a First Deed of Trust on certain of the Company’s U.S. oil and gas interests, including a general security agreement, a second mortgage on the Company’s Canadian properties, and the guaranty of the Company and Dejour USA.

As partial consideration for providing the Loan Facility, the Company issued the Lender 7,291,667 Warrants. Each Warrant entitles the holder to acquire one common share at a price of $0.24 per share any time prior to June 18, 2015. If the Company issues any common shares at a price per share less than $0.24 (the “Issue Price”) any time until December 18, 2013, then the exercise price of the Warrants would automatically be reduced to the higher of (i) the Issue Price and (ii) $0.20. Shares acquired through the exercise of Warrants prior to October 18, 2013 are restricted from sale through the facilities of the Canadian stock exchange.

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The Company’s ability to continue as a going concern is dependent upon attaining profitable operations and obtaining sufficient financing to meet obligations and continue exploration and development activities. There is no assurance that these activities will be successful. These material uncertainties cast substantial doubt upon the Company’s ability to continue as a going concern. The related consolidated financial statements do not reflect the adjustments to the carrying values of assets and liabilities, the reported revenues and expenses, and the balance sheet classifications used that would be necessary if the going concern assumptions were not appropriate.

Cash Balances

The Company had cash and cash equivalents of $505,000 as at December 31, 2013.

Financial Contract

On December 31, 2012, Dejour USA entered into a financial contract with a U.S. oil and gas drilling fund (“Drilling Fund”), that is associated through a relationship with a former director of the Company, to drill up to three wells and complete up to four wells (“the Tranche 1 Wells”) in the State of Colorado. By agreement:

(a)

Dejour USA contributed four natural gas well spacing units, including one drilled and cased well with a cost of US$1.1 million;

   
(b)

The Drilling Fund contributed US$6.5 million cash directly to a drilling company, that is owned by a former consultant of Dejour USA, as prepaid drilling costs. During the year ended December 31, 2013, the Drilling Fund also committed to invest a further US$500,000 in the four wells for a total of US$7.0 million. As at December 31, 2013, US$417,000 of the incremental US$500,000 has been invested for a total of US$6.9 million;

   
(c)

Dejour USA will earn a “before payout” working interest of 10% to 14% and an “after payout” working interest of 28% to 39% in the net operating profits from the Tranche 1 Wells based on the actual cash invested in the drilling program. In September 2013, Dejour USA signed an amendment with the Drilling Fund and agreed to earn the revised “before payout” working interest of 15.88% to 22.23% and revised “after payout” working interest of 29.77% to 41.67% in the net operating profits from the Tranche 1 Wells based on the actual cash invested in the drilling program;

   
(d)

The Drilling Fund has the right to require that Dejour USA purchase the Drilling Fund’s entire working interest in the Tranche 1 Wells 36 months after the commencement of production from the initial Tranche 1 Well. In the event the Drilling Fund exercises its right, the purchase price to be paid by Dejour USA will equal 75% of the Drilling Fund’s actual investment less 75% of the Drilling Fund’s share of working interest net profits from the Tranche 1 Wells, if any, for the 36-month period, plus a “top-up” amount so that the Drilling Fund earns a minimum 8% return, compounded annually and applied on a monthly basis, on 75% of its original investment over the 36-month period; and

   
(e)

The Drilling Fund has the right to require Dejour USA to purchase all of the Drilling Fund’s interest in the Tranche 1 Wells if at any time Dejour USA plans to divest of greater than 51% of its Working Interest in the Tranche 1 Wells and resigns as Operator (a “Change of Control Event”). The purchase price is equal to the future net profit from the “Proven and Probable Reserves” attributable to the Drilling Funds working interest in the Tranche 1 Wells, discounted at 12%, as determined by a third party evaluator acceptable to both parties.

45


Dejour USA considers the transaction to be a financial contract liability as the risks and rewards of ownership have not been substantially transferred at the Agreement date. On the Drilling Fund financing advance, the Company increased property and equipment and financial contract liability by $6.5 million (US$6.5 million). During the year ended December 31, 2013, the Company increased property and equipment and financial contract liability by $443,000 (US$417,000) of the incremental US$500,000 advance received in the year. On initial recognition, the Company imputed its borrowing cost of 8.4% based on the estimated timing and amount of operating profit using the independent reserve engineer’s estimated future cash flows for the Drilling Funds working interest in the Tranche 1 Wells. Subsequent to initial measurement the financial contract liability will be increased by the imputed interest expense and decreased by the Drilling Fund’s net operating profit from the Tranche 1 Wells. Any changes in the estimated timing and amount of the net operating profit cash flows will be discounted at the initial imputed interest rate with any change in the recognized liability recognized as a gain (loss) in the period of change. The Company has estimated the current portion of the obligation based on the expected net operating profit to be paid to the Drilling Fund in the next twelve months.

(CA$ thousands)    
Loan advance at December 31, 2012 (US$6,500)   6,467  
Loan advance during the year (US$417)   443  
Accretion expense (US$471)   486  
Foreign exchange loss   461  
    7,857  
Less:      
(a) Net operating income (US$441 paid in 2013)   (468 )
(b) Gain on financial contract liability (US$1,192)   (1,268 )
Balance at December 31, 2013 (US$5,755)   6,121  
Current portion of financial contract liability (US$1,173)   (1,248 )
Non-current portion of financial contract liability (US$4,582)   4,873  

The estimated reduction in the financial contract liability is estimated to be:

(CA$ thousands)   US$     CAD$  
2014   1,173     1,248  
2015   412     438  
2016   4,170     4,435  

Working Capital Position

As at December 31, 2013 (CA$ thousands)    $  
Working capital deficit   (8,908 )
Non-cash warrant liability   324  
Non-cash derivative liability   287  
Current portion of financial contract liability   1,248  
Adjusted working capital deficit   (7,049 )
Add: Bank line of credit   2,900  
Add: Loan facility   2,911  
Adjusted working capital (excluding bank line of credit and loan facility)   (1,248 )

Working capital is defined as current assets less current liabilities.

As at December 31, 2013, the Company had a working capital deficit of $8.9 million. Excluding the non-cash warrant liability of $0.3 million related to the fair value of US$ denominated warrants issued in previous equity financings, the non-cash derivative liability of $0.3 million related to the fair value of warrants issued in loan facility closed in June 2013 and the current portion of financial contract liability of $1.2 million, the adjusted working capital deficit was $7.0 million. The majority of the working capital deficit relates to the $2.9 million outstanding bank line of credit, with a $0.6 million credit limit remaining and the $2.9 million outstanding loan facility.

46


The bank line of credit is classified as current liabilities because it is a demand loan, subject to periodic review by the lender. At December 31, 2013, Dejour USA was in default of its working capital ratio covenant with the Canadian institutional lender (“Lender”) who provided the loan facility. As a result, the loan facility is due upon demand and classified as current liabilities. The Lender has not demanded repayment as at December 31, 2013.

The Company expects to fund future capital requirements and expenditures through the use of a combination of cash provided by operating activities and bank debt supplemented by new equity or debt offerings, as required.

Capital Resources

a)     Canada

During 2013, the Company incurred $31,000 of its consolidated capital expenditures of $2 million at Drake/Woodrush in northeastern British Columbia. These capital expenditures were funded by cash on hand and an operating line of credit of $3,500,000 provided by DEAL’s Canadian bank.

The Company has developed a capital budget of $2,500,000 to further develop the natural gas potential of its Drake/Woodrush properties. It is expected this program, if implemented, will be funded by one, or a combination, of the following sources:

i)

Existing bank operating line of credit;

   
ii)

Proceeds of a private placement or public offering of the Company’s shares, or

   
iii)

A joint venture financing arrangement with an industry participant.

b)     United States

The Company and partners drilled and completed 4 Williams Fork formation wells at the Company’s core Kokopelli natural gas property in the Piceance Basin in 2013. This drilling program increased the number of “proved undeveloped” drilling locations from 92 locations to 139 locations, as determined by the Company’s independent reservoir engineers in a report dated January 1, 2014.

The Company has monitored production from the 4 initial wells since the fourth well was placed on production in September 2013. The Company is now seeking a joint venture partner to purchase an interest in Kokopelli, provide a negotiated amount of financing to further develop “Phase II” of Kokopelli, and, initially pay for the Company’s share of drilling and completion costs up to a predetermined contractual maximum. Following completion of this initial capital expenditure, the Company will be responsible for its working interest share of remaining capital costs to fully develop Kokopelli.

2012

On December 31, 2012, the Company closed a US$6,500,000 financing with a Denver-based drilling fund to partially fund the initial development of the Company’s “Kokopelli” project in the eastern portion of the Piceance Basin. The Drilling Fund also committed to invest a further US$500,000 in the four wells for a total of US$7.0 million. As at December 31, 2013, US$417,000 of the incremental US$500,000 has been invested for a total of US$6.9 million. Under the terms of the industry-standard agreement, the Company will earn a “before-payout” (‘BPO’) working interest of 10% to 14% and an “after payout” (‘APO’) working interest of 28% to 39%. In September 2013, Dejour USA signed an amendment with the Drilling Fund and agreed to earn the revised “before payout” working interest of 15.88% to 22.23% and revised “after payout” working interest of 29.77% to 41.67% in the net operating profits from the Tranche 1 Wells based on the actual cash invested in the drilling program.

47


The agreement with the Drilling Fund provides for an additional two tranches of drilling under the following terms and conditions:

The Drilling Fund will have the right until August 2015, but not the obligation, to invest up to an additional US$8.5 million for a total of US$15.5 million in two additional tranches;

   

Tranche 3 estimated between US$4 million to US$5 million, can only be initiated within two years after committing to the full US$4 million to US$5 million in Tranche 2;

   

Dejour will receive a 10% BPO carried interest in all wells or partial wells drilled by the Drilling Fund, reverting to a 32.5% APO working interest. “Payout” to the Drilling Fund is defined as 125% of the capital investment amount on a tranche by tranche basis. In September 2013, Dejour USA signed an amendment with the Drilling Fund and will receive a revised BPO working interest of 15.88% to 22.23% in all wells or partial wells drilled by the Drilling Fund, reverting to a revised APO working interest of 29.77% to 41.67%. “Payout” to the Drilling Fund is defined as 150% of the capital investment amount on a tranche by tranche basis;

   

Tranche 2 and 3 wells will be funded only in conjunction with Dejour’s plans for development of Kokopelli. If, for example, no development is planned, the Drilling Fund’s option will remain in effect until Dejour presents a drilling plan to the Drilling Fund; and

   

The Drilling Fund does not earn the right to “put” its Tranche 2 and 3 working interests back to the Company under any circumstances.

C.             Research and Development, Patents and Licenses, etc.

None.

D.             Trend Information

During mid-December, 2013, the “polar vortex” resulted in record low temperatures for most of Canada and 2/3rds of the United States. High demand for natural gas drew working gas in storage in the U.S. down to well under the five year average. At the end of Q1 2014, working gas in storage was approximately 826 Bcf, roughly 849 Bcf less than the same period in 2013 and 997 Bcf off the five-year average.

The need to replenish the shortfall of natural gas in storage will likely contribute to a strong demand for natural gas for most of the remainder of 2014, extending into 2015. This supports the NYMEX futures prices for natural gas at the end of Q1 2014 which show strong prices in excess of US$4.50 per Mcf through June, 2015.

E.             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 at December 31, 2013.

F.             Tabular Disclosure of Contractual Obligations

As of December 31, 2013, and in the normal course of business we have obligations to make future payments, representing contracts and other commitments that are known and committed.

48



(CA$ thousands)   2014     2015     2016     2017     2018     Thereafter     Total  
    $     $     $     $     $     $     $  
Operating lease obligations   187     52     -     -     -     Nil     239  
Bank credit facility   2,900     -     -     -     -     Nil     2,900  
Loan facility   3,500     -     -     -     -     Nil     3,500  
Financial contract liability (1)   1,248     438     4,435     -     -     Nil     6,121  
Total   7,835     490     4,435     -           Nil     12,760  

(1)

This represents the Company’s obligations over the 36-month put option period until it expires. See Note 12 to the consolidated financial statements for

   
(2)

An estimate of interest on the debt cannot be made at this time.

G. Safe Harbor

The Company seeks safe harbor for our forward-looking statements contained in Items 5.E and F. See the heading “Cautionary Note Regarding Forward-Looking Statements” above.

ITEM 6.    DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

A.             Directors and Senior Management

The following table sets forth all current directors and executive officers of Dejour as of the date of this annual report on Form 20-F, with each position and office held by them in the Company and the period of service as such.

Name, Jurisdiction
of Residence and
Position (1)
Principal occupation or
employment during the past
5 years
Number of Dejour Common
Shares beneficially owned,
directly or indirectly, or
controlled or directed (2)
Percentage of Dejour
Common Shares
beneficially owned, directly
or indirectly, or controlled
or directed (2)
Director
Since
Robert L. Hodgkinson
British Columbia,
Canada
Director, Chairman and Chief Executive Officer
(Age: 64)

President of a private company, Hodgkinson Equities Corporation, which provides consulting services to emerging businesses in the petroleum resource industry. Formerly a director of Titan Uranium (TSX-V: TUE).

8,000,000 4.89% May 18, 2004
Dr. A. Gorrell (4)(5)
British Columbia,
Canada
Director
(Age: 69)

Dr. Gorrell has over 30 years’ experience with both private and public oil and gas property exploration and development in Western Canada and China. Dr. Gorrell has served as director, officer and controlling principal of several oil and gas ventures listed on the Toronto Stock Exchange. Currently, Dr. Gorrell is a director, President/CEO and Co-Chairman of Petromin Resources Ltd.

- - December 14, 2012
Richard Kennedy (3)(5)
Alberta, Canada
Director
(Age: 58)

Mr. Kennedy is a prominent barrister, solicitor and partner at Kennedy Agrios LLP, an Edmonton, Alberta based law firm focusing on commercial real estate, administrative and regulatory law.

294,900 0.18% December 14, 2012

49



Name, Jurisdiction
of Residence and
Position (1)
Principal occupation or
employment during the past
5 years
Number of Dejour Common
Shares beneficially owned,
directly or indirectly, or
controlled or directed (2)
Percentage of Dejour
Common Shares
beneficially owned, directly
or indirectly, or controlled
or directed (2)
Director
Since
Craig Sturrock (3)(4)(5)
British Columbia,
Canada
Director
(Age: 70)

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

650,000 0.40% August 22, 2005
Ronnie Bozzer (3)(4)
British Columbia,
Canada
Director
(Age: 64)

Mr. Bozzer has extensive years of legal practice encompassing mergers and acquisitions, banking and finance transactions, public private partnerships, syndications and securitizations.

450,000 0.28% January 15, 2014
David Matheson
British Columbia,
Canada
Chief Financial
Officer
(Age: 64)

Mr. Matheson has over 30 years of executive experience in the oil and gas industry in both operations and finance. He previously served as CFO and then as President of Equatorial Energy Ltd., a public Canadian oil and gas exploration & production company with operations in Canada and Indonesia. Mr. Matheson was admitted to the Institute of Chartered Accountants in British Columbia, the Northwest Territories, and Canada in 1975.

- - N/A

50



Name, Jurisdiction
of Residence and
Position (1)
Principal occupation or
employment during the past
5 years
Number of Dejour Common
Shares beneficially owned,
directly or indirectly, or
controlled or directed (2)
Percentage of Dejour
Common Shares
beneficially owned, directly
or indirectly, or controlled 
or directed (2)
Director
Since
Phillip Bretzloff, BA, LLB
British Columbia,
Canada
Vice President and
General Counsel
(Age: 64)

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

59,500 0.04% N/A
Neyeska Mut
EVP Operations,
Dejour Energy (USA)
Corp.
(Age: 56)

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

50,001 0.03% N/A

(1)

Each director will serve until the next annual general meeting of the Company or until a successor is duly elected or appointed in accordance with the Notice of Articles and Articles of the Company and the Business Corporations Act (British Columbia).

(2)

The number of common shares beneficially owned, directly or indirectly, or over which control or direction is exercised is based upon information furnished to the Company by individual directors and executive officers.

(3)

Member of audit committee .

(4)

Member of reserves committee .

(5)

Member of compensation and corporate governance committee .

Directors and Executive Officers

Brief biographies for Dejour's directors and executive officers are set forth below:

Robert L. Hodgkinson: Mr. Hodgkinson was the founder and Chairman of Optima Petroleum, which drilled wells in Alberta and the Gulf of Mexico before merging to form Petroquest Energy, a NASDAQ traded company. Subsequently, he founded and was CEO of Australian Oil Fields, which would later merge to become Resolute Energy/Cardero Energy Inc. Mr. Hodgkinson was also a Vice-President and partner of Canaccord Capital Corporation, and an early stage investor and original lease financier in Synenco Energy's Northern Lights Project in the Alberta oil sands.

Dr. A. Gorrell: Dr. Gorrell has over 30 years’ experience with both private and public oil and gas property exploration and development in Western Canada and China. Dr. Gorrell has served as director, officer and controlling principal of several oil and gas ventures listed on the Toronto Stock Exchange. Currently, Dr. Gorrell is a director, President/CEO and Co-Chairman of Petromin Resources Ltd.

Richard Kennedy: Mr. Kennedy is a prominent barrister, solicitor and partner at Kennedy Agrios LLP, an Edmonton, Alberta based law firm focusing on commercial real estate, administrative and regulatory law.

51


Craig Sturrock: Mr. Sturrock has served as a director and founding member of various public and private companies. Admitted to the British Columbia Bar in 1969, he joined Thorsteinssons LLP, tax lawyers in 1971. He served for 15 years as a tax lawyer and partner at Birnie, Sturrock & Company returning to Thorsteinssons as a partner in 1989. He is an author and speaker for the Canadian and British Columbia Bar Associations, the Continuing Legal Education Society of British Columbia and the Canadian Tax Foundation. He is also a former member of the Board of Governors of the Canadian Tax Foundation.

Ronnie Bozzer: Mr. Bozzer's legal practice encompasses mergers and acquisitions, banking and finance transactions, public private partnerships, syndications and securitizations. His honours include recieving the highest peer review rating by Martindale Hubbell, becoming Chairman of Canada's International Finance Centre and recognition by "2010 Best Lawyers in Canada" in the specialty of Banking Law. Mr Bozzer is also listed as Candian Leading Lawyer in the field of Corporate Law by "Law Day".

David Matheson : Mr. Matheson has over 30 years of executive experience in the oil and gas industry in both operations and finance. He previously served as CFO and then as President of Equatorial Energy Ltd., a public Canadian oil and gas exploration & production company with operations in Canada and Indonesia. Mr. Matheson was admitted to the Institute of Chartered Accountants in British Columbia, the Northwest Territories, and Canada in 1975.

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

Neyeska Mut : Since 2000, Ms. Mut has been President of Nycon Energy Consulting working as an advisor to two major oil companies. Prior to forming Nycon Energy Consulting, Ms. Mut pursued international opportunities with Atlantic Richfield Corporation. Ms. Mut has been with Dejour since 2008.

Family Relationships

There are no family relationships between any directors or executive officers of the Company.

Arrangements

There are no known arrangements or understandings with any major shareholders, customers, suppliers or others, pursuant to which any of the Company’s officers or directors was selected as an officer or director of the Company, other than indicated immediately above and at “Item 7. Major Shareholders and Related Party Transactions - Related Party Transactions.”

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

52


To the knowledge of the Company, no director or executive officer of the Company is, or has been in the last ten years, a director, chief executive officer or chief financial officer of an issuer that, while that person was acting in that capacity, (a) was the subject of a cease trade order or similar order or an order that denied the issuer access to any exemptions under Canadian securities legislation, for a period of more than 30 consecutive days, or (b) was subject to an event that resulted, after that person ceased to be a director, chief executive officer or chief financial officer, in the issuer being the subject of a cease trade or similar order or an order that denied the issuer access to any exemption under Canadian securities legislation, for a period of more than 30 consecutive days. To the knowledge of the Company, no director or executive officer of the Company, or a shareholder holding a sufficient number of securities in the Company to affect materially the control of the Company, is or has been in the last ten years, a director or executive officer of an issuer that, while or acting in that capacity within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets. To the knowledge of the Company, in the past ten years, no such person has become bankrupt, made a proposal under any legislation related to bankruptcy or insolvency, or was subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold their assets.

Conflicts of Interest

Certain of the Company's directors and officers serve or may agree to serve as directors or officers of other reporting companies or have significant shareholdings in other reporting companies and, to the extent that such other companies may participate in ventures in which the Company may participate, the directors of the Company may have a conflict of interest in negotiating and concluding terms respecting the extent of such participation. In the event that such a conflict of interest arises at a meeting of the Company's directors, a director who has such a conflict will abstain from voting for or against the approval of such participation or such terms and such director will not participate in negotiating and concluding terms of any proposed transaction. From time to time, several companies may participate in the acquisition, exploration and development of natural resource properties thereby allowing for their participation in larger programs, permitting involvement in a greater number of programs and reducing financial exposure in respect of any one program. It may also occur that a particular company will assign all or a portion of its interest in a particular program to another of these companies due to the financial position of the company making the assignment. Under the laws of the Province of British Columbia, the directors of the Company are required to act honestly, in good faith and in the best interests of the Company. In determining whether or not the Company will participate in a particular program and the interest therein to be acquired by it, the directors will primarily consider the degree of risk to which the Company may be exposed and its financial position at that time. See also "Description of the Business – Risk Factors".

B.              Compensation

Basis of Compensation for Executive Officers

The Company compensates its executive officers through a combination of base compensation, bonuses and Common Stock options. The base compensation provides an immediate cash incentive for the executive officers. Bonuses encourage and reward exceptional performance over the financial year. Common Stock options ensure that the executive officers are motivated to achieve long term growth of the Company and continuing increases in shareholder value. In terms of relative emphasis, the Company places more importance on Common Stock options as long term incentives. Bonuses are related to performance and may form a greater or lesser part of the entire compensation package in any given year. Each of these means of compensation is briefly reviewed in the following sections.

Base Compensation

Base compensation, including that of the Chief Executive Officer, are set by the Compensation Committee and approved by the Board of Directors on the basis of the applicable executive officer’s responsibilities, experience and past performance. The compensation program is intended to provide a base compensation competitive among companies of a comparable size and character in the oil and gas industry. In making such an assessment, the Board considers the objectives set forth in the Company’s business plan and the performance of executive officers and employees in executing the plan in combination with the overall result of the activities undertaken.

53


Common Stock Options

The Company provides long term incentive compensation to its executive officers through the Common Stock Option Plan, which is considered an integral part of the Company’s compensation program. Upon the recommendation of management and approval by the Board of Directors, stock options are granted under the Company’s Option Plan to new directors, officers and key employees, usually upon their commencement of employment with the Company. The Board approves the granting of additional stock options from time to time based on its assessment of the appropriateness of doing so in light of the long term strategic objectives of the Company, its current stage of development, the need to retain or attract key technical and managerial personnel in a competitive industry environment, the number of stock options already outstanding, overall market conditions, and the individual’s level of responsibility and performance within the Company.

The Board views the granting of stock options as a means of promoting the success of the Company and creating and enhancing returns to its shareholders. As such, the Board does not grant stock options in excessively dilutive numbers. Total options outstanding are presently limited to 10% of the total number of shares outstanding under the rules of the TSX. Grant sizes are, therefore, determined by various factors including the number of eligible individuals currently under the Option Plan and future hiring plans of the Company.

The Board granted a total of 3,750,000 stock options to the executive officers in 2013.

Summary Compensation Table

The following table provides a summary of the compensation earned during the fiscal year ended December 31, 2013 for the Named Executive Officers and Directors listed in the table below.

54



    Annual Compensation Long Term Compensation  
Name and
principal
position



Year











Salary
($)










Consulting
Fees
($)









Bonus
($)




Awards Payouts
($)




All other
compensation
($)



Securities
Under
Option/
SAR's
Granted
(#)
Shares/
Units
Subject to
Resale
Restrictions
($)
Robert
Hodgkinson,
Director,
Chairman and
Chief
Executive
Officer
2013
2012
2011









78,000
78,000
78,000









177,000
177,000
177,000









Nil
Nil
100,000



775,000
775,000
300,000



Nil
Nil
Nil



Nil
Nil
Nil



Nil
Nil
Nil



Harrison
Blacker,
Director and
President of
Dejour Energy
(USA) (1)
2013
2012
2011


US$
US$
US$


310,000
326,688
295,000







Nil
Nil
Nil


US$
US$
US$


Nil
Nil
135,000


775,000
775,000
300,000


Nil
Nil
Nil


Nil
Nil
Nil


Nil
Nil
58,000 (2)


Stephen Mut,
Director and
Co-Chairman (3)
2013
2012
2011


Nil
Nil
Nil
US$
US$
US$
Nil
17,191
138,573


Nil
Nil
Nil
325,000
375,000
300,000
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Craig Sturrock,
Director
2013
2012
2011


Nil
Nil
Nil


Nil
Nil
Nil


Nil
Nil
Nil
250,000
250,000
100,000
Nil
Nil
Nil
Nil
Nil
Nil
7,500
7,500
7,000
Darren Devine,
Director (4)
2013
2012
2011


Nil
Nil
Nil


Nil
Nil
Nil


Nil
Nil
Nil
200,000
200,000
100,000
Nil
Nil
Nil
Nil
Nil
Nil
2,000
7,000
7,000
Richard
Bachmann
Director (5)
2013
2012


Nil
Nil


Nil
Nil


Nil
Nil
Nil
500,000
Nil
Nil
Nil
Nil
7,500
Nil
Dr. A. Gorrell
Director
2013
2012

Nil
Nil

Nil
Nil

Nil
Nil
Nil
300,000
Nil
Nil
Nil
Nil
7,000
500
Richard
Kennedy
Director
2013
2012


Nil
Nil


Nil
Nil


Nil
Nil
Nil
300,000
Nil
Nil
Nil
Nil
6,500
500
David
Matheson,
Chief Financial
Officer (6)
2013





188,141





Nil





Nil


750,000


Nil


Nil


Nil


Mathew Wong,
Chief Financial
Officer (7)
2013
2012
2011


5,650
78,000
78,000


26,052
151,000
151,000


Nil
Nil
100,000
Nil
250,000
300,000
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Neyeska Mut,
EVP
Operations of
Dejour Energy
(USA)
2013
2012
2011

US$
US$
US$

200,470
200,470
200,470





Nil
Nil
Nil

US$
US$
US$

Nil
Nil
100,000

450,000
400,000
306,000

Nil
Nil
Nil

Nil
Nil
Nil

Nil
Nil
Nil

Phil Bretzloff,
VP and
General
Counsel
2013
2012
2011



Nil
Nil
Nil



141,647
141,584
130,984



Nil
Nil
13,320
225,000
225,000
140,000
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil
Nil

(1)

Mr. Blacker was the President of Dejour Energy (USA) Corp. until January 15, 2014, when he departed the Corporation. He ceased to be an executive officer and director of the Corporation effective that date.

(2)

US$58,000 was paid for relocation expenses reimbursement.

(3)

Mr. Mut resigned from the Board on January 15, 2014.

(4)

Mr. Devine resigned from the Board on April 10, 2013.

(5)

Mr. Bachmann resigned from the Board on January 15, 2014.

(6)

On January 28, 2013, Mr. Matheson was appointed Chief Financial Officer of the Corporation.

55



(7)

On January 28, 2013, Mr. Wong resigned from his position as Chief Financial Officer and ceased to be an executive officer of the Corporation on the date of his resignation. Amount represents Mr. Wong’s remuneration from January 1, 2013 to January 28, 2013 of $31,702 in his capacity as Chief Financial Officer.

Stock Option Grants


Name
Number of
Options Granted
Exercise Price
per Share
Grant Date
Expiration Date
Robert Hodgkinson 775,000 $0.18 April 4, 2013 April 3, 2016
Harrison Blacker 775,000 $0.18 April 4, 2013 April 3, 2016
Stephen Mut 325,000 $0.18 April 4, 2013 April 3, 2016
Craig Sturrock 250,000 $0.18 April 4, 2013 April 3, 2016
Darren Devine 200,000 $0.18 April 4, 2013 April 3, 2016
David Matheson 500,000 $0.20 February 12, 2013 February 11, 2016
David Matheson 250,000 $0.18 April 4, 2013 April 3, 2016
Neyeska Mut 450,000 $0.18 April 4, 2013 April 3, 2016
Phil Bretzloff 225,000 $0.18 April 4, 2013 April 3, 2016

Director Compensation

The Company has compensation agreements for its Directors who are not executive officers. Under the agreements, Directors receive $2,500 per meeting for the first 4 meetings each year, and $1,500 for each meeting thereafter. The Board of Directors may award special remuneration to any Director undertaking any special services on behalf of the Company other than services ordinarily required of a Director. Per an amendment to the agreements approved by the Board of Directors, effective January 1, 2010, the Directors received $1,000 per quarter plus $500 for each meeting.

Long Term Incentive Plan Awards

Long term incentive plan awards (" LTIP ") means any plan providing compensation intended to serve as an incentive for performance to occur over a period longer than one financial year, whether the performance is measured by reference to financial performance of the Company or an affiliate of the Company, the price of the Company's shares, or any other measure, but does not include option or stock appreciation rights plans or plans for compensation through restricted shares or units. The Company did not award any LTIPs to any executive officer during the most recently completed financial year ended December 31, 2013. There are no pension plan benefits in place for the executive officers.

Stock Appreciation Rights

Stock appreciation rights (" SARs ") means a right, granted by the Company or any of its subsidiaries as compensation for services rendered or in connection with office or employment, to receive a payment of cash or an issue or transfer of securities based wholly or in part on changes in the trading price of the Company's shares. No SARs were granted to, or exercised by, any executive officer of the Company during the most recently completed financial year ended December 31, 2013.

Bonus/Profit Sharing/Non-Cash Compensation

The Board adopted a bonus plan for eligible executives, which include the senior executives of the Company or any subsidiary of the Company, including but not limited to the CEO, President, Executive Vice-President and CFO who, by the nature of their positions are, in the opinion of the Committee, in a senior position to contribute to the success of the Company.

The bonus plan includes both non-discretionary and discretionary portions.

  A)

Executives Non-Discretionary;

     
 

Each Eligible Executives will receive a USD$100,000 award should:

56



  i)

Total Shareholder Return % exceeds Total XEG Return % by a minimum of 10% and in addition. For purposes of the bonus plan, “ XEG ” is defined as the iShares™ CDN Energy Sector Index Fund, trading under the symbol “XEG” on the TSX. Total Shareholder Return and Total XEG Return are based on the 20 days average closing shares price of Dejour shares and XEG on the TSX at the end of each fiscal year.;

     
  ii)

Total Shareholder Return is positive (the share price of Dejour shares is higher at the end of the year, in comparison to, the price of the shares at the beginning of the year).


 

For example, for fiscal 2011, if Total Shareholder Return % is 20%, while Total XEG Return is 5%, then Dejour’s stock outperformed the XEG by 15% and a USD$100,000 award is payable to each executives. However, this award would only be payable in the event that during the same period shareholder return is positive.

     
  B)

Executives Discretionary;

     
 

The Compensation Committee, upon the recommendation of the CEO, shall review (i) performance goals and objectives (“Performance Targets') for the Company and the subsidiaries for such period and (ii) target awards (“Target Awards') for each Participant which shall be based on, up to 30% of the Participant's base compensation, provided however, the Performance Targets for each Executive Participants shall be exactly the same during each year, calculated based on the same percentage of each Participants base compensation, unless otherwise agreed by the Participants.

     
 

Such Performance Targets shall include but not be limited to the following:


 

Increase in oil & gas production;

Achievement of financial stability and working capital position including compliance with the Company loan covenants;

 

Increase in Proved Developed Production (PDP) Reserves;

 

Increase in Proved and Probable (2P) reserves;

Creating significant positive impact on the Company business as demonstrated by significant accomplishments not in the base budget/business plan;

 

Increase in Operating Cash flow and Adjusted EBITDA;

 

Reduce operation costs;

 

Reducing overhead costs;

 

Other factors or extraordinary success, that in the opinion of the Committee, enhance shareholder value.

Pension/Retirement Benefits

No funds were set aside or accrued by the Company during fiscal 2013 to provide pension, retirement or similar benefits for Directors or Senior Management.

C.             Board Practices

Compensation and Corporate Governance Committee

The Company has a Compensation and Corporate Governance Committee composed of three Directors, Richard Kennedy, Dr. A. Gorrell and Craig Sturrock.

Role of the Compensation and Corporate Governance Committee

The Compensation and Corporate Governance Committee exercises general responsibility regarding overall executive compensation. The Board sets the annual compensation, bonus, options and other benefits of the Chief Executive Officer and approves compensation for all other executive officers of the Corporation after considering the recommendations of the Compensation and Corporate Governance Committee. Each or the members of the Compensation and Corporate Governance Committee has extensive experience in management and compensation procedures.

57


The members of the Compensation and Corporate Governance Committee do not have fixed terms and are appointed and replaced from time to time by resolution of the Board of Directors.

Audit Committee

The Company’s Board of Directors has a separately-designated standing Audit Committee established for the purpose of overseeing the accounting and financial reporting processes of the Company and audits of the Company’s annual financial statements in accordance with Section 3(a)(58)(A) of the Exchange Act. As of the date of this annual report on Form 20-F, the Company’s Audit Committee is comprised of Richard Kennedy, Craig Sturrock and Ronnie Bozzer.

In the opinion of the Company’s Board of Directors, all the members of the Audit Committee are independent (as determined under Rule 10A-3 of the Exchange Act and Section 803A of the NYSE Amex Company Guide). The Audit Committee meets the composition requirements set forth by Section 803B(2) of the NYSE Amex Company Guide. All two members of the Audit Committee are financially literate, meaning they are able to read and understand the Company’s financial statements and to understand the breadth and level of complexity of the issues that can reasonably be expected to be raised by the Company’s financial statements.

The members of the Audit Committee do not have fixed terms and are appointed and replaced from time to time by resolution of the Board of Directors.

Terms of Reference for the Audit Committee

Audit Committee Mandate

The primary function of the audit committee is to assist the Board in fulfilling its financial oversight responsibilities by reviewing the financial reports and other financial information provided by the Company to regulatory authorities and Shareholders, the Company’s systems of internal controls regarding finance and accounting and the Company’s auditing, accounting and financial reporting processes. Consistent with this function, the audit committee will encourage continuous improvement of, and should foster adherence to, the Company’s policies, procedures and practices at all levels. The audit committee’s primary duties and responsibilities are to:

  • Serve as an independent and objective party to monitor the Company’s financial reporting and internal control system and review the Company’s financial statements;
  • Review and appraise the performance of the Company’s external auditors; and
  • Provide an open avenue of communication among the Company’s auditors, financial and senior management and the Board.

Composition

The audit committee shall be comprised of three Directors as determined by the Board, the majority of whom shall be free from any relationship that, in the opinion of the Board, would interfere with the exercise of his or her independent judgment as a member of the audit committee.

At least one member of the audit committee shall have accounting or related financial management expertise. All members of the audit committee that are not financially literate will work towards becoming financially literate to obtain a working familiarity with basic finance and accounting practices. For the purposes of the Company's Charter, the definition of “financially literate” is the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can presumably be expected to be raised by the Company's financial statements.

The members of the audit committee shall be elected by the Board at its first meeting following the annual Shareholders’ meeting. Unless a Chair is elected by the full Board, the members of the audit committee may designate a Chair by a majority vote of the full audit committee membership.

58


Meetings

The audit committee shall meet a least twice annually, or more frequently as circumstances dictate. As part of its job to foster open communication, the audit committee will meet at least annually with the Chief Financial Officer and the external auditors in separate sessions.

Responsibilities and Duties

To fulfill its responsibilities and duties, the audit committee shall:

Documents/Reports Review

(a)

Review and update this Charter annually.

(b)

Review the Company's financial statements, MD&A and any annual and interim earnings, press releases before the Company publicly discloses this information and any reports or other financial information (including quarterly financial statements), which are submitted to any governmental body, or to the public, including any certification, report, opinion, or review rendered by the external auditors.

(c)

Approve, on behalf of the Board, the Corporation’s interim financial statements to be filed pursuant to section 4.3 of NI 51-102, before the Corporation publicly discloses such information.

External Auditors

(a)

Review annually, the performance of the external auditors who shall be ultimately accountable to the Board and the audit committee as representatives of the Shareholders of the Company.

(b)

Obtain annually, a formal written statement of external auditors setting forth all relationships between the external auditors and the Company, consistent with Independence Standards Board Standard 1.

(c)

Review and discuss with the external auditors any disclosed relationships or services that may impact the objectivity and independence of the external auditors.

(d)

Take, or recommend that the full Board take, appropriate action to oversee the independence of the external auditors.

(e)

Recommend to the Board the selection and, where applicable, the replacement of the external auditors nominated annually for Shareholder approval.

(f)

At each meeting, consult with the external auditors, without the presence of management, about the quality of the Company’s accounting principles, internal controls and the completeness and accuracy of the Company's financial statements.

(g)

Review and approve the Company's hiring policies regarding partners, employees and former partners and employees of the present and former external auditors of the Company.

(h)

Review with management and the external auditors the audit plan for the year-end financial statements and intended template for such statements.

(i)

Review and pre-approve all audit and audit-related services and the fees and other compensation related thereto, and any non-audit services, provided by the Company’s external auditors. The pre-approval requirement is waived with respect to the provision of non-audit services if:


  i.

the aggregate amount of all such non-audit services provided to the Company constitutes not more than five percent of the total amount of revenues paid by the Company to its external auditors during the fiscal year in which the non-audit services are provided;

  ii.

such services were not recognized by the Company at the time of the engagement to be non-audit services; and

  iii.

such services are promptly brought to the attention of the audit committee by the Company and approved prior to the completion of the audit by the audit committee or by one or more members of the audit committee who are members of the Board to whom authority to grant such approvals has been delegated by the audit committee.

Provided the pre-approval of the non-audit services is presented to the audit committee's first scheduled meeting following such approval such authority may be delegated by the audit committee to one or more independent members of the audit committee.

59


Financial Reporting Processes

(a)

In consultation with the external auditors, review with management the integrity of the Company's financial reporting process, both internal and external.

(b)

Consider the external auditors’ judgments about the quality and appropriateness of the Company’s accounting principles as applied in its financial reporting.

(c)

Consider and approve, if appropriate, changes to the Company’s auditing and accounting principles and practices as suggested by the external auditors and management.

(d)

Review significant judgments made by management in the preparation of the financial statements and the view of the external auditors as to appropriateness of such judgments.

(e)

Following completion of the annual audit, review separately with management and the external auditors any significant difficulties encountered during the course of the audit, including any restrictions on the scope of work or access to required information.

(f)

Review any significant disagreement among management and the external auditors in connection with the preparation of the financial statements.

(g)

Review with the external auditors and management the extent to which changes and improvements in financial or accounting practices have been implemented.

(h)

Review any complaints or concerns about any questionable accounting, internal accounting controls or auditing matters.

(i)

Review certification process.

(j)

Establish a procedure for the confidential, anonymous submission by employees of the Company of concerns regarding questionable accounting or auditing matters.

Other

Review any related-party transactions

Audit Committee Oversight

At no time since the commencement of the Company’s most recently completed financial year was a recommendation of the audit committee to nominate or compensate an external auditor not adopted by the Board of Directors.

D.             Employees

The Company had the equivalent of approximately 10 full-time employees and consultants during 2013 (Canada: 6 and United States: 4).

E.              Share Ownership

Directors and Officer Beneficial Ownership

The following table discloses as of April 24, 2014, Directors and Senior Management who beneficially own the Company's voting securities, consisting solely of common shares, and the amount of the Company's voting securities owned by the Directors and Senior Management as a group.

60


Shareholdings of Directors and Senior Management as of April 24, 2014

Title of
Class
Name of Beneficial Owner

Note

Amount and Nature
of Beneficial
Ownership
Percent of Class

         
Common Robert L. Hodgkinson (1) 11,456,818 7.01%
Common Dr. A. Gorrell (2) 350,000 0.21%
Common Richard Kennedy (3) 794,900 0.49%
Common Craig Sturrock (4) 1,650,000 1.01%
Common Ronnie Bozzer (5) 950,000 0.58%
Common David Matheson (6) 1,700,000 1.04%
Common Neyeska Mut (7) 1,775,001 1.09%
Common Phillip Bretzloff (8) 784,500 0.48%
  Total Directors/Management   19,461,219 11.91%

(1)

Of these shares, 8,000,000 are represented by common shares, 56,250 are represented by vested stock options and 681,818 are represented by currently exercisable share purchase warrants. 1,500,000 of these shares are owned by 7804 Yukon Inc., a private company owned by Robert Hodgkinson. A further 2,718,750 stock options have been granted but not yet vested.

(2)

Of these shares, 231,250 are represented by vested stock options. A further 118,750 stock options have been granted but not yet vested.

(3)

Of these shares, 294,900 are represented by common shares and 37,500 are represented by vested stock options. A further 462,500 stock options have been granted but not yet vested.

(4)

Of these shares, 650,000 are represented by common shares, 12,500 are represented by vested stock options and 150,000 are represented by currently exercisable share purchase warrants. A further 837,500 stock options have been granted but not yet vested.

(5)

Of these shares, 450,000 are represented by common shares and 50,000 are represented by vested stock options. A further 450,000 stock options have been granted but not yet vested.

(6)

Of these shares, 181,250 are represented by vested stock options. A further 1,518,750 stock options have been granted but not yet vested.

(7)

Of these shares, 50,001 are represented by common shares and 56,250 are represented by vested stock options. A further 1,668,750 stock options have been granted but not yet vested.

(8)

Of these shares, 59,500 are represented by common shares and 6,250 are represented by vested stock options. A further 718,750 stock options have been granted but not yet vested.


All percentages based on 163,753,874 shares outstanding as of April 24, 2014.
 

61


Stock Option Plan

We have a Stock Option Plan (the “Option Plan”), the principal purposes of which is to (i) advance our interests by aiding us, and our subsidiaries, in motivating, attracting and retaining key employees and directors capable of assuring the future success of the Company; and (ii) secure for us and our shareholders the benefits inherent in the ownership of our common shares by key employees and directors of the Company and our subsidiaries. We also have a United States stock incentive sub-plan that was initially approved in 2009 and amended in 2012 (the “Sub-Plan”) and forms a part of the Option Plan. Any option granted under the Sub-Plan is also subject to the terms and conditions of the Option Plan. Where there is a conflict between the terms and conditions of the Sub-Plan and the terms and conditions of the Option Plan, the terms and conditions of the Option Plan govern.

Directors, officers, employees and other insiders of us or any of our subsidiaries, as well as any person or corporation engaged to provide services for us or for any entity controlled by us for an initial, renewable or extended period of twelve months or more (or a lesser period of time if approved by the committee that administers the Option Plan and acceptable to the Toronto Stock Exchange (the “TSX”) (including individuals employed by such person or corporation), are eligible to participate in the Option Plan. Eligible participants who are natural persons resident in the United States, United States citizens, or are otherwise subject to United States tax law may participate in the Sub-Plan.

At the time of grant of any option, the aggregate number of common shares reserved for issuance under the Option Plan (which includes the Sub-Plan) that may be made subject to options any time and from time to time, together with common shares reserved for issuance at that time under any of our other share compensation arrangements, may not exceed 10% of the total number of issued and outstanding common shares, on a non-diluted basis, on the date of grant of the option. Of this 10%, the number of common shares reserved for issuance to any one participant pursuant to the Sub-Plan in any year may not exceed 5% of our total outstanding common shares on a non-diluted basis. Common shares subject to any option (or portion thereof) under the Option Plan that has been cancelled or otherwise terminated prior to the issuance or transfer of such common shares will again be available for options under the Option Plan. The number of common shares authorized under the Option Plan may be increased, decreased or fixed by the Board of Directors. Subject to adjustment in accordance with the Sub-Plan, a maximum of 18,500,000 common shares, less those common shares issued under the Option Plan, may be issued pursuant to stock options issued under the Sub-Plan. To clarify this rule, notwithstanding the number of options permitted under the US Sub-Plan to a total of 18.5 million, the Company is still bound by its Option Plan whereby the maximum number of shares that can be awarded as options is still 10%, but within the 10% as permitted, up to 18,500,000 can be allocated to the US Sub-Plan. If a stock option terminates, is forfeited or is cancelled without the issuance of any common shares, or any common shares covered by a stock option or to which a stock option relates are not issued for any other reason, then the number of common shares counted against the aggregate number of common shares available under the Sub-Plan with respect to such stock option, to the extent of any such termination, forfeiture, cancellation or other event, will again be available for granting stock options under the Sub-Plan.

The option exercise price will be determined by the committee that administers the Option Plan or the Sub-Plan administrator, as applicable. The exercise price may not be less than the last closing price per common share on the TSX on the trading day immediately preceding the day the options are granted, or if the common shares are not listed on the TSX, on the most senior of any other exchange on which the common shares are then traded, on the last trading day immediately preceding the date of grant of such options.

The Option Plan may be terminated by the committee that administers the Option Plan at any time. The Sub-Plan terminates at midnight on January 5, 2022, unless it is terminated before then by our Board of Directors. Any option outstanding under the Option Plan or Sub-Plan at the time of termination shall remain in effect until such option has been exercised, has expired, has been surrendered to us or has been terminated.

A copy of the Option Plan and Sub-Plan is incorporated by reference into this Form 20-F as Exhibits 4.17 and 4.18, respectively.

Stock Options Outstanding

The names and titles of the Directors/Executive Officers of the Company to whom outstanding stock options have been granted and the number of common shares subject to such options is set forth in the following table as of April 25, 2013:

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Stock Options Outstanding as of April 24, 2014

Name Number of Options Number of Exercise Price Grant Date Expiration Date
  Held Options per Option    
    Vested      
           
Robert Hodgkinson 450,000 56,250                  $0.20 1/31/2014 1/30/2019
  2,325,000 0                  $0.26 4/9/2014 4/8/2017
Dr. A. Gorrell 300,000 225,000                  $0.20 12/18/2012 12/17/2015
  50,000 6,250                  $0.20 1/31/2014 1/30/2019
Richard Kennedy 100,000 25,000                  $0.20 12/18/2012 12/17/2015
  100,000 12,500                  $0.20 1/31/2014 1/30/2019
  300,000 0                  $0.26 4/9/2014 4/8/2017
Craig Sturrock 100,000 12,500                  $0.20 1/31/2014 1/30/2019
  750,000 0                  $0.26 4/9/2014 4/8/2017
Ronnie Bozzer 400,000 50,000                  $0.20 1/31/2014 1/30/2019
  100,000 0                  $0.26 4/9/2014 4/8/2017
David Matheson 250,000 62,500                  $0.20 2/12/2013 2/11/2016
  100,000 25,000                  $0.18 4/4//2013 4/3/2013
  750,000 93,750                  $0.20 1/31/2014 1/30/2019
  600,000 0                  $0.26 4/9/2014 4/8/2017
Neyeska Mut 450,000 56,250                  $0.20 1/31/2014 1/30/2019
  1,275,000 0                  $0.26 4/9/2014 4/8/2017
Phillip Bretzloff 50,000 6,250                  $0.20 1/31/2014 1/30/2019
  675,000 0                  $0.26 4/9/2014 4/8/2017
Total Officers/Directors 9,125,000 631,250      

63


ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS .

A.              Major Shareholders

Shareholders

The Company is aware of one person who each beneficially own 5% or more of the Registrant's voting securities. The following table lists as of April 24, 2014 persons and/or companies holding 5% or more beneficial interest in the Company’s outstanding common stock.

5% or Greater Shareholders as of April 24, 2014

Title of Class
Name of Owner
Amount and Nature of
Beneficial Ownership
Percent of Class
       
Common Robert L. Hodgkinson (1)                                    11,456,818                            7.01%

(1)

Of these shares, 8,000,000 are represented by common shares, 56,250 are represented by vested stock options and 681,818 are represented by currently exercisable share purchase warrants. 1,500,000 of these shares are owned by 7804 Yukon Inc., a private company owned by Robert Hodgkinson. A further 2,718,750 stock options have been granted but not yet vested.


All percentages based on 163,753,874 shares outstanding as of April 24, 2014.

Changes in ownership by major shareholders

To the best of the Company’s knowledge there have been no changes in the ownership of the Company’s shares other than disclosed herein.

Voting Rights

The Company’s major shareholders do not have different voting rights.

Shares Held in the United States

As of April 24, 2014, there were approximately 7,228 registered holders of the Company’s shares in the United States, with combined holdings of 118,494,052 common shares.

Change of Control

As of the date of this annual report, there were no arrangements known to the Company which may, at a subsequent date, result in a change of control of the Company.

Control by Others

To the best of the Company’s knowledge, the Company is not directly or indirectly owned or controlled by another corporation, any foreign government, or any other natural or legal person, severally or jointly.

B.             Related Party Transactions

During the years ended December 31, 2013 and 2012, the Company entered into the following transactions with related parties:

(a)

Compensation awarded to key management included a total of salaries and consulting fees of $1,173,000 (2012 - $1,194,000) and non-cash stock-based compensation of $302,000 (2012 - $412,000). Key management includes the Company’s officers and directors. The salaries and consulting fees are included in general and administrative expenses.

64



(b)

Included in interest and other income is $21,200 (2012 - $30,000) received from the companies controlled by officers of the Company for rental income.

   
(c)

In December 2009, a company controlled by the CEO of the Company (“HEC”) became a 5% working interest partner in the Woodrush property. Included in accounts payable and accrued liabilities at December 31, 2013 is $4,000 (December 31, 2012 - $20,000) owing to HEC.

   
(d)

In January 2012, directors and officers of the Company exercised 750,000 warrants with an exercise price of US$0.35 each that were issued in February 2011.

   
(e)

On December 31, 2012, Dejour USA entered into a financial contract with a U.S. oil and gas drilling fund (“Drilling Fund”) whereby the parties agreed to form an industry-standard drilling partnership for purposes of drilling three wells and completing four wells in the State of Colorado. A director of the Company provides investment advice for a fee to the Drilling Fund. The director abstained from voting when the Board of Directors approved the Company signing a financial contract with the Drilling Fund.

   
(f)

In December 2013, Dejour USA sold its working interests in certain non-core oil and gas leases in the area of Colorado to a related U.S. oil and gas corporation for gross proceeds of $477,000 (US$450,000). A director of the Company is the President of the U.S. oil and gas corporation. The sale price represented the higher of two competing offers to purchase the oil and gas leases in Colorado and the director of the Company abstained from voting to approve the Company’s sale of the leases.

C.              Interests of Experts and Counsel

Not Applicable.

65


ITEM 8. FINANCIAL INFORMATION.

A.              Consolidated Statements and Other Financial Information

Financial Statements

Description Page
   
Consolidated Financial Statements for the Years Ended December 31, 2013, 2012 and 2011 F-1 - F-41

Supplementary Oil and Gas Reserve Estimation and Disclosures (Unaudited) for the years ending December 31, 2013 and 2012

Legal Proceedings

The Directors and the management of the Company do not know of any material, active or pending, legal proceedings against them; nor is the Company involved as a plaintiff in any material proceeding or pending litigation.

The Directors and the management of the Company know of no active or pending proceedings against anyone that might materially adversely affect an interest of the Company.

Dividend Policy

The Company has not paid any dividends on its common shares. Any decision to pay dividends on common shares in the future will be made by the board of directors on the basis of the earnings, financial requirements and other conditions existing at such time.

B.              Significant Changes

None.

66


ITEM 9. THE OFFER AND LISTING

A.             Offering and Listing Details

The Company’s common shares are traded on the Toronto Stock Exchange and on the NYSE Amex, in both cases under the symbol “DEJ.” The following tables set forth for the periods indicated, the high and low closing prices in Canadian dollars of our common shares traded on the Toronto Stock Exchange and in United States dollars on the NYSE Amex. The Company traded on the Toronto Stock Exchange Venture Exchange in Vancouver, British Columbia, Canada, until November 20, 2008 when it began trading on the Toronto Stock Exchange. The Company changed its symbol to “DEJ” after a one for three share consolidation effective October 1, 2003. The Company changed its Toronto Stock Exchange trading symbol on May 23, 2007 to “DEJ” to coincide with its listing on the American Stock Exchange (now NYSE Amex) on the same day under the symbol “DEJ”.

The following table contains the annual high and low market prices for the five most recent fiscal years:

Toronto Stock Exchange (Cdn$)

  High Low
2013 $0.25 $0.10
2012 $0.59 $0.12
2011 $0.61 $0.24
2010 $0.48 $0.29
2009 $0.76 $0.23

NYSE Amex (US$)

  High Low
2013 $0.25 $0.09
2012 $0.57 $0.12
2011 $0.61 $0.21
2010 $0.50 $0.26
2009 $0.67 $0.12

The following table contains the high and low market prices for our common shares on the Toronto Stock Exchange and the NYSE Amex for each fiscal quarter for the two most recent fiscal years and any subsequent period:

Toronto Stock Exchange (Cdn$)

  High Low
2014    
Q1 $0.32 $0.13
2013    
Q4 $0.20 $0.10
Q3 $0.23 $0.18
Q2 $0.23 $0.16
Q1 $0.25 $0.17
2012    
Q4 $0.24 $0.16
Q3 $0.26 $0.12
Q2 $0.38 $0.23
Q1 $0.59 $0.35

NYSE Amex (US$)

High Low
2014    

67



Q1 $0.29 $0.11
2013    
Q4 $0.19 $0.09
Q3 $0.24 $0.18
Q2 $0.24 $0.17
Q1 $0.25 $0.16
2012    
Q4 $0.25 $0.16
Q3 $0.26 $0.12
Q2 $0.39 $0.21
Q1 $0.57 $0.34

The following table contains the high and low market prices for our common shares on the Toronto Stock Exchange and the NYSE Amex for each of the most recent six months:

Toronto Stock Exchange (Cdn$)

  High Low
March, 2014 $0.32 $0.15
February, 2014 $0.22 $0.15
January, 2014 $0.23 $0.13
December, 2013 $0.16 $0.10
November, 2013 $0.20 $0.11
October, 2013 $0.19 $0.16

NYSE Amex (US$)

  High Low
March, 2014 $0.29 $0.14
February, 2014 $0.21 $0.14
January, 2014 $0.21 $0.11
December, 2013 $0.16 $0.09
November, 2013 $0.19 $0.11
October, 2013 $0.19 $0.17

On April 24, 2014, the closing price of our common shares on the TSX was Cdn $0.26 per common share and on the NYSE was US $0.24 per common share.

B.             Plan of Distribution

Not Applicable.

C.              Markets

Our common shares, no par value, are traded on the TSX under the symbol “DEJ” and are traded on the NYSE Amex under the symbol "DEJ".

D.             Selling Shareholders

Not Applicable.

E.             Dilution

68


Not Applicable.

F.             Expenses of the Issue

Not Applicable.

ITEM 10. ADDITIONAL INFORMATION

A.             Share Capital

Not Applicable.

B.             Memorandum and Articles of Association

Dejour Energy Inc. (formerly Dejour Enterprises Ltd.) is incorporated under the laws of British Columbia, Canada. The Company was originally incorporated as “Dejour Mines Limited” on March 29, 1968 under the laws of the Province of Ontario. By articles of amendment dated October 30, 2001, the issued shares were consolidated on the basis of one (1) new for every fifteen (15) old shares and the name of the Company was changed to Dejour Enterprises Ltd. On June 6, 2003, the shareholders approved a resolution to complete a one-for-three-share consolidation, which became effective on October 1, 2003. In 2005, the Company was continued in British Columbia under the Business Corporations Act (British Columbia) (the “Act”). Effective March 9, 2011, the Company changed its name from Dejour Enterprises Ltd. to Dejour Energy Inc.

There are no restrictions on what business the Company may carry on in the Articles of Incorporation.

Under Article 17 of the Company’s Articles and under Part 5, Division 3 of the Act, a director must declare its interest in any existing or proposed contract or transaction with the Company and is not allowed to vote on any transaction or contract with the Company in which has a disclosable interest, unless all directors have a disclosable interest in that contract or transaction, in which case any or all of those directors may vote on such resolution. A director may hold any office or place of profit with the Company in conjunction with the office of director, and no director shall be disqualified by his office from contracting with the Company. A director or his firm may act in a professional capacity for the Company and he or his firm shall be entitled to remuneration for professional services. A director may become a director or other officer or employee of, or otherwise interested in, any corporation or firm in whom the Company may be interested as a shareholder or otherwise. The director shall not be accountable to the Company for any remuneration or other benefits received by him from such other corporation or firm subject to the provisions of the Act.

Article 16 of the Company’s Articles addresses the powers and duties of the directors. Directors must, subject to the Act, manage or supervise the management of the business and affairs of the Company and have the authority to exercise all such powers which are not required to be exercised by the shareholders as governed by the Act. Article 19 of the Company’s Articles addresses Committees of the Board of Directors. Directors may, by resolution, create and appoint an executive committee consisting of the director or directors that they deem appropriate. This executive committee has, during the intervals between meetings of the Board, all of the directors’ powers, except the power to fill vacancies in the Board, the power to remove a Director, the power to change the membership of, or fill vacancies in, any committee of the Board and any such other powers as may be set out in the resolution or any subsequent directors’ resolution. Directors may also by resolution appoint one or more committees other than the executive committee.

These committees may be delegated any of the directors’ powers except the power to fill vacancies on the board of directors, the power to remove a director, the power to change the membership or fill vacancies on any committee of the directors, and the power to appoint or remove officers appointed by the directors. Article 18 of the Company’s Articles details the proceedings of directors. A director may, and the Secretary or Assistant Secretary, if any, on the request of a director must call a meeting of the directors at any time. The quorum necessary for the transaction of the business of the directors may be fixed by the directors and if not so fixed shall be deemed to a majority of the directors. If the number of directors is set at one, it quorum is deemed to be one director.

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Article 8 of the Company’s Articles details the borrowing powers of the directors. They may, on behalf of the Company:

  • Borrow money in a manner and amount, on any security, from any source and upon any terms and conditions as they deem appropriate;

  • Issue bonds, debentures, and other debt obligations either outright or as security for any liability or obligation of the Company or any other person at such discounts or premiums and on such other terms as they consider appropriate;

  • Guarantee the repayment of money by any other person or the performance of any obligation of any other person; and

  • Mortgage, charge, or grant a security in or give other security on, the whole or any part of the present or future assets and undertaking of the Company.

A director need not be a shareholder of the Company, and there are no age limit requirements pertaining to the retirement or non-retirement of directors. The directors are entitled to the remuneration for acting as directors, if any, as the directors may from time to time determine. If the directors so decide, the remuneration of directors, if any, will be determined by the shareholders. The remuneration may be in addition to any salary or other remuneration paid to any officer or employee of the Company as such who is also a director. The Company must reimburse each director for the reasonable expenses that he or she may incur in and about the business of the Company. If any director performs any professional or other services for the Company that in the opinion of the directors are outside the ordinary duties of a director, or if any director is otherwise specially occupied in or about the Company’s business, he or she may be paid remuneration fixed by the directors, or, at the option of that director, fixed by ordinary resolution and such remuneration may be either in addition to, or in substitution for, any other remuneration that he or she may be entitled to receive. Unless other determined by ordinary resolution, the directors on behalf of the Company may pay a gratuity or pension or allowance on retirement to any director who has held any salaried office or place of profit with the Company or to his or her spouse or dependents and may make contributions to any fund and pay premiums for the purchase or provision of any such gratuity, pension or allowance.

Article 21 of the Company’s Articles provides for the mandatory indemnification of directors, former directors, and alternate directors, as well as his or hers heirs and legal personal representatives, or any other person, to the greatest extent permitted by the Act. The indemnification includes the mandatory payment of expenses actually and reasonably incurred by such person in respect of that proceeding. The failure of a director, alternate director, or officer of the Company to comply with the Act or the Company’s Articles does not invalidate any indemnity to which he or she is entitled. The directors may cause the Company to purchase and maintain insurance for the benefit of eligible parties who:

(a)

is or was a director, alternate director, officer, employee or agent of the Company;

   
(b)

is or was a director, alternate director, officer employee or agent of a corporation at a time when the corporation is or was an affiliate of the Company;

   
(c)

at the request of the Company, is or was a director, alternate director, officer, employee or agent of a corporation or of a partnership, trust, joint venture or other unincorporated entity;

   
(d)

at the request of the Company, holds or held a position equivalent to that of a director, alternate director or officer of a partnership, trust, joint venture or other unincorporated entity;

against any liability incurred by him or her as such director, alternate director, officer, employee or agent or person who holds or held such equivalent position

Under Article 9 of the Company’s Articles and subject to the Act, the Company may alter its authorized share structure by directors’ resolution or ordinary resolution, in each case determined by the directors, to:

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(a)

create one or more classes or series of shares or, if none of the shares of a series of a class or series of shares are allotted or issued, eliminate that class or series of shares;

   
(b)

increase, reduce or eliminate the maximum number of shares that the Company is authorized to issue out of any class or series of shares or establish a maximum number of shares that the company is authorized to issue out of any class or series of shares for which no maximum is established;

   
(c)

subdivide or consolidate all or any of its unissued, or fully paid issued, shares;

   
(d)

if the Company is authorized to issue shares of a class or shares with par value;


  (i)

decrease the par value of those shares; or

     
  (ii)

if none of the shares of that class of shares are allotted or issued, increase the par value of those shares;


(e)

change all or any of its unissued, or fully paid issued, shares with par value into shares without par value or any of its unissued shares without par value into shares with par value;

   
(f)

alter the identifying name of any of its shares; or

by ordinary resolution otherwise alter its share or authorized share structure.

Subject to Section9.2 of the Company’s Articles and the Act, the Company may:

(1)

by directors’ resolution or ordinary resolution, in each case determined by the directors, create special rights or restrictions for, and attach those special rights or restrictions to, the shares of any class or series of shares, if none of those shares have been issued, or vary or delete any special rights or restrictions attached to the shares of any class or series of shares, if none of those shares have been issued; and

   
(2)

by special resolution of the shareholders of the class or series affected, do any of the acts in Section 9.1 of the Company’s Articles if any of the shares of the class or series of shares has been issued.

The Company may by resolution of its directors or by ordinary resolution, in each case as determined by the directors, authorize an alteration of its Notice of Articles in order to change its name.

The directors may, whenever they think fit, call a meeting of shareholders. An annual general meeting shall be held once every calendar year at such time (not being more than 15 months after holding the last preceding annual meeting) and place as may be determined by the Directors.

There are no limitations upon the rights to own securities.

There is no special ownership threshold above which an ownership position must be disclosed. However, any ownership level above 10% must be disclosed to the TSX and all applicable Canadian Securities Commission.

Description of Share Capital

The Company is authorized to issue an unlimited number of common shares, preferred shares and series 1 preferred shares of which, as of April 24, 2014, 163,753,874 common shares, are issued and outstanding. The rights, preferences and restrictions attaching to each class of the Company’s shares are as follows:

Common Shares

All the common shares of the Company are of the same class and, once issued, rank equally as to dividends, voting powers, and participation in assets. All common shareholders are entitled to receive notice of, attend and be heard at any meeting of shareholders of the Company, excepting a meeting of the holders of shares of another class, as such, and excepting a meeting of the holders of a particular series, as such. Holders of shares of common stock are entitled to one vote for each share held of record on all matters to be acted upon by the shareholders, including the election of directors. Except as otherwise required by law the holders of the Company’s common shares will possess all voting power. Generally, all matters to be voted on by shareholders must be approved by a majority (or, in the case of election of directors, by a plurality) of the votes entitled to be cast by all common shares that are present in person or represented by proxy. Subject to the special rights and restrictions attached to the shares of any class or series of classes, one holder of common shares issued, outstanding and entitled to vote, represented in person or by proxy, is necessary to constitute a quorum at any meeting of our shareholders.

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Upon liquidation, dissolution or winding up of the Company, whether voluntary or involuntary, or other disposition of the property or assets of the Company, holders of shares of common stock are entitled to receive pro rata the assets of Company, if any, remaining after payments of all debts and liabilities to the holders of preferred shares or any other shares ranking senior to shares of common stock. No shares have been issued subject to call or assessment. There are no preemptive or conversion rights and no provisions for redemption or purchase for cancellation, surrender, or sinking or purchase funds.

The holders of the Company’s common shares will be entitled to such cash dividends as may be declared from time to time by our Board of Directors but such dividend will rank junior to the holders of preferred shares and series 1 preferred shares.

In the event of any merger or consolidation with or into another company in connection with which the Company’s common shares are converted into or exchangeable for shares, other securities or property (including cash), all holders of the Company’s common shares will be entitled to receive the same kind and amount of shares and other securities and property (including cash).

There are no indentures or agreements limiting the payment of dividends on the Company’s common shares and there are no special liquidation rights or subscription rights attaching to the Company’s common shares.

Preferred Shares

Preferred shares may, at any time and from time to time, be issued in one or more series and the Company may, by directors’ resolution or ordinary resolution, do one or more of the following:

  • determine the maximum number of shares of any of those series of preferred shares that the Company is authorized to issue, determine that there is no maximum number or alter any determination made or otherwise, in relation to a maximum number of those shares, and authorize the alteration of the Notice of Articles accordingly;

  • alter the Articles of the Company, and authorize the alteration of the Notice of Articles, to create an identifying name by which the shares of any of those series of preferred shares may be identified or to alter any identifying name created for those shares; and

  • alter the Articles of the Company, and authorize the alteration of the Notice of Articles, to attach special rights or restrictions to the shares of any of those series of preferred shares or to alter any special rights or restrictions attached to those shares, subject to the special rights and restrictions attached to the preferred shares.

If the alterations, determinations or authorizations contemplated above are to be made in relation to a series of shares of which there are issued shares, those alterations, determinations or authorizations may be made by ordinary resolution. However, no special rights or restrictions attached to a series of preferred shares shall confer on the series of preferred shares priority over another series of preferred shares respecting (i) dividends or (ii) return of capital on the dissolution of the Company or on the occurrence of any event that entitles the shareholders holding the shares of all series of preferred shares to a return of capital.

All holders of preferred shares shall not be entitled to receive notice of, attend and be heard at any meeting of or vote at any meeting of shareholders of the Company, except any specific meeting of the holders of preferred shares.

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The holders of the Company’s preferred shares will be entitled to such cash dividends as may be declared from time to time by our Board of Directors and shall rank senior to the holders of our common shares and any other shares of the Company ranking junior to the preferred shares.

Upon liquidation, dissolution or winding up of the Company, whether voluntary or involuntary, or other disposition of the property or assets of the Company, holders of the holders of the Preferred Shares, including the Series 1 Preferred Shares, shall be entitled to receive, for each preferred share held, from the property and assets of the Company, a sum equivalent to the amount paid up thereon together with the premium (if any) thereon and any dividends declared thereon before any amount shall be paid or any property or asset of the Company is distributed to the holders of the common shares or any other shares ranking junior to the preferred shares with respect to repayment of capital. After payment to the holders of the preferred shares of the amount so payable to them, the holders of the preferred shares shall not be entitled to share in any further distribution of the property or assets of the Company except as specifically provided in special rights and restrictions attached to any particular series of preferred shares

Series 1 Preferred Shares

The Company may, at any time and from time to time, issue series 1 preferred shares. The Company may, by directors’ resolution or ordinary resolution passed before the issue of any series 1 preferred shares, in each case as determined by the directors or, if there are issued series 1 preferred shares, by ordinary resolution, do one or more of the following:

  • determine the maximum number of the series 1 preferred shares that the Company is authorized to issue, determine that there is no maximum number or alter any determination made in relation to a maximum number of those shares, and authorize the alteration of the Notice of Articles accordingly;

  • alter the Articles of the Company, and authorize the alteration of the Notice of Articles, to alter the name of the series 1 preferred shares; and

  • alter the Articles of the Company, and authorize the alteration of the Notice of Articles, to attach special rights or restrictions to the series 1 preferred shares or to alter any special rights or restrictions attached to those shares, subject to the special rights and restrictions attached to the preferred shares.

The special rights and restrictions that may be attached to the series 1 preferred shares may include, without in any way limiting or restricting the generality of such paragraph, rights and restrictions respecting the following:

  • the rate or amount of dividends, whether cumulative, non-cumulative or partially cumulative and the dates, places and currencies of payment thereof;

  • the consideration for, and the terms and conditions of, any purchase for cancellation or redemption thereof, including redemption after a fixed term or at a premium, conversion or exchange rights;

  • the terms and conditions of any share purchase plan or sinking fund;

  • the restrictions respecting the payment of dividends on, or the repayment of capital in respect of, any other shares of the Company;

  • voting rights; and

  • the issuance of any shares of any other class or series of shares of the Company or any evidences of indebtedness or any other securities convertible into or exchangeable for such shares

No special rights or restrictions attached to the series 1 preferred shares confers on the series 1 preferred shares priority over another series of preferred shares respecting (i) dividends or (ii) return of capital on the dissolution of the Company or on the occurrence of any event that entitles the shareholders holding the shares of all series of preferred shares to a return of capital.

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All holders of series 1 preferred shares are not entitled to receive notice of, attend and be heard at any meeting of or vote at any meeting of shareholders of the Company, except any specific meeting of the holders of series 1 preferred shares.

The holders of the Company’s series 1 preferred shares will be entitled to such cash dividends as may be declared from time to time by the Company’s Board of Directors and will rank senior to the holders of the Company’s common shares and any other shares of the Company ranking junior to the preferred shares.

Dividend Record

The Company has not paid any dividends on its common shares and has no policy with respect to the payment of dividends.

Ownership of Securities and Change of Control

There are no limitations on the rights to own securities, including the rights of non-resident or foreign shareholders to hold or exercise voting rights on the securities imposed by foreign law or by the constituent documents of the Company.

Any person who beneficially owns, directly or indirectly, or exercises control or direction over more than 10% of the Company’s voting shares is considered an insider, and must file an insider report with the Canadian regulatory commissions within ten days of becoming an insider, disclosing any direct or indirect beneficial ownership of, or control or direction over securities of the Company. In addition, if the Company itself holds any of its own securities, the Company must disclose such ownership.

There are no provisions in the Company’s Articles or Notice of Articles that would have an effect of delaying, deferring or preventing a change in control of the Company operating only with respect to a merger, acquisition or corporate restructuring involving the Company or its subsidiaries.

Differences from Requirements in the United States

Except for the Company’s quorum requirements, certain requirements related to related party transactions and the requirement for notice of shareholder meetings, discussed above, there are no significant differences in the law applicable to the Company, in the areas outlined above, in Canada versus the United States. In most states in the United States, a quorum must consist of a majority of the shares entitled to vote. Some states allow for a reduction of the quorum requirements to less than a majority of the shares entitled to vote. Having a lower quorum threshold may allow a minority of the shareholders to make decisions about the Company, its management and operations. In addition, most states in the United States require that a notice of meeting be mailed to shareholders prior to the meeting date. Additionally, in the United States, a director may not be able to vote on the approval of any transaction in which the director has an interest.

C.              Material Contracts

The following are material contracts to which the Company is a party:

Financial Contract with a U.S. Oil and Gas Drilling Fund

On December 31, 2012, Dejour USA entered into a financial contract with a U.S. oil and gas drilling fund (“Drilling Fund”), that is associated through a relationship with a former director of the Company, to drill up to three wells and complete up to four wells (“the Tranche 1 Wells”) in the State of Colorado. By agreement:

(a)

Dejour USA contributed four natural gas well spacing units, including one drilled and cased well with a cost of US$1.1 million;

(b)

The Drilling Fund contributed US$6.5 million cash directly to a drilling company, that is owned by a former consultant of Dejour USA, as prepaid drilling costs. During the year ended December 31, 2013, the Drilling Fund also committed to invest a further US$500,000 in the four wells for a total of US$7.0 million. As at December 31, 2013, US$417,000 of the incremental US$500,000 has been invested for a total of US$6.9 million;

(c)

Dejour USA will earn a “before payout” working interest of 10% to 14% and an “after payout” working interest of 28% to 39% in the net operating profits from the Tranche 1 Wells based on the “actual cash” invested in the drilling program. In September 2013, Dejour USA signed an amendment with the Drilling Fund and agreed to earn the revised “before payout” working interest of 15.88% to 22.23% and revised “after payout” working interest of 29.77% to 41.67% in the net operating profits from the Tranche 1 Wells based on the actual cash invested in the drilling program;

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(d)

The Drilling Fund has the right to require that Dejour USA purchase the Drilling Fund’s entire working interest in the Tranche 1 Wells 36 months after the commencement of production from the initial Tranche 1 Well. In the event the Drilling Fund exercises its right, the purchase price to be paid by Dejour USA will equal 75% of the Drilling Fund’s actual investment less 75% of the Drilling Fund’s share of working interest net profits from the Tranche 1 Wells, if any, for the 36-month period, plus a “top-up” amount so that the Drilling Fund earns a minimum 8% return, compounded annually and applied on a monthly basis, on 75% of its original investment over the 36-month period; and

(e)

The Drilling Fund has the right to require Dejour USA to purchase all of the Drilling Fund’s interest in the Tranche 1 Wells if at any time Dejour USA plans to divest itself of greater than 51% of its Working Interest in the Tranche 1 Wells and resigns as Operator (a “Change of Control Event”). The purchase price is equal to the future net profit from the “Proven and Probable Reserves” attributable to the Drilling Funds working interest in the Tranche 1 Wells, discounted at 12%, as determined by a third party evaluator acceptable to both parties.

Dejour USA considers the transaction to be a financial contract liability as the risks and rewards of ownership have not been substantially transferred at the Agreement date. On the Drilling Fund financing advance, the Company increased property and equipment and financial contract liability by $6.5 million (US$6.5 million). During the year ended December 31, 2013, the Company increased property and equipment and financial contract liability by $443,000 (US$417,000) of the incremental US$500,000 advance received in the year. On initial recognition, the Company imputed its borrowing cost of 8.4% based on the estimated timing and amount of operating profit using the independent reserve engineer’s estimated future cash flows for the Drilling Funds working interest in the Tranche 1 Wells. Subsequent to initial measurement the financial contract liability will be increased by the imputed interest expense and decreased by the Drilling Fund’s net operating profit from the Tranche 1 Wells. Any changes in the estimated timing and amount of the net operating profit cash flows will be discounted at the initial imputed interest rate with any change in the recognized liability recognized as a gain (loss) in the period of change. The Company has estimated the current portion of the obligation based on the expected net operating profit to be paid to the Drilling Fund in the next twelve months.

Bank Line of Credit

On March 28, 2013, DEAL signed a new “Commitment Letter” with the Bank to renew its $5.95 million (December 31, 2012 - $6.0 million) revolving operating demand loan under the following terms and conditions:

(a)

“Credit Facility “A” – Revolving Operating Demand Loan - $3.7 million to be used for general corporate purposes, ongoing operations, capital expenditures, and acquisition of additional petroleum and natural gas assets. Interest on Credit Facility “A” is at Prime + 1% payable monthly and all amounts outstanding are payable on demand any time, and

(b)

Credit Facility “B” – Non-Revolving Demand Loan - $2.25 million. Interest on Credit Facility “B” is at Prime + 3 1/2% payable monthly. Monthly principal payments of $200,000 are due and payable commencing March 26, 2013 with all amounts outstanding under Credit Facility “B” ($1,450,000) due and payable in full on June 30, 2013.

Collateral for Credit Facilities “A” and “B” (the “Credit Facilities”) is provided by a $10.0 million first floating charge over all the assets of DEAL, a general assignment of DEAL’s book debts, a $10.0 million debenture with a first floating charge over all the assets of the Company and an unlimited guarantee provided by Dejour USA. On June 5, 2013, DEAL renewed the Credit Facilities with the Bank and the maximum amount of “Credit Facility A” was reduced to $3.5 million. On June 19, 2013, “Credit Facility B” was repaid in full. Further, on December 16, 2013 and amended on February 18, 2014, DEAL renewed the Credit Facility “A” with the Bank and contracted to utilize $600,000 of the $3.5 million to fund the proposed acquisition of certain producing natural gas properties in Canada until March 31, 2014. The acquisition closed on March 26, 2014. Effective March 1, 2014, Credit Facility “A” reduces by $100,000 per month. The next annual review is scheduled on or before May 1, 2014.

Under the terms of the Credit Facilities, DEAL is required to maintain a working capital ratio of greater than 1:1 at all times. The working capital ratio is defined as the ratio of (i) current assets (including any undrawn and authorized availability under the Credit Facilities) less unrealized hedging gains to (ii) current liabilities (excluding the current portion of outstanding balances of the facility) less unrealized hedging losses. As at December 31, 2013, DEAL was in compliance with its working capital ratio requirement.

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Loan Facility

On June 19, 2013, the Company borrowed $3.5 million (“Loan Facility”) from a Canadian institutional lender (“Lender”). The Loan Facility bears interest at 14%, payable monthly, and matures on December 14, 2014. The principal is repayable any time after December 18, 2013 without penalty. Certain incentive share purchase warrants (“Warrant” or “Warrants”) issued to the Lender. Security for the Loan Facility is comprised of a First Deed of Trust on certain of the Company’s U.S. oil and gas interests, including a general security agreement, a second mortgage on the Company’s Canadian properties, and the guaranty of the Company and Dejour USA.

As partial consideration for providing the Loan Facility, the Company issued the Lender 7,291,667 Warrants. Each Warrant entitles the holder to acquire one common share at a price of $0.24 per share any time prior to June 18, 2015. If the Company issues any common shares at a price per share less than $0.24 (the “Issue Price”) any time until December 18, 2013, then the exercise price of the Warrants would automatically be reduced to the higher of (i) the Issue Price and (ii) $0.20. Shares acquired through the exercise of Warrants prior to October 18, 2013 are restricted from sale through the facilities of the Canadian stock exchange.

Other terms and conditions of the Loan Facility are:

(a)

Commencing September 30, 2013, Dejour USA is required to maintain a working capital ratio of greater than 1:1, as defined, at all times. The working capital ratio is defined as the ratio of (i) current assets to (ii) current liabilities (excluding any liability pursuant to the Drilling Fund);

(b)

Restrictions on borrowings; and

(c)

No changes to the Company’s senior management team without the Lender’s written consent.

At December 31, 2013, Dejour USA was in default of its working capital ratio covenant. As a result, the loan facility is due upon demand and classified as current liabilities. The Lender has not demanded repayment as at December 31, 2013.

D. Exchange Controls

There are no governmental laws, decrees, or regulations in Canada relating to restrictions on the export or import of capital, or affecting the remittance of interest, dividends, or other payments to non-resident holders of the Company’s common stock. Any remittances of dividends to United States residents are, however, subject to a 15% withholding tax (10% if the shareholder is a corporation owning at least 10% of the outstanding Common Stock of the Company) pursuant to Article X of the reciprocal tax treaty between Canada and the United States.

Except as provided in the Investment Canada Act (the “ICA”), there are no limitations specific to the rights of non-Canadians to hold or vote the common shares of the Company under the laws of Canada or the Province of British Columbia or in the charter documents of the Company.

Management of the Company considers that the following general summary is materially complete and fairly describes those provisions of the ICA pertinent to an investment by an American investor in the Company.

The ICA requires a non-Canadian making an investment which would result in the acquisition of control of a Canadian business, the gross value of the assets of which exceed certain threshold levels or the business activity of which is related to Canada’s cultural heritage or national identity, to either notify, or file an application for review with, Investment Canada, the federal agency created by the ICA.

The notification procedure involves a brief statement of information about the investment of a prescribed form which is required to be filed with Investment Canada by the investor at any time up to 30 days following implementation of the investment. It is intended that investments requiring only notification will proceed without government intervention unless the investment is in a specific type of business activity related to Canada’s cultural heritage and national identity.

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If an investment is reviewable under the ICA, an application for review in the form prescribed is normally required to be filed with Investment Canada prior to the investment taking place and the investment may not be implemented until the review has been completed and the Minister responsible for Investment Canada is satisfied that the investment is likely to be of net benefit to Canada. If the Minister is not satisfied that the investment is likely to be of net benefit to Canada, the non-Canadian must not implement the investment or, if the investment has been implemented, may be required to divest himself of control of the business that is the subject of the investment.

The following investments by non-Canadians are subject to notification under the ICA:

(a)

an investment to establish a new Canadian business; and

   
(b)

an investment to acquire control of a Canadian business that is not reviewable pursuant to the ICA.

An investment is reviewable under the ICA if there is an acquisition by a non-Canadian of a Canadian business and the asset value of the Canadian business being acquired equals or exceeds the following thresholds:

(a)

for non-WTO Investors, the threshold is $5,000,000 for a direct acquisition and over $50,000,000 for an indirect acquisition. The $5,000,000 threshold will apply however for an indirect acquisition if the asset value of the Canadian business being acquired exceeds 50% of the asset value of the global transaction;

   
(b)

except as specified in paragraph (c) below, a threshold is calculated annually for reviewable direct acquisitions by or from WTO Investors. The threshold for 2012 is $330,000,000. Pursuant to Canada’s international commitments, indirect acquisitions by or from WTO Investors are not reviewable; and

   
(c)

the limits set out in paragraph (a) apply to all investors for acquisitions of a Canadian business that is a cultural business.:

WTO Investor as defined in the ICA means:

(a)

an individual, other than a Canadian, who is a national of a WTO Member or who has the right of permanent residence in relation to that WTO Member;

   
(b)

a government of a WTO Member, whether federal, state or local, or an agency thereof;

   

an entity that is not a Canadian-controlled entity, and that is a WTO investor-controlled entity, as determined in accordance with the ICA;

   
(c)

a corporation or limited partnership:


  (i)

that is not a Canadian-controlled entity, as determined pursuant to the ICA;

  (ii)

that is not a WTO investor within the meaning of the ICA;

  (iii)

of which less than a majority of its voting interests are owned by WTO investors;

  (iv)

that is not controlled in fact through the ownership of its voting interests; and

  (v)

of which two thirds of the members of its board of directors, or of which two thirds of its general partners, as the case may be, are any combination of Canadians and WTO investors;


(d)

a trust:


  (i)

that is not a Canadian-controlled entity, as determined pursuant to the ICA;

  (ii)

that is not a WTO investor within the meaning of the ICA;

  (iii)

that is not controlled in fact through the ownership of its voting interests, and

  (iv)

of which two thirds of its trustees are any combination of Canadians and WTO investors, or


(e)

any other form of business organization specified by the regulations that is controlled by a WTO investor.

WTO Member as defined in the ICA means a member of the World Trade Organization.

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Generally, an acquisition is direct if it involves the acquisition of control of the Canadian business or of its Canadian parent or grandparent and an acquisition is indirect if it involves the acquisition of control of a non-Canadian parent or grandparent of an entity carrying on the Canadian business. Control may be acquired through the acquisition of actual or de jure voting control of a Canadian corporation or through the acquisition of substantially all of the assets of the Canadian business. No change of voting control will be deemed to have occurred if less than one-third of the voting control of a Canadian corporation is acquired by an investor.

The ICA specifically exempts certain transactions from either notification or review. Included among the category of transactions is the acquisition of voting shares or other voting interests by any person in the ordinary course of that person’s business as a trader or dealer in securities.

E.             Taxation

CANADIAN FEDERAL INCOME TAX CONSIDERATIONS

The following summary describes the principal Canadian federal income tax considerations generally applicable to a holder who is the beneficial holder of common shares of the Company and who, at all relevant times, for the purposes of the application of the Income Tax Act (Canada) and the Income Tax Regulations (collectively, the “ Canada Tax Act ”) (i) deals at arm’s length with the Company, (ii) is not affiliated with the Company, (iii) holds the common shares as capital property, and (iv) who, for the purposes of the Canada Tax Act and the Canada – United States Income Tax Convention (the “ Treaty ”), is at all relevant times resident in and only in the United States, is a qualifying person entitled to all of the benefits of the Treaty, and (v) does not use or hold and is not deemed to use or hold the shares in carrying on a business in Canada (a “ U.S. Holder ”). Special rules, which are not discussed below, may apply to a U.S. Holder that is an insurer or authorized foreign bank that carries on business in Canada and elsewhere.

This summary is based on the current provisions of the Canada Tax Act and the current published administrative policies and assessing practices of the Canada Revenue Agency (“ CRA ”) published in writing prior to the date hereof. This summary also takes into account all specific proposals to amend the Canada Tax Act and Regulations publicly announced by the Minister of Finance (Canada) prior to the date hereof (collectively, the “ Tax Proposals ”) and assumes all Tax Proposals will be enacted in the form proposed. There is no certainty that the Tax Proposals will be enacted in the form proposed, if at all. This summary does not otherwise take into account or anticipate any changes in laws or administrative policy or assessing practice whether by judicial, regulatory, administrative or legislative decision or action nor does it take into account provincial, territorial or foreign income tax legislation or considerations.

This summary is of a general nature only and is not, and is not intended to be, nor should it be construed to be, legal or tax advice to any particular purchaser of Units. This summary is not exhaustive of all Canadian federal income tax considerations. Accordingly, purchasers should consult their own tax advisors regarding the income tax consequences of purchasing Units based on their particular circumstances.

Dividends

Dividends paid or credited or deemed to be paid or credited to a U.S. Holder by the Company will be subject to Canadian withholding tax at the rate of 25% under the Canada Tax Act, subject to any reduction in the rate of withholding to which the U.S. Holder is entitled under the Treaty. For example, if the U.S. Holder is entitled to benefits under the Treaty and is the beneficial owner of the dividends, the applicable rate of Canadian withholding tax is generally reduced to 15%. The rate of Canadian withholding tax for such U.S. Holder will generally be further reduced under the Treaty to 5% if such holder is a corporation that beneficially owns at least 10% of the voting shares of the Company, and may be further reduced to nil if such holder is a qualifying pension fund or charity.

Dispositions

A U.S. Holder will not be subject to tax under the Canada Tax Act on any capital gain realized on a disposition of a common share (including a deemed disposition on death), unless the common share is or is deemed to be “taxable Canadian property” to the U.S. Holder for the purposes of the Canada Tax Act and the U.S. Holder is not entitled to relief under the Treaty.

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Generally, provided the Shares are listed on a “designated stock exchange” as defined in the Canada Tax Act (which includes the TSX) at the time of disposition, the Shares will not constitute taxable Canadian property of a U.S. Holder, unless at any time during the 60-month period immediately preceding the disposition, the U.S. Holder, persons with whom the U.S. Holder did not deal at arm’s length, or the U.S. Holder together with all such persons, owned 25% or more of the issued shares of any class of shares of the Company and more than 50% of the fair market value of those shares was derived directly or indirectly from any one or combination of (i) real or immovable property situated in Canada,(ii) Canadian resource properties, (iii) timber resource properties, and (iv) options in respect of, or interests in, or for civil rights law rights in, property described in any of (i) to (iii), whether or not that property exists.

U.S. Holders whose common shares may constitute taxable Canadian property should consult with their own tax advisors.

CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The following is a general summary of certain material U.S. federal income tax considerations applicable to a U.S. Holder (as defined below) arising from and relating to the acquisition, ownership, and disposition of common shares of the Company.

This summary is for general information purposes only and does not purport to be a complete analysis or listing of all potential U.S. federal income tax considerations that may apply to a U.S. Holder arising from and relating to the acquisition, ownership, and disposition of common shares. In addition, this summary does not take into account the individual facts and circumstances of any particular U.S. Holder that may affect the U.S. federal income tax consequences to such U.S. Holder, including specific tax consequences to a U.S. Holder under an applicable tax treaty. Accordingly, this summary is not intended to be, and should not be construed as, legal or U.S. federal income tax advice with respect to any U.S. Holder. Each U.S. Holder should consult its own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences relating to the acquisition, ownership and disposition of common shares.

No legal opinion from U.S. legal counsel or ruling from the Internal Revenue Service (the “IRS”) has been requested, or will be obtained, regarding the U.S. federal income tax consequences of the acquisition, ownership, and disposition of common shares. This summary is not binding on the IRS, and the IRS is not precluded from taking a position that is different from, and contrary to, the positions taken in this summary. In addition, because the authorities on which this summary is based are subject to various interpretations, the IRS and the U.S. courts could disagree with one or more of the positions taken in this summary.

Scope of this Summary

Authorities

This summary is based on the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations (whether final, temporary, or proposed), published rulings of the IRS, published administrative positions of the IRS, U.S. court decisions, the Convention Between Canada and the United States of America with Respect to Taxes on Income and on Capital, signed September 26, 1980, as amended (the “Treaty”), and U.S. court decisions that are applicable and, in each case, as in effect and available, as of the date of this document. Any of the authorities on which this summary is based could be changed in a material and adverse manner at any time, and any such change could be applied on a retroactive or prospective basis which could affect the U.S. federal income tax considerations described in this summary. This summary does not discuss the potential effects, whether adverse or beneficial, of any proposed legislation that, if enacted, could be applied on a retroactive or prospective basis.

U.S. Holders

For purposes of this summary, the term "U.S. Holder" means a beneficial owner of common shares that is for U.S. federal income tax purposes:

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  • an individual who is a citizen or resident of the U.S.;

  • a corporation (or other entity taxable as a corporation for U.S. federal income tax purposes) organized under the laws of the U.S., any state thereof or the District of Columbia;

  • an estate whose income is subject to U.S. federal income taxation regardless of its source; or

  • a trust that (a) is subject to the primary supervision of a court within the U.S. and the control of one or more U.S. persons for all substantial decisions or (b) has a valid election in effect under applicable Treasury regulations to be treated as a U.S. person.

Non-U.S. Holders

For purposes of this summary, a “non-U.S. Holder” is a beneficial owner of common shares that is not a U.S. Holder. This summary does not address the U.S. federal income tax consequences to non-U.S. Holders arising from and relating to the acquisition, ownership, and disposition of common shares. Accordingly, a non-U.S. Holder should consult its own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences (including the potential application of and operation of any income tax treaties) relating to the acquisition, ownership, and disposition of common shares.

U.S. Holders Subject to Special U.S. Federal Income Tax Rules Not Addressed

This summary does not address the U.S. federal income tax considerations applicable to U.S. Holders that are subject to special provisions under the Code, including the following U.S. Holders: (a) U.S. Holders that are tax-exempt organizations, qualified retirement plans, individual retirement accounts, or other tax-deferred accounts; (b) U.S. Holders that are financial institutions, underwriters, insurance companies, real estate investment trusts, or regulated investment companies; (c) U.S. Holders that are dealers in securities or currencies or U.S. Holders that are traders in securities that elect to apply a mark-to-market accounting method; (d) U.S. Holders that have a “functional currency” other than the U.S. dollar; (e) U.S. Holders that own common shares as part of a straddle, hedging transaction, conversion transaction, constructive sale, or other arrangement involving more than one position; (f) U.S. Holders that acquired common shares in connection with the exercise of employee stock options or otherwise as compensation for services; (g) U.S. Holders that hold common shares other than as a capital asset within the meaning of Section 1221 of the Code (generally, property held for investment purposes); (h) partnerships and other pass-through entities (and investors in such partnerships and entities); or (i) U.S. Holders that own or have owned (directly, indirectly, or by attribution) 10% or more of the total combined voting power of the outstanding shares of the Company. This summary also does not address the U.S. federal income tax considerations applicable to U.S. Holders who are: (a) U.S. expatriates or former long-term residents of the U.S. subject to Section 877 of the Code; (b) persons that have been, are, or will be a resident or deemed to be a resident in Canada for purposes of the Act; (c) persons that use or hold, will use or hold, or that are or will be deemed to use or hold common shares in connection with carrying on a business in Canada; (d) persons whose common shares constitute “taxable Canadian property” under the Act; or (e) persons that have a permanent establishment in Canada for the purposes of the Treaty. U.S. Holders that are subject to special provisions under the Code, including U.S. Holders described immediately above, should consult their own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences relating to the acquisition, ownership and disposition of common shares.

If an entity that is classified as a partnership (or pass-through entity) for U.S. federal income tax purposes holds common shares, the U.S. federal income tax consequences to such partnership and the partners of such partnership generally will depend on the activities of the partnership and the status of such partners. Partners of entities that are classified as partnerships for U.S. federal income tax purposes should consult their own tax advisor regarding the U.S. federal income tax consequences arising from and relating to the acquisition, ownership, and disposition of common shares.

Tax Consequences Not Addressed

This summary does not address the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences to U.S. Holders of the acquisition, ownership, and disposition of common shares. Each U.S. Holder should consult its own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local, and foreign tax consequences of the acquisition, ownership, and disposition of common shares.

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U.S. Federal Income Tax Consequences of the Acquisition, Ownership, and Disposition of Common Shares

If the Company is not considered a “passive foreign investment company” (a “PFIC”, as defined below) at any time during a U.S. Holder’s holding period, the following sections will generally describe the U.S. federal income tax consequences to U.S. Holders of the acquisition, ownership, and disposition of the Company’s common shares.

Distributions on Common Shares

A U.S. Holder that receives a distribution, including a constructive distribution, with respect to a common share will be required to include the amount of such distribution in gross income as a dividend (without reduction for any Canadian income tax withheld from such distribution) to the extent of the current or accumulated “earnings and profits” of the Company, as computed for U.S. federal income tax purposes. A dividend generally will be taxed to a U.S. Holder at ordinary income tax rates. To the extent that a distribution exceeds the current and accumulated “earnings and profits” of the Company, such distribution will be treated first as a tax-free return of capital to the extent of a U.S. Holder’s tax basis in the common shares and thereafter as gain from the sale or exchange of such common shares (see “Sale or Other Taxable Disposition of Common Shares” below). However, the Company does not intend to maintain the calculations of earnings and profits in accordance with U.S. federal income tax principles, and each U.S. Holder should therefore assume that any distribution by the Company with respect to the common shares will constitute ordinary dividend income. Dividends received on common shares generally will not be eligible for the “dividends received deduction.”

Dividends paid by the Company generally will be taxed at the preferential tax rates applicable to long-term capital gains if (a) the Company is a “qualified foreign corporation” (as defined below), (b) the U.S. Holder receiving such dividend is an individual, estate, or trust, and (c) certain holding period requirements are met. The Company generally will be a “qualified foreign corporation” under Section 1(h)(11) of the Code (a “QFC”) if (a) the Company is eligible for the benefits of the Treaty, or (b) common shares of the Company are readily tradable on an established securities market in the U.S. However, even if the Company satisfies one or more of such requirements, the Company will not be treated as a QFC if the Company is a PFIC for the taxable year during which the Company pays a dividend or for the preceding taxable year. (See the section below under the heading "Passive Foreign Investment Company Rules").

If the Company is a QFC, but a U.S. Holder otherwise fails to qualify for the preferential tax rate applicable to dividends discussed above, a dividend paid by the Company to a U.S. Holder, including a U.S. Holder that is an individual, estate, or trust, generally will be taxed at ordinary income tax rates (and not at the preferential tax rates applicable to long-term capital gains). The dividend rules are complex, and each U.S. Holder should consult its own tax advisor regarding the dividend rules.

Sale or Other Taxable Disposition of Common Shares

A U.S. Holder will recognize gain or loss on the sale or other taxable disposition of common shares in an amount equal to the difference, if any, between (a) the amount of cash plus the fair market value of any property received and (b) such U.S. Holder’s tax basis in such common shares sold or otherwise disposed of. Subject to the PFIC rules discussed below, any such gain or loss generally will be capital gain or loss, which will be long-term capital gain or loss if, at the time of the sale or other disposition, such common shares are held for more than one year.

Gain or loss recognized by a U.S. Holder on the sale or other taxable disposition of common shares generally will be treated as “U.S. source” for purposes of applying the U.S. foreign tax credit rules unless the gain is subject to tax in Canada and is sourced as “foreign source” under the Treaty and such U.S. Holder elects to treat such gain or loss as “foreign source.”

Preferential tax rates apply to long-term capital gains of a U.S. Holder that is an individual, estate, or trust. There are currently no preferential tax rates for long-term capital gains of a U.S. Holder that is a corporation. Deductions for capital losses are subject to significant limitations under the Code.

Receipt of Foreign Currency

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The amount of any distribution paid in foreign currency to a U.S. Holder in connection with the ownership of common shares, or on the sale, exchange or other taxable disposition of common shares, generally will be equal to the U.S. dollar value of such foreign currency based on the exchange rate applicable on the date of receipt (regardless of whether such foreign currency is converted into U.S. dollars at that time). A U.S. Holder that receives foreign currency and converts such foreign currency into U.S. dollars at a conversion rate other than the rate in effect on the date of receipt may have a foreign currency exchange gain or loss, which generally would be treated as U.S. source ordinary income or loss. If the foreign currency received is not converted into U.S. dollars on the date of receipt, a U.S. Holder will have a basis in the foreign currency equal to its U.S. dollar value on the date of receipt. Any U.S. Holder who receives payment in foreign currency and engages in a subsequent conversion or other disposition of the foreign currency may have a foreign currency exchange gain or loss that would be treated as ordinary income or loss, and generally will be U.S. source income or loss for foreign tax credit purposes. Each U.S. Holder should consult its own U.S. tax advisor regarding the U.S. federal income tax consequences of receiving, owning, and disposing of foreign currency.

Foreign Tax Credit

A U.S. Holder who pays (whether directly or through withholding) Canadian income tax with respect to dividends paid on common shares generally will be entitled, at the election of such U.S. Holder, to receive either a deduction or a credit for such Canadian income tax paid. Generally, a credit will reduce a U.S. Holder’s U.S. federal income tax liability on a dollar-for-dollar basis, whereas a deduction will reduce a U.S. Holder’s income subject to U.S. federal income tax. This election is made on a year-by-year basis and applies to all foreign taxes paid (whether directly or through withholding) by a U.S. Holder during a year.

Complex limitations apply to the foreign tax credit, including the general limitation that the credit cannot exceed the proportionate share of a U.S. Holder’s U.S. federal income tax liability that such U.S. Holder’s “foreign source” taxable income bears to such U.S. Holder’s worldwide taxable income. In applying this limitation, a U.S. Holder’s various items of income and deduction must be classified, under complex rules, as either “foreign source” or “U.S. source.” Generally, dividends paid by a foreign corporation should be treated as foreign source for this purpose, and gains recognized on the sale of stock of a foreign corporation by a U.S. Holder should be treated as U.S. source for this purpose, except as otherwise provided in an applicable income tax treaty, and if an election is properly made under the Code. However, the amount of a distribution with respect to the common shares that is treated as a “dividend” may be lower for U.S. federal income tax purposes than it is for Canadian federal income tax purposes, resulting in a reduced foreign tax credit allowance to a U.S. Holder. In addition, this limitation is calculated separately with respect to specific categories of income. Dividends paid by the Company generally will constitute “foreign source” income and generally will be categorized as “passive income.”

The foreign tax credit rules are complex, and each U.S. Holder should consult its own tax advisor regarding the foreign tax credit rules.

Additional Tax on Passive Income

For tax years beginning after December 31, 2012, certain individuals, estates and trusts whose income exceeds certain thresholds will be required to pay a 3.8% Medicare surtax on “net investment income” including, among other things, dividends and net gain from disposition of property (other than property held in a trade or business). U.S. Holders should consult with their own tax advisors regarding the effect, if any, of this tax on their ownership and disposition of common shares.

Information Reporting; Backup Withholding Tax For Certain Payments

Under U.S. federal income tax law and regulations, certain categories of U.S. Holders must file information returns with respect to their investment in, or involvement in, a foreign corporation. For example, recently enacted legislation generally imposes new U.S. return disclosure obligations (and related penalties) on U.S. Holders that hold certain specified foreign financial assets in excess of $50,000. The definition of specified foreign financial assets includes not only financial accounts maintained in foreign financial institutions, but also, unless held in accounts maintained by a financial institution, any stock or security issued by a non-U.S. person, any financial instrument or contract held for investment that has an issuer or counterparty other than a U.S. person and any interest in a foreign entity. U. S. Holders may be subject to these reporting requirements unless their common shares are held in an account at a domestic financial institution. Penalties for failure to file certain of these information returns are substantial. U.S. Holders of common shares should consult with their own tax advisors regarding the requirements of filing information returns, these rules, including the requirement to file an IRS Form 8938.

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Payments made within the U.S., or by a U.S. payor or U.S. middleman, of dividends on, and proceeds arising from the sale or other taxable disposition of, common shares generally will be subject to information reporting and backup withholding tax, at the rate of 28% (and increasing to 31% for payments made after December 31, 2012), if a U.S. Holder (a) fails to furnish such U.S. Holder’s correct U.S. taxpayer identification number (generally on Form W-9), (b) furnishes an incorrect U.S. taxpayer identification number, (c) is notified by the IRS that such U.S. Holder has previously failed to properly report items subject to backup withholding tax, or (d) fails to certify, under penalty of perjury, that such U.S. Holder has furnished its correct U.S. taxpayer identification number and that the IRS has not notified such U.S. Holder that it is subject to backup withholding tax. However, certain exempt persons, such as corporations, generally are excluded from these information reporting and backup withholding tax rules. Any amounts withheld under the U.S. backup withholding tax rules will be allowed as a credit against a U.S. Holder’s U.S. federal income tax liability, if any, or will be refunded, if such U.S. Holder furnishes required information to the IRS in a timely manner. Each U.S. Holder should consult its own tax advisor regarding the information reporting and backup withholding rules.

Passive Foreign Investment Company Rules

If the Company were to constitute a PFIC (as defined below) for any year during a U.S. Holder’s holding period, then certain different and potentially adverse tax consequences would apply to such U.S. Holder’s acquisition, ownership and disposition of common shares.

The Company generally will be a PFIC under Section 1297 of the Code if, for a tax year, (a) 75% or more of the gross income of the Company for such tax year is passive income (the “income test”) or (b) 50% or more of the value of its average quarterly assets held by the Company either produce passive income or are held for the production of passive income, based on the fair market value of such assets (the “asset test”). “Gross income” generally includes all revenues less the cost of goods sold, plus income from investments and from incidental or outside operations or sources, and “passive income” includes, for example, dividends, interest, certain rents and royalties, certain gains from the sale of stock and securities, and certain gains from commodities transactions. Active business gains arising from the sale of commodities generally are excluded from passive income if substantially all (85% or more) of a foreign corporation’s commodities are (a) stock in trade of such foreign corporation or other property of a kind which would properly be included in inventory of such foreign corporation, or property held by such foreign corporation primarily for sale to customers in the ordinary course of business, (b) property used in the trade or business of such foreign corporation that would be subject to the allowance for depreciation under Section 167 of the Code, or (c) supplies of a type regularly used or consumed by such foreign corporation in the ordinary course of its trade or business, and certain other requirements are satisfied.

In addition, for purposes of the PFIC income test and asset test described above, if the Company owns, directly or indirectly, 25% or more of the total value of the outstanding shares of another foreign corporation, the Company will be treated as if it (a) held a proportionate share of the assets of such other foreign corporation and (b) received directly a proportionate share of the income of such other foreign corporation. In addition, for purposes of the PFIC income test and asset test described above, “passive income” does not include any interest, dividends, rents, or royalties that are received or accrued by the Company from a “related person” (as defined in Section 954(d)(3) of the Code), to the extent such items are properly allocable to the income of such related person that is not passive income.

Under certain attribution rules, if the Company is a PFIC, U.S. Holders will be deemed to own their proportionate share of any subsidiary of the Company which is also a PFIC (a ‘‘Subsidiary PFIC’’), and will be subject to U.S. federal income tax on (i) a distribution on the shares of a Subsidiary PFIC or (ii) a disposition of shares of a Subsidiary PFIC, both as if the holder directly held the shares of such Subsidiary PFIC.

The Company does not believe that it was a PFIC during the tax year ending December 31, 2012. However, PFIC classification is fundamentally factual in nature, generally cannot be determined until the close of the tax year in question, and is determined annually. Additionally, the analysis depends, in part, on the application of complex U.S. federal income tax rules, which are subject to differing interpretations. Furthermore, if for any given year the Company reaches either of the test standards (i.e., “income test” and “asset test”), it remains a PFIC forever, no matter how active it becomes in the future. Consequently, there can be no assurance that the Company has never been and will not become a PFIC for any tax year during which U.S. Holders hold common shares.

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If the Company were a PFIC in any tax year and a U.S. Holder held common shares, such holder generally would be subject to special rules with respect to “excess distributions” made by the Company on the common shares and with respect to gain from the disposition of common shares. An “excess distribution” generally is defined as the excess of distributions with respect to the common shares received by a U.S Holder in any tax year over 125% of the average annual distributions such U.S. Holder has received from the Company during the shorter of the three preceding tax years, or such U.S. Holder’s holding period for the common shares. Generally, a U.S. Holder would be required to allocate any excess distribution or gain from the disposition of the common shares ratably over its holding period for the common shares. Such amounts allocated to the year of the disposition or excess distribution would be taxed as ordinary income, and amounts allocated to prior tax years would be taxed as ordinary income at the highest tax rate in effect for each such year and an interest charge at a rate applicable to underpayments of tax would apply.

While there are U.S. federal income tax elections that sometimes can be made to mitigate these adverse tax consequences (including, without limitation, the “QEF Election” and the “Mark-to-Market Election”), such elections are available in limited circumstances and must be made in a timely manner. U.S. Holders should be aware that, for each tax year, if any, that the Company is a PFIC, the Company can provide no assurances that it will satisfy the record keeping requirements of a PFIC, or that it will make available to U.S. Holders the information such U.S. Holders require to make a QEF Election under Section 1295 of the Code with respect of the Company or any Subsidiary PFIC. U.S. Holders are urged to consult their own tax advisers regarding the potential application of the PFIC rules to the ownership and disposition of common shares, and the availability of certain U.S. tax elections under the PFIC rules.

F.             Dividends and Paying Agents

Not Applicable.

G.             Statements by Experts

Not Applicable.

H.             Documents on Display

We are subject to the informational requirements of the Exchange Act and file reports and other information with the SEC. You may read and copy any of our reports and other information at, and obtain copies upon payment of prescribed fees from, the Public Reference Room maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. In addition, the SEC maintains a Website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

We are required to file reports and other information with the securities commissions in Canada. You are invited to read and copy any reports, statements or other information, other than confidential filings, that we file with the provincial securities commissions. These filings are also electronically available from the Canadian System for Electronic Document Analysis and Retrieval (“SEDAR”) (http://www.sedar.com), the Canadian equivalent of the SEC’s electronic document gathering and retrieval system.

We “incorporate by reference” information that we file with the SEC, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is an important part of this Form 20-F and more recent information automatically updates and supersedes more dated information contained or incorporated by reference in this Form 20-F.

As a foreign private issuer, we are exempt from the rules under the Exchange Act prescribing the furnishing and content of proxy statements to shareholders.

We will provide without charge to each person, including any beneficial owner, to whom a copy of this annual report has been delivered, on the written or oral request of such person, a copy of any or all documents referred to above which have been or may be incorporated by reference in this annual report (not including exhibits to such incorporated information that are not specifically incorporated by reference into such information). Requests for such copies should be directed to us at the following address: 598 – 999 Canada Place, Vancouver, British Columbia, Canada V6C 3E1, Telephone: (604) 638-5050, Facsimile: (604) 638-5051.

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I.             Subsidiary Information

Not applicable.

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ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is engaged primarily in mineral and oil and gas exploration and production and manages related industry risk issues directly. The Company may be at risk for environmental issues and fluctuations in commodity pricing. Management is not aware of and does not anticipate any significant environmental remediation costs or liabilities in respect of its current operations.

The Company’s functional currency is the Canadian dollar. The Company operates in foreign jurisdictions, giving rise to significant exposure to market risks from changes in foreign currency rates. The financial risk is the risk to the Company’s operations that arises from fluctuations in foreign exchange rates and the degree of volatility of these rates. Currently, the Company does not use derivative instruments to reduce its exposure to foreign currency risk.

The Company also has exposure to a number of risks from its use of financial instruments including: credit risk, liquidity risk, and market risk. This note presents information about the Company’s exposure to each of these risks and the Company’s objectives, policies and processes for measuring and managing risk, and the Company’s management of capital.

The Board of Directors has overall responsibility for the establishment and oversight of the Company’s risk management framework. The Board has implemented and monitors compliance with risk management policies. The Company’s risk management policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls, and to monitor risks and adherence to market conditions and the Company’s activities.

(a)     Credit Risk

Credit risk arises from credit exposure to receivables due from joint venture partners and marketers included in accounts receivable. The maximum exposure to credit risk is equal to the carrying value of the financial assets.

The Company is exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company’s business, financial condition, and results of operations.

The objective of managing the third party credit risk is to minimize losses in financial assets. The Company assesses the credit quality of the partners, taking into account their financial position, past experience, and other factors. The Company mitigates the risk of non-collection of certain amounts by obtaining the joint venture partners’ share of capital expenditures in advance of a project and by monitoring accounts receivable on a regular basis. As at December 31, 2013 and 2012, no accounts receivable has been deemed uncollectible or written off during the year.

As at December 31, 2013, the Company’s receivables consist of $4,000 (2012 - $30,000) from joint interest partners, $760,000 (2012 - $494,000) from oil and natural gas marketers and $67,000 (2012 - $25,000) from other trade receivables.

The Company considers all amounts outstanding for more than 90 days as past due. Currently, there is no indication that amounts are non-collectable; thus an allowance for doubtful accounts has not been set up. As at December 31, 2013, $Nil (2012 - $Nil) of accounts receivable are past due.

(b)     Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they are due. The nature of the oil and gas industry is capital intensive and the Company maintains and monitors a certain level of cash flow to finance operating and capital expenditures.

The Company’s ongoing liquidity and cash flow are impacted by various events and conditions. These events and conditions include but are not limited to commodity price fluctuations, general credit and market conditions, operation and regulatory factors, such as government permits, the availability of drilling and other equipment, lands and pipeline access, weather, and reservoir quality.

To mitigate the liquidity risk, the Company closely monitors its credit facility, production level and capital expenditures to ensure that it has adequate liquidity to satisfy its financial obligations.

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The following are the contractual maturities of financial liabilities as at December 31, 2013:

(CA$ thousands)   Carrying amount     2014  
           
Accounts payable and accrued liabilities   2,623     2,623  
Bank line of credit   2,900     2,900  
Loan facility   2,911     3,500  
    8,434     9,023  

For the contractual maturities of financial contract liability as at December 31, 2013, see note 12 to the 2013 consolidated financial statements for details.

(c) Market Risk

Market risk is the risk that changes in market prices, such as foreign exchange rates, commodity prices, and interest rates will affect the Company’s net earnings. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns. The Company utilizes financial derivatives to manage certain market risks. All such transactions are conducted in accordance with the risk management policy that has been approved by the Board of Directors.

(i)       Foreign Currency Exchange Risk

Foreign currency exchange rate risk is the risk that the fair value of financial instruments or future cash flows will fluctuate as a result of changes in foreign exchange rates. Although substantially all of the Company’s oil and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for oil and natural gas are impacted by changes in the exchange rate between the Canadian and United States dollars. Given that changes in exchange rate have an indirect influence, the impact of changing exchange rates cannot be accurately quantified. The Company had no forward exchange rate contracts in place as at or during the year ended December 31, 2013 and 2012.

The Company was exposed to the following foreign currency risk at December 31:

(CA$ thousands)   2013     2012  
Expressed in foreign currencies   CND$     CND$  
Cash and cash equivalents   376     1,031  
Accounts receivable   421     30  
Accounts payable and accrued liabilities   (1,613 )   (869 )
Balance sheet exposure   (816 )   192  

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

    2013     2012  
December 31, reporting date rate   1.0636     0.9949  
YTD average USD to CAD   1.0301     0.9999  

The Company has performed a sensitivity analysis on its foreign currency denominated financial instruments. Based on the Company’s foreign currency exposure noted above and assuming that all other variables remain constant, a 10% appreciation of the US dollar against the Canadian dollar would result in the increase of net loss of $82,000 at December 31, 2013 (2012 - $19,000 decrease of net loss). 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.

87


(ii)    Interest Rate Risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. At December 31, 2013, the Company was exposed to interest rate fluctuations on its bank credit facility which bore a floating rate of interest. Assuming all other variables remain constant, an increase or decrease of 1% in market interest rate at December 31, 2013 would have increased or decreased net loss by $41,000. The Company had no interest rate swaps or financial contracts in place at or during the year ended December 31, 2013 and 2012.

(iii)   Commodity Price Risk

Revenues and consequently cash flows fluctuate with commodity prices and the US/Canadian dollar exchange rate. Commodity prices are determined on a global basis and circumstances that occur in various parts of the world are outside of the control of the Company. The Company may protect itself from fluctuations in prices by using the financial derivative sales contracts. The Company may enter into commodity price contracts to manage the risks associated with price volatility and thereby protect its cash flows used to fund its capital program. Assuming all other variables remain constant, an increase or decrease of oil price of $1 per bbl and gas price of $0.01 per mcf at December 31, 2013 would have decreased or increased net loss by $85,000. The Company had no commodity contracts in place at December 31, 2013.

(d)      Capital Management Strategy

The Company’s policy on capital management is to maintain a prudent capital structure so as to maintain financial flexibility, preserve access to capital markets, maintain investor, creditor and market confidence, and to allow the Company to fund future developments. The Company considers its capital structure to include share capital, cash and cash equivalents, bank line of credit, and working capital. In order to maintain or adjust capital structure, the Company may from time to time issue shares or enter into debt agreements and adjust its capital spending to manage current and projected operating cash flows and debt levels.

The Company’s current borrowing capacity is based on the lender’s review of the Company’s oil and gas reserves. The Company is also subject to various covenants. Compliance with these covenants is monitored on a regular basis and at December 31, 2013, the Company is in compliance with the covenant for its bank credit facility and is in default of the covenant for its loan facility.

The Company’s share capital is not subject to any external restrictions. The Company has not paid or declared any dividends, nor are any contemplated in the foreseeable future. There have been no changes to the Company’s capital management strategy during the year ended December 31, 2013.

ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

A.-C.

Not applicable.

D.    American Depositary Receipts

The Company does not have securities registered as American Depositary Receipts.

88


PART II

ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

None.

ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

A. – D.

None.

E.              Use of Proceeds

Not Applicable.

ITEM 15. CONTROLS AND PROCEDURES

A.             Disclosure Controls and Procedures

As of the end of the fiscal year ended December 31, 2013, an evaluation of the effectiveness of the Company’s “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), was performed by the Company’s management, under the supervision and with the participation of the Company’s Chief Executive Officer and Chief Financial Officer. Based on that evaluation, the Company’s CEO and CFO have concluded that the Company’s disclosure controls and procedures were effective to give reasonable assurance that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Our management concluded that our disclosure controls and procedures were effective. The applicable information was filed on a timely basis with the Canadian securities regulators on SEDAR and was publicly accessible on www.SEDAR.com and on the Company’s website, but was not timely furnished on Edgar on Form 6-K. We have taken steps designed to ensure that future information required to be furnished on Form 6-K will be so furnished on a timely basis.

B.             Management’s Report on Internal Control over Financial Reporting

The Company’s management, including the Company’s Chief Executive Officer and the Company’s Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over the Company’s internal control over financial reporting, as such term is defined in Rule 13a-15(f) under the Exchange Act. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation and fair presentation of financial statements for external purposes in accordance with International Financial Reporting Standards. It should be noted that a control system, no matter how well conceived or operated, can only provide reasonable assurance, not absolute assurance, that the objectives of the control system are met. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.

The Company’s management, (with the participation of the Company’s Chief Executive Officer and the Company’s Chief Financial Officer), conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2013. This evaluation was based on the criteria set forth in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment, management has concluded that, as of December 31, 2013, the Company’s internal control over financial reporting was effective and management’s assessment did not identify material weaknesses.

89


C.             Attestation Report of the Registered Public Accounting Firm

Because the Company is not an “accelerated filer” or “large accelerated filer” within the meaning of such terms under the Exchange Act, this Annual Report is not required to include an attestation report of the Company’s independent auditors regarding the Company’s internal control over financial reporting.

D.             Changes in Internal Control Over Financial Reporting

There were no amendments to the Company’s system of internal control over financial reporting during the year ended December 31, 2013 and the Company is not aware of any amendments to its system of internal control that should be implemented to strengthen its system of internal control over financial reporting.

ITEM 16. [RESERVED]

ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT

The Company does not have a financial expert, as defined by the US Securities and Exchange Commission, serving on the Company’s “Audit Committee”. In 2011, the Company adopted “International Financial Reporting Standards” (“IFRS”) to comply with Canadian public company reporting standards. The Audit Committee members do not, as yet, have sufficient experience and in-depth understanding of IFRS to qualify as experts.

ITEM 16B. CODE OF ETHICS

The Board of Directors of the Company has adopted a Code of Conduct and Ethics that outlines the Company’s values and its commitment to ethical business practices in every business transaction. This code applies to all directors, officers, and employees of the Company and its subsidiaries and affiliates. A copy of the Company’s Code of Business Conduct and Ethics is available on the Company’s website at www.dejour.com.

Reporting Unethical and Illegal Conduct/Ethics Questions

The Company is committed to taking prompt action against violations of the Code of Conduct and Ethics and it is the responsibility of all directors, officers and employees to comply with the Code and to report violations or suspected violations to the Company’s Compliance Officer. Employees may also discuss their concerns with their supervisor who will then report suspected violations to the Compliance Officer.

The Compliance Officer is appointed by the Board of Directors and is responsible for investigating and resolving all reported complaints and allegations and shall advise the President and CEO, the CFO and/or the Audit Committee.

During the fiscal year ended December 31, 2013, the Company did not substantially amend, waive, or implicitly waive any provision of the Code with respect to any of the directors, executive officers or employees subject to it.

90


ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table sets out the fees billed to the Company by BDO Canada LLP for professional services rendered during fiscal years ended December 31, 2013 and December 31, 2012. During these years, BDO Canada LLP was our external auditors.



Year ended
December 31, 2013
$
Year ended
December 31, 2012
$
Audit Services (1) 201,762 229,950
Audit Related Services (2) 29,700 100,430
Tax Services (3) 8,500 11,210
All Other Fees (4) 16,235 27,850

NOTES:

(1)

Audit fees consist of fees for the audit of the Company’s annual financial statements and review of the Company’s quarterly financial statements, or services that are normally provided in connection with statutory and regulatory filings or engagements.

   
(2)

Audit-related fees consist of fees for assurance and related services that are reasonably related to the performance of the audit or review of the Company’s financial statements and are not reported as Audit fees. During fiscal 2013 and 2012, the services provided in this category included consultation on accounting and audit-related matters and review of reserves disclosure.

   
(3)

Tax fees consist of fees for tax compliance services, tax advice and tax planning. During fiscal 2013 and 2012, the services provided in this category included assistance and advice in relation to the preparation of corporate income tax returns.

   
(4)

During fiscal 2013 and 2012, the aggregate fees in this category consist of Canadian Public Accountability Board (“CPAB”) fees and administration costs.

Pre-Approval Policies and Procedures

Generally, in the past, prior to engaging the Company’s auditors to perform a particular service, the Company’s audit committee has, when possible, obtained an estimate for the services to be performed. The audit committee in accordance with procedures for the Company approved all of the services described above.

In relation to the pre-approval of all audit and audit-related services and fees the Company’s audit committee charter provides that the audit committee shall:

Review and pre-approve all audit and audit-related services and the fees and other compensation related thereto, and any non-audit services, provided by the Company’s external auditors. The pre-approval requirement is waived with respect to the provision of non-audit services if:

i.

the aggregate amount of all such non-audit services provided to the Company constitutes not more than five percent of the total amount of revenues paid by the Company to its external auditors during the fiscal year in which the non-audit services are provided;

ii.

such services were not recognized by the Company at the time of the engagement to be non-audit services; and

iii.

such services are promptly brought to the attention of the Committee by the Company and approved prior to the completion of the audit by the Committee or by one or more members of the Committee who are members of the Board to whom authority to grant such approvals has been delegated by the Committee.

Provided the pre-approval of the non-audit services is presented to the Committee’s first scheduled meeting following such approval such authority may be delegated by the Committee to one or more independent members of the Committee.

We did not rely on the de minimus exemption provided by Section (c)(7)(i)(C) of Rule 2-01 of SEC Regulation S-X in 2013.

ITEM 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES

None.

91


ITEM 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS

The Company did not repurchase any common shares in the fiscal year ended December 31, 2013.

ITEM 16F. CHANGE IN REGISTRANT’S CERTIFYING ACCOUNTANT

Not applicable.

ITEM 16G. CORPORATE GOVERNANCE

The Company’s common shares are listed on the NYSE Amex. Section 110 of the NYSE Amex Company Guide permits the NYSE Amex to consider the laws, customs and practices of foreign issuers in relaxing certain NYSE Amex listing criteria, and to grant exemptions from NYSE Amex listing criteria based on these considerations. A company seeking relief under these provisions is required to provide written certification from independent local counsel that the non-complying practice is not prohibited by home country law. A description of the significant ways in which the Company’s governance practices differ from those followed by domestic companies pursuant to NYSE Amex standards is as follows:

Shareholder Meeting Quorum Requirement : The NYSE Amex minimum quorum requirement for a shareholder meeting is one-third of the outstanding shares of common stock. In addition, a company listed on NYSE Amex is required to state its quorum requirement in its bylaws. The Company’s quorum requirement is set forth in its Articles and bylaws. A quorum for a meeting of members of the Company is one holder of common shares issued, outstanding and entitled to vote, represented in person or by proxy.

Proxy Delivery Requirement : NYSE Amex requires the solicitation of proxies and delivery of proxy statements for all shareholder meetings, and requires that these proxies shall be solicited pursuant to a proxy statement that conforms to SEC proxy rules. The Company is a “foreign private issuer” as defined in Rule 3b-4 under the Exchange Act, and the equity securities of the Company are accordingly exempt from the proxy rules set forth in Sections 14(a), 14(b), 14(c) and 14(f) of the Exchange Act. The Company solicits proxies in accordance with applicable rules and regulations in Canada.

Shareholder Approval Requirement: The Company will follow Toronto Stock Exchange rules for shareholder approval of new issuances of its common shares. Following Toronto Stock Exchange rules, shareholder approval is required for certain issuances of shares that: (i) materially affect control of the Company; or (ii) provide consideration to insiders in aggregate of 10% or greater of the market capitalization of the listed issuer and have not been negotiated at arm’s length. Shareholder approval is also required, pursuant to TSX rules, in the case of private placements: (x) for an aggregate number of listed securities issuable greater than 25% of the number of securities of the listed issuer which are outstanding, on a non-diluted basis, prior to the date of closing of the transaction if the price per security is less than the market price; or (y) that during any six month period are to insiders for listed securities or options, rights or other entitlements to listed securities greater than 10% of the number of securities of the listed issuer which are outstanding, on a non-diluted basis, prior to the date of the closing of the first private placement to an insider during the six month period.

The foregoing is consistent with the laws, customs and practices in Canada.

In addition, the Company may from time-to-time seek relief from NYSE Amex corporate governance requirements on specific transactions under Section 110 of the NYSE Amex Company Guide by providing written certification from independent local counsel that the non-complying practice is not prohibited by our home country law, in which case, the Company shall make the disclosure of such transactions available on the Company’s website at www.dejour.com. Information contained on its website is not part of this annual report.

ITEM 16H – MINE SAFETY DISCLOSURE

Not Applicable.

92


PART III

ITEM 17. FINANCIAL STATEMENTS

The Company has provided financial statements pursuant to Item 18.

ITEM 18. FINANCIAL STATEMENTS

Report of Independent Registered Chartered Accountants, dated March 18, 2014
 
Consolidated Balance Sheets at December 31, 2013 and 2013
 
Consolidated Statements of Comprehensive Loss for the years ending December 31, 2013, 2012 and 2011.
 
Consolidated Statements of Changes in Shareholder’s Equity for the years ended December 31, 2013, 2012 and 2011.
 
Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011.
 
Notes to the Consolidated Financial Statements
 
Supplementary Oil and Gas Reserve Estimation and Disclosures (Unaudited) for the years ending December 31, 2013 and 2012

93


ITEM 19. EXHIBITS

Financial Statements

Description Page
   
Consolidated Financial Statements for the Years Ended December 31, 2013, 2012 and 2011. F-1 - F-41

Supplementary Oil and Gas Reserve Estimation and Disclosures (Unaudited) for the years ending December 31, 2013 and 2012

EXHIBIT  
NUMBER DESCRIPTION
   
1.1

Articles (1)

   
1.2

Notice of Articles (1)

   
1.3

Certificate of Continuation (1)

   
1.4

Notice of Alteration (1)

   
1.5

Certificate of Name Change (1)

   
1.6

Amendment to Articles to Include Special Rights (1)

   
4.1

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

   
4.2

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

   
4.3

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

   
4.4

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

   
4.5

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

   
4.6

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

   
4.7

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

   
4.8

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

   
4.9

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

   
4.10

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

   
4.11

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

   
4.12

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

   
4.13

Loan Agreement between the Registrant and Toscana Capital Corporation dated February 19, 2010 (6)

   
4.14

Amended Loan Agreement between the Registrant and Toscana Capital Corporation dated September 1, 2010 (6)

   
4.15

Credit Facility Agreement between DEAL and Canadian Western Bank dated August 3, 2011 (7)

   
4.16

Credit Facility Renewal Letter between DEAL and Canadian Western Bank dated December 29, 2011 (7)

94



EXHIBIT  
NUMBER DESCRIPTION
   
4.17 Option Plan (1)
   
4.18 Option Plan (Sub-Plan) (1)
   
4.19

Credit Facility Renewal Letter between DEAL and Canadian Western Bank dated May 11, 2012 (7)

   
4.20

Credit Facility Renewal Letter between DEAL and Canadian Western Bank dated October 3, 2012 (7)

   
4.21

Financial Contract with Bakken Drilling Fund III, LP dated December 31, 2012 (7)

   
4.22

Credit Facility Renewal Letter between DEAL and Canadian Western Bank dated March 25, 2013 (7)

   
4.23

Credit Facility Renewal Letter between DEAL and Canadian Western Bank dated June 5, 2013*

   
4.24

Commitment Letter between the Registrant and Invico Performance Yield Fund Limited Partnership dated June 11, 2013*

   
4.25

Amendment to Financial Contract with Bakken Drilling Fund III, LP dated September 10, 2013*

   
4.26

Credit Facility Renewal Letter between DEAL and Canadian Western Bank dated December 16, 2013*

   
4.27

Credit Facility Renewal Letter between DEAL and Canadian Western Bank dated February 18, 2014*

   
8.1

List of Subsidiaries (7)

   
12.1

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

   
12.2

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

   
13.1

Certification of CEO Pursuant to 18 U.S.C. Section 1350*

   
13.2

Certification of CFO Pursuant to 18 U.S.C. Section 1350*

   
15.1

Consent of BDO Canada LLP*

   
15.2

Consent Letter from GLJ Petroleum Consultants*

   
15.3

Consent Letter from Deloitte LLP*

   
15.4

Consent Letter from Gustavson Associates*

   
99.1

Third Party Report on Reserves Prepared by GLJ Petroleum Consultants, Effective December 31, 2013*

   
99.2

Reserve Estimate and Financial Forecast as to Dejour’s Interests in the Kokopelli Field Area, Garfield County, Colorado, Prepared by Gustavson Associates, Effective January 1, 2014*


(1)

Incorporated by reference to the Registrant’s registration statement on Form S-8, filed with the commission on February 16, 2012.

(2)

Incorporated by reference to the Registrant’s annual report on Form 20-F, filed July 14, 2006.

(3)

Incorporated by reference to the Registrant’s annual report on Form 20-F/A amendment no. 2, filed December 7, 2007.

(4)

Incorporated by reference to the Registrant’s annual report on Form 20-F, filed on June 30, 2009.

(5)

Incorporated by reference to the Registrant’s annual report on Form 20-F, filed on June 30, 2010.

(6)

Incorporated by reference to the Registrant’s annual report on Form 20-F, filed on June 30, 2011.

(7)

Previously Filed.

* Filed herewith

95


SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

      DEJOUR Energy Inc.
       
       
       
Dated: April 24, 2014   /s/ Robert L. Hodgkinson
      Robert L. Hodgkinson
      Chairman & CEO

96


CONSOLIDATED FINANCIAL STATEMENTS (AUDITED)

December 31, 2013

F-1


F-2


F-3


DEJOUR ENERGY INC.
CONSOLIDATED BALANCE SHEETS
(Expressed in Canadian Dollars)

          December 31,     December 31,  
(CA$ thousands)   Notes     2013     2012  
          $     $  
ASSETS                  
Current                  
       Cash and cash equivalents         505     1,508  
       Accounts receivable         831     549  
       Prepaids and deposits         49     92  
Current Assets         1,385     2,149  
Non-current                  
     Deposits         447     392  
     Exploration and evaluation assets   5     3,281     3,890  
     Property and equipment   6     20,386     21,144  
Total Assets         25,499     27,575  
                   
LIABILITIES                  
Current                  
       Bank credit facilities   8     2,900     5,957  
       Loan facility   10     2,911     -  
       Accounts payable and accrued liabilities         2,623     2,019  
       Warrant liability   9     324     1,425  
       Derivative liability   10     287     -  
       Current portion of financial contract liability   12     1,248     1,305  
Current Liabilities         10,293     10,706  
Non-current                  
     Decommissioning liability   11     1,212     1,429  
     Other liabilities         22     32  
     Financial contract liability   12     4,873     5,162  
Total Liabilities         16,400     17,329  
SHAREHOLDERS' EQUITY                  
       Share capital   13     90,274     90,274  
       Contributed surplus   15     9,150     8,802  
       Deficit         (90,839 )   (88,262 )
       Accumulated other comprehensive income (loss)         514     (568 )
Total Shareholders' Equity         9,099     10,246  
Total Liabilities and Shareholders' Equity         25,499     27,575  

Approved on behalf of the Board:    
     
     
"signed Robert Hodgkinson"   "signed Craig Sturrock"
Robert Hodgkinson - Director   Craig Sturrock - Director

The accompanying notes are an integral part of these consolidated financial statements. F-4


DEJOUR ENERGY INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(Expressed in Canadian Dollars)

          Year ended December 31  
(CA$ thousands, except per share amounts)   Notes     2013     2012     2011  
          $     $     $  
REVENUES                        
     Gross revenues         9,317     6,882     8,824  
     Royalties         (1,811 )   (1,116 )   (1,628 )
       Total Revenues, net of royalties   21     7,506     5,766     7,196  
                         
EXPENSES                        
     Operating and transportation         3,398     3,793     2,500  
     General and administrative         3,384     3,525     4,042  
     Financing expenses         1,182     587     868  
     Stock based compensation   15     348     866     662  
     Foreign exchange loss (gain)         505     190     97  
     (Gain) loss on disposal of E&E assets   5     185     (299 )   -  
     Loss on disposal of property and equipment   6     107     -     -  
     Amortization, depletion and impairment losses   7     3,630     10,676     8,652  
     Change in fair value of warrant liability   9     (1,101 )   (1,842 )   1,580  
     Change in fair value of derivative liability   10     (264 )   -     -  
     Gain on financial contract liability   12     (1,268 )   -     -  
       Total Expenses         10,106     17,496     18,401  
                         
Loss before other items         (2,600 )   (11,730 )   (11,205 )
   Financial instrument loss         -     (55 )   (59 )
   Other income         23     33     34  
                         
Loss before income taxes         (2,577 )   (11,752 )   (11,230 )
   Deferred tax recovery         -     -     187  
                         
Loss for the year         (2,577 )   (11,752 )   (11,043 )
   Foreign currency translation adjustment         1,082     (175 )   292  
                         
Comprehensive loss         (1,495 )   (11,927 )   (10,751 )
                         
Loss per common share - basic and diluted   16     (0.02 )   (0.08 )   (0.09 )

The accompanying notes are an integral part of these consolidated financial statements. F-5


DEJOUR ENERGY INC.
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Expressed in Canadian Dollars)

          Number     Share     Contributed                    
(CA$ thousands, except number of shares)   Notes     of Shares     Capital     Surplus     Deficit     AOCI(L)*     Total  
              $     $     $     $     $  
Balance as at January 1, 2013         148,916,374     90,274     8,802     (88,262 )   (568 )   10,246  
   Stock-based compensation   15                 348                 348  
   Net loss                           (2,577 )         (2,577 )
   Foreign currency translation adjustment                                 1,082     1,082  
Balance as at December 31, 2013         148,916,374     90,274     9,150     (90,839 )   514     9,099  
                                           
Balance as at January 1, 2012         126,892,386     85,076     8,134     (76,510 )   (393 )   16,307  
   Shares issued via private placements, net of issuance costs         18,130,305     3,248                       3,248  
   Issue of shares on exercise of warrants and options         3,893,683     1,466                       1,466  
   Warrant liability reallocated on exercise of warrants               286                       286  
   Contributed surplus reallocated on exercise of options   13           198     (198 )               -  
   Stock-based compensation                     866                 866  
   Net loss                           (11,752 )         (11,752 )
   Foreign currency translation adjustment                                 (175 )   (175 )
Balance as at December 31, 2012         148,916,374     90,274     8,802     (88,262 )   (568 )   10,246  
                                           
Balance as at January 1, 2011         110,180,545     79,386     7,639     (65,467 )   (685 )   20,873  
   Shares issued via private placements, net of issuance costs         11,010,000     2,694                       2,694  
   Issue of shares on exercise of warrants and options         5,701,841     2,091                       2,091  
   Warrant liability reallocated on exercise of warrants               738                       738  
   Contributed surplus reallocated on exercise of options   13           167     (167 )               -  
   Stock-based compensation                     662                 662  
   Net loss                           (11,043 )         (11,043 )
   Foreign currency translation adjustment                                 292     292  
Balance as at December 31, 2011         126,892,386     85,076     8,134     (76,510 )   (393 )   16,307  

* Accumulated other comprehensive income (loss)

The accompanying notes are an integral part of these consolidated financial statements. F-6

DEJOUR ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Expressed in Canadian Dollars)

          Year ended December 31  
(CA$ thousands)   Notes     2013     2012     2011  
          $     $     $  
CASH FLOWS FROM (USED IN) OPERATING ACTIVITIES                        
     Net loss for the year         (2,577 )   (11,752 )   (11,043 )
     Adjustment for items not affecting cash:                        
         Amortization, depletion and impairment losses         3,630     10,676     8,652  
         Stock based compensation         348     866     662  
         Non-cash financing expenses         1,012     53     22  
         Non-cash foreign exchange on financial contract liability         462     -     -  
         Loss on settlement of decommissioning liability         -     92     -  
         (Gain) loss on disposal of E&E assets         185     (299 )   -  
         Loss on disposal of property and equipment         107     -     -  
         Gain on financial contract liability         (1,268 )   -     -  
         Deferred tax recovery         -     -     (187 )
         Change in fair value of derivative liability         (264 )   -     -  
         Change in fair value of warrant liability         (1,101 )   (1,842 )   1,580  
         Amortization of deferred leasehold inducement         (12 )   (12 )   (8 )
     Changes in operating working capital   16     440     (1,009 )   442  
          Total Cash Flows from (used in) Operating Activities         962     (3,227 )   120  
CASH FLOWS FROM (USED IN) INVESTING ACTIVITIES                        
     Deposits         (55 )   12     39  
     E&E expenditures         (249 )   (448 )   (225 )
     Additions to property and equipment         (1,792 )   (4,037 )   (8,135 )
     Proceeds from sale of E&E assets         284     353     -  
     Proceeds from sale of property and equipment         477     2     1  
     Changes in investing working capital   16     (76 )   (583 )   888  
          Total Cash Flows from (used in) Investing Activities         (1,411 )   (4,701 )   (7,432 )
CASH FLOWS FROM (USED IN) FINANCING ACTIVITIES                        
     Advance (repayment) of bank credit facilities         (3,057 )   410     5,546  
     Advance (repayment) of bridge loan         -     -     (4,800 )
     Advance (repayment) of loan facility         2,971     -     -  
     Advance (repayment) of financial contract liability         (468 )   -     -  
     Advance (repayment) of loans from related parties & other liabilities         -     -     (230 )
     Shares issued on exercise of warrants and options         -     1,466     2,091  
     Shares issued for cash, net of share issue costs         -     4,556     3,004  
     Changes in financing working capital   16     -     516     (568 )
          Total Cash Flows from (used in) Financing Activities         (554 )   6,948     5,043  
                         
CHANGE IN CASH AND CASH EQUIVALENTS         (1,003 )   (980 )   (2,269 )
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR         1,508     2,488     4,757  
                         
CASH AND CASH EQUIVALENTS, END OF YEAR         505     1,508     2,488  

Supplemental cash flow information - Note 16

The accompanying notes are an integral part of these consolidated financial statements. F-7


DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 1 – CORPORATE INFORMATION

Dejour Energy Inc. (the “Company”) is a public company trading on the New York Stock Exchange AMEX (“NYSE-AMEX”) and the Toronto Stock Exchange (“TSX”), under the symbol “DEJ.” The Company is in the business of exploring and developing energy projects with a focus on oil and gas in North America. On March 9, 2011, the Company changed its name from Dejour Enterprises Ltd. to Dejour Energy Inc. The address of its registered office is 598 – 999 Canada Place, Vancouver, British Columbia.

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”), incorporated in Alberta, Wild Horse Energy Ltd. (“Wild Horse”), incorporated in Alberta, and 0855524 B.C. Ltd., incorporated in British Columbia. All intercompany transactions are eliminated upon consolidation.

The consolidated financial statements are presented in Canadian dollars, which is also the functional currency of the parent company. These consolidated financial statements were authorized and approved for issuance by the Board of Directors on March 18, 2014.

NOTE 2 – BASIS OF PRESENTATION

(a)     Basis of presentation

The consolidated financial statements (the “financial statements”) are presented under International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board and interpretations of the Internal Financial Reporting Interpretations Committee (“IFRIC”) and adopted by the Canadian Institute of Chartered Accountants (“CICA”). A summary of the Company’s significant accounting policies under IFRS is presented in note 3.

(b)     Going concern

The financial statements were prepared on a going concern basis. The going concern basis assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities and commitments in the normal course of business. The Company has a working capital deficiency of $8.9 million and accumulated deficit of $90.8 million. Working capital includes non-cash warrant liability and non-cash derivative liability.

On June 19, 2013, the Company, through Dejour USA, borrowed under a $3.5 million loan facility (“Loan Facility”) from a Canadian institutional lender (“Lender”). At December 31, 2013, Dejour USA was in default of its working capital ratio covenant. As a result, the loan facility is due upon demand and classified as current liabilities. The Lender has not demanded repayment as at December 31, 2013.

Subsequent to December 31, 2013, DEAL renewed its Credit Facilities with a Canadian Bank and contracted to utilize $600,000 of the $3.5 million to fund the proposed acquisition of certain producing natural gas properties in Canada until March 31, 2014. If the proposed acquisition fails to close for whatever reason by March 31, 2014, the maximum amount will be reduced by $300,000 effective April 1, 2014. Monthly principal payments of $100,000 are still due and payable commencing March 1, 2014.

The Company’s ability to continue as a going concern is dependent upon attaining profitable operations and obtaining sufficient financing to meet obligations and continue exploration and development activities. There is no assurance that these activities will be successful. These material uncertainties cast substantial doubt upon the Company’s ability to continue as a going concern. These consolidated financial statements do not reflect the adjustments to the carrying values of assets and liabilities, the reported revenues and expenses, and the balance sheet classifications used that would be necessary if the going concern assumptions were not appropriate.

F-8



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 2 – BASIS OF PRESENTATION (continued)

(c)     Basis of measurement

The consolidated annual financial statements have been prepared on the historical cost basis except for the revaluation of certain financial assets and liabilities to fair value as explained in the accounting policies in note 3.

(d)     Use of estimates and judgments

The preparation of consolidated annual financial statements in compliance with IFRS requires management to make certain critical accounting estimates. It also requires management to exercise judgment in applying the Company’s accounting policies. The areas involving a higher degree of judgment or complexity, or areas where assumptions and estimates are significant to the financial statements are disclosed in note 4.

(e)     Functional and presentation currency

Subsidiaries measure items using the currency of the primary economic environment in which the entity operates with entities having a functional currency different from the parent company, translated into Canadian dollars.

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The accounting policies set out below have been applied consistently to all periods presented in these consolidated annual financial statements and have been applied consistently by the Company’s entities.

(a)     Basis of consolidation

The consolidated annual financial statements include the financial statements of the Company and subsidiaries controlled by the Company. Subsidiaries are fully consolidated from the date of acquisition, being the date on which the Company obtains control, and continue to be consolidated until the date that such control ceases. All intra-group balances, transactions, income and expenses are eliminated in full on consolidation.

The financial statements of the subsidiaries are prepared using the same reporting period as the parent company, using consistent accounting policies.

Exploration, development, and production activities may be conducted jointly with others and accordingly, the Company accounts for the assets, liabilities, revenues and expenses related to its interest in the joint operations from the date that joint control commences until the date that it ceases.

(b)     Foreign currency

Items included in the financial statements of each consolidated entity in the group are measured using the currency of the primary economic environment in which the entity operates (the “functional currency”).

The financial statements of entities within the consolidated group that have a functional currency different from that of the Company (“foreign operations”) are translated into Canadian dollars as follows: assets and liabilities – at the closing rate as at the balance sheet date, and income and expenses – at the average rate of the period (as this is considered a reasonable approximation to actual rates). All resulting changes are recognized in other comprehensive income (loss) as cumulative translation differences.

F-9



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(b)    Foreign currency (continued)

When the Company disposes of its entire interests in a foreign operation, or loses control, joint control, or significant influence over a foreign operation, the foreign currency gains or losses accumulated in other comprehensive income (loss) related to the foreign operation are recognized in profit or loss. If an entity disposes of part of an interest in a foreign operation which remains a subsidiary, a proportionate amount of foreign currency gains or losses accumulated in other comprehensive income related to the subsidiary are reallocated between controlling and non-controlling interests.

Transactions in foreign currencies are translated into the functional currency at exchange rates at the date of the transactions. Foreign currency differences arising on translation are recognized in profit or loss. Foreign currency monetary assets and liabilities are translated at the functional currency exchange rate at the balance sheet date. Non- monetary items that are measured at historical cost in a foreign currency are translated using the exchange rates as at the dates of the initial transactions. Non-monetary items measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value was determined.

Exchange differences recognized in the profit or loss statement of the Company’s entities’ separate financial statements on the translation of monetary items forming part of the Company’s net investment in the foreign operation are reclassified to foreign exchange reserve on consolidation.

(c)     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.

(d)     Resource properties

Exploration and evaluation (“E&E”) costs

Pre-license costs are expensed in the period in which they are incurred.

E&E costs are initially capitalized as either tangible or intangible E&E assets according to the nature of the assets acquired. Intangible E&E assets may include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, and directly attributable overhead and administration expenses. The costs are accumulated in cost centers by well, field or exploration area pending determination of technical feasibility and commercial viability.

E&E assets are assessed for impairment if sufficient data exists to determine technical feasibility and commercial viability or facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For purposes of impairment testing, E&E assets are assessed at the individual asset level. If it is not possible to estimate the recoverable amount of the individual asset, exploration and evaluation assets are allocated to cash-generating units (“CGU’s”). Such CGU’s are not larger than an operating segment.

Exploration assets are not depleted and are carried forward until technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable or sufficient/continued progress is made in assessing the commercial viability of the E&E assets. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable when proven reserves are determined to exist. A review of each exploration license or field is carried out, at least annually, to confirm whether the Company intends further appraisal activity or to otherwise extract value from the property. When this is no longer the case, the costs are written off. Upon determination of proven reserves, E&E assets attributable to those reserves are first tested for impairment and then reclassified from E&E assets to oil and natural gas properties.

F-10



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(d)    Resource properties (continued)

The Company may occasionally enter into arrangements, whereby the Company will transfer part of an oil and gas interest, as consideration, for an agreement by the transferee to meet certain E&E expenditures which would have otherwise been undertaken by the Company. The Company does not record any expenditures made by the transferee. Any cash consideration received from the agreement is credited against the costs previously capitalized to the oil and gas interest given up by the Company, with any excess cash accounted for as a gain on disposal.

Oil and gas properties and other property and equipment costs

Items of property and equipment, which include oil and gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses.

The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of the decommissioning obligation and, for qualifying assets, borrowing costs. The purchase price or construction cost is the aggregate amount paid and the fair value of any other consideration given to acquire the asset.

When significant parts of an item of property and equipment, including oil and natural gas interests, have different useful lives, they are accounted for as separate items (major components).

Depletion and Depreciation

Oil and gas development and production assets are depreciated, by significant component, on a unit-of-production basis over proved and probable reserve volumes, taking into account estimated future development costs necessary to bring those reserves into production. Future development costs are estimated by taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually. Changes in reserve estimates are dealt with prospectively. Proved and probable reserves are estimated using independent reserve engineer reports and represent the estimated quantities of oil, natural gas and gas liquids.

Other property and equipment are depreciated based on a declining balance basis, which approximates the estimated useful lives of the asset, at the following rates:

Office furniture and equipment 20%
Computer equipment 45%
Vehicle 30%
Leasehold improvements term of lease

Depreciation methods, useful lives and residual values are reviewed at each reporting date. Other property and equipment are allocated to each of the Company’s primary cash-generating units, based on estimated future net revenue, consistent with the recoverable values applied in the most recent impairment test.

Derecognition

The carrying amount of an item of property and equipment is derecognized on disposal, when no beneficial interest is retained, or when no future economic benefits are expected from its use or disposal. The gain or loss arising from derecognition is included in profit or loss when the item is derecognized and is measured as the difference between the net disposal proceeds, if any, and the carrying amount of the item. The date of disposal is the date when the Company is no longer subject to the risks of ownership and is no longer the beneficiary of the rewards of ownership. Where the asset is derecognized, the date of disposal coincides with the date the revenue from the sale of the asset is recognized.

On the disposition of an undivided interest in a property, where an economic benefit remains, the Company recognizes the farm out only on the receipt of consideration by reducing the carrying amount of the related property with any excess recognized in profit or loss of the period.

F-11



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(d)    Resource properties (continued)

Major maintenance and repairs

The costs of day-to-day servicing are expensed as incurred. These primarily include the costs of labor, consumables and small parts. Material costs of replaced parts, turnarounds and major inspections are capitalized as it is probable that future economic benefits will be received. The carrying value of a replaced part is derecognized in accordance with the derecognition principles above.

Jointly controlled assets and operations

The Company has certain exploration and production activities that are conducted under joint operating agreements whereby two or more parties jointly control the assets. These financial statements reflect the Company’s assets, including its share of any assets held jointly; its liabilities, including its share of any liabilities incurred jointly; and, once production commences, its revenue from the sale of its share of the output arising from the joint operation; and its expenses, including its share of any expenses incurred jointly.

(e)     Provisions

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risk specific to the liability.

Decommissioning liability

A decommissioning liability is recognized when the Company has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of obligation can be made. A corresponding amount equivalent to the provision is also recognized as part of the cost of the related asset. The amount recognized is management’s estimated cost of decommissioning, discounted to its present value using a risk free rate. Changes in the estimated timing of decommissioning or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision and a corresponding adjustment to the related asset unless the change arises from production. The unwinding of the discount on the decommissioning provision is included as a finance cost. Actual costs incurred upon settlement of the decommissioning liability are charged against the provision to the extent the provision was established.

(f)     Earnings (loss) per share

Basic earnings (loss) per share figures have been calculated using the weighted average number of common shares outstanding during the respective periods.

Diluted earnings (loss) per common share is calculated by dividing the profit or loss applicable to common shares by the sum of the weighted average number of common shares issued and outstanding and all additional common shares that would have been outstanding if potentially dilutive instruments were converted. The diluted earnings (loss) per share figure is equal to that of basic earnings (loss) per share since the effects of options and warrants have been excluded as they are anti-dilutive.

F-12



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(g)     Share based payments

Where equity-settled share options are awarded to employees, the fair value of the options at the date of grant is charged to profit or loss over the vesting period. Performance vesting conditions are taken into account by adjusting the number of equity instruments expected to vest at each reporting date so that, ultimately, the cumulative amount recognized over the vesting period is based on the number of options that will eventually vest. Where equity instruments are granted to employees, they are recorded at the instruments grant date fair value.

Where the terms and conditions of options are modified before they vest, the increase in the fair value of the options, measured immediately before and after the modification, is also charged to profit or loss over the remaining vesting period.

Where equity instruments are granted to non-employees, they are recorded at the fair value of the goods or services received in profit or loss, unless they are related to the issuance of shares. Amounts related to the issuance of shares are recorded as a reduction of share capital.

When the value of goods or services received in exchange for the share-based payment to non-employees cannot be reliably estimated, the fair value of the share-based payment is measured by use of a valuation model to measure the value of the equity instruments issued. The expected life used in the model is adjusted, based on management’s best estimate, for the effects of non-transferability, exercise restrictions, and behavioural considerations.

All equity-settled share based payments are reflected in contributed surplus, until exercised. Upon exercise, shares are issued from treasury and the amount reflected in contributed surplus is credited to share capital along with any consideration received.

Where a grant of options is cancelled or settled during the vesting period, excluding forfeitures when vesting conditions are not satisfied, the Company immediately accounts for the cancellation as an acceleration of vesting and recognizes the amount that otherwise would have been recognized for services received over the remainder of the vesting period. Any payment made to the employee on the cancellation is accounted for as the repurchase of an equity interest except to the extent the payment exceeds the fair value of the equity instrument granted, measured at the repurchase date. Any such excess is recognized as an expense.

(h)     Revenue recognition

Revenue from the sale of oil and petroleum products is recognized when the significant risks and rewards of ownership have been transferred, which is when title passes to the customer. This generally occurs when the product is physically transferred into a vessel, pipe or other delivery mechanism. Revenue is stated after deducting sales taxes, excise duties and similar levies.

Revenue from the production of oil and natural gas in which the Company has an interest with other producers is recognized based on the Company’s working interest and the terms of the relevant production sharing contracts.

(i)     Financial instruments

Financial assets

Financial assets are classified as one of the following categories. All transactions related to financial instruments are recorded on a trade date basis. The Company's accounting policy for each category is as follows:

F-13



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(i)    Financial instruments (continued)

Loans and receivables

These assets are non-derivative financial assets resulting from the delivery of cash or other assets by a lender to a borrower in return for a promise to repay on a specified date or dates, or on demand. They are initially recognized at fair value plus transaction costs that are directly attributable to their acquisition or issue and subsequently carried at amortized cost, using the effective interest rate method, less any impairment losses. Amortized cost is calculated taking into account any discount or premium on acquisition and includes fees that are an integral part of the effective interest rate and transaction costs. Gains and losses are recognized in profit or loss when the loans and receivables are derecognized or impaired, as well as through the amortization process. The Company’s loans and receivables comprise cash and cash equivalents and accounts and other receivables.

Held-to-maturity investments

Held to maturity investments are initially measured at fair value and are subsequently measured at amortized cost using the effective interest rate method, less any impairment losses. The Company does not currently have any held-to-maturity investments.

Available-for-sale assets

Available-for-sale assets are measured at fair value, with unrealized gains and losses recorded in other comprehensive income (loss) until the asset is realized or impairment is viewed as other than temporary, at which time they will be recorded in profit or loss. The Company does not currently have any available-for-sale assets.

Financial assets at fair value through profit or loss

An instrument is classified at fair value through profit or loss if it is held for trading or is designated as such upon initial recognition. Financial instruments are designated at fair value through profit or loss if the Company manages such investments and makes purchase and sale decisions based on their fair value in accordance with the Company’s risk management or investment strategy. Upon initial recognition, attributable transaction costs are recognized in profit or loss when incurred. Financial instruments at fair value through profit or loss are measured at fair value, and changes therein are recognized in profit or loss. The Company does not have any financial assets at fair value through profit or loss.

Financial liabilities

Financial liabilities are classified as either fair value through profit or loss or other financial liabilities, based on the purpose for which the liability was incurred.

The Company’s other financial liabilities comprise accounts payable and accrued liabilities, line of credit and financial contract liabilities. These liabilities are initially recognized at fair value, net of any transaction costs directly attributable to the issuance of the instrument and subsequently carried at amortized cost using the effective interest rate method, which ensures that any interest expense over the period of repayment is at a constant rate on the balance of the liability carried in the balance sheet. Interest expense in this context includes initial transaction costs and premiums payable on redemption, as well as any interest or coupon payable while the liability is outstanding. Any revision to the amount or timing of cash flows related to an instrument is reflected in its carrying amount by computing the present value of the revised cash flows at the instrument’s initial effective interest rate. The change in carrying amount is reflected in profit or loss of the period. Accounts payable represent liabilities for goods and services provided to the Company prior to the end of the period which are unpaid. Trade payable amounts are unsecured and are usually paid within 30 days from receipt of invoice.

Financial liabilities are classified as held-for-trading if they are acquired for the purpose of selling in the near term. Derivatives are also categorized as held for trading unless they are designated as hedges.

F-14



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(i)    Financial instruments (continued)

The Company has derivative financial instruments in the form of warrants issued in US dollars and contracts entered into to manage its exposure to volatility in commodity prices. Commodity contracts are not used for trading or other speculative purposes. Such derivative financial instruments are initially recognized at fair value at the date at which the derivatives are issued and are subsequently re-measured at fair value. These derivatives do not qualify for hedge accounting and changes in fair value are recognized immediately in profit and loss.

For outstanding warrants at each reporting period, the liability change between reporting periods is recorded in the consolidated statement of comprehensive income (loss). As warrants are exercised, immediately before exercise, the liability on these exercised warrants is re-measured and the valuation change is recorded in the consolidated statement of comprehensive income (loss). Upon exercise, the re-measured warrant liability on these exercised warrants is eliminated and there is an offsetting entry to share capital.

Financial instrument measurement

If the market value for a financial instrument is not an active market the Company establishes fair value by using a valuation technique. Valuation techniques include using recent arm’s length market transaction between knowledgeable, willing parties, if available, reference to the current fair value of another instrument that is substantially the same, discounted cash flow analysis and option pricing models. The fair value of a financial instrument will be based on one or more factors that may include the time value of money, credit risk, commodity prices, equity prices, volatility, servicing costs and other factors.

(j)    Impairment

Impairment of financial assets

At each reporting date, the Company assesses whether there is objective evidence that a financial asset is impaired. If such evidence exists, the Company recognizes an impairment loss, as follows:

Financial assets carried at amortized cost: The loss is the difference between the amortized cost of the loan or receivable and the present value of the estimated future cash flows, discounted using the instrument’s original effective interest rate. The carrying amount of the asset is reduced by this amount either directly or indirectly through the use of an allowance account.

Impairment losses on financial assets carried at amortized cost are reversed in subsequent periods if the amount of the loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognized.

Non-financial assets

For the purpose of impairment testing, assets are grouped together in CGUs, which are the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets. The carrying value of long-term assets is reviewed at each period for indicators that the carrying value of an asset or a CGU may not be recoverable. The Company uses geographical proximity, geological similarities, analysis of shared infrastructure, commodity type, assessment of exposure to market risks and materiality to define its CGUs. If indicators of impairment exist, the recoverable amount of the asset or CGU is estimated. If the carrying value of the asset or CGU exceeds the recoverable amount, the asset or CGU is written down with an impairment recognized in profit or loss.

The recoverable amount of an asset or CGU is the greater of its value in use and its fair value less costs to sell. Fair value is determined to be the amount for which the asset could be sold in an arm’s length transaction. For resource properties, fair value less costs to sell may be determined by using discounted future net cash flows of proved and probable reserves using forecast prices and costs. Value in use is determined by estimating the net present value of future net cash flows expected from the continued use of the asset or CGU. Refer to note 3(d) for more details.

F-15



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(j)    Impairment (continued)

Impairment losses recognized in prior years are assessed at each reporting date for any indication that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimate used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had been recognized.

(k)    Taxes

Income taxes

Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

Deferred tax is recognized for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on temporary differences on the initial recognition of assets or liabilities in a transaction that is not a business combination and affects neither accounting profit nor taxable profit. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when the asset is realized or the liability is settled, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, when they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.

A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

Production taxes

Royalties, resource rent taxes and revenue-based taxes are accounted for under International Accounting Standards (‘IAS’) 12 when they have characteristics of an income tax. This is considered to be the case when they are imposed under Government authority and the amount is payable based on taxable income, rather than based on quantity produced or as a percentage of revenue, after adjustment for temporary differences. For such arrangements, current and deferred tax is provided on the same basis as described above for other forms of taxation. Obligations arising from royalty arrangements that do not satisfy these criteria are recognized as a reduction of revenues.

(l)    Share capital

The Company’s common shares, stock options, share purchase warrants and flow-through shares are classified as equity instruments only to the extent that they do not meet the definition of a financial liability or financial asset. Incremental costs directly attributable to the issue of equity instruments are shown in equity as a deduction, net of tax, from the proceeds.

F-16



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(m)    Flow-through shares

The Company will from time to time, issue flow-through common shares to finance a significant portion of its exploration program. Pursuant to the terms of the flow-through share agreements, these shares transfer the tax deductibility of qualifying resource expenditures to investors. On issuance, the Company separates the flow-through share into i) a flow-through share premium, equal to the estimated premium, if any, investors pay for the flow-through feature, which is recognized as a liability and; ii) share capital. Upon expenditures being incurred, the Company derecognizes the liability and recognizes a deferred tax liability for the amount of tax reduction renounced to the shareholders. The premium is recognized as deferred income tax recovery and the related deferred tax is recognized as a tax provision. To the extent that the Company has available tax pools for which the benefit has not been previously recognized, that are probable to be utilized, a deferred income tax recovery is recognized at the time of renunciation of the tax pools. The Company may also be subject to a Part XII.6 tax on flow-through proceeds renounced under the Look-back Rule, in accordance with Government of Canada flow-through regulations. When applicable, this tax is accrued as a financial expense until paid.

(n)    Borrowing costs

Borrowing costs directly associated with the acquisition, construction or production of a qualifying asset are capitalized when a substantial period of time is required to make the asset ready for its intended use. To the extent general borrowings are used for the purpose of obtaining a qualifying asset, the related costs are capitalized based on the weighted average of the borrowing costs applicable to the total outstanding borrowings in the period other than those made specifically for the purpose of the acquisition, construction or production of a qualifying asset. All other borrowing costs are recognized as an expense in the period in which they are incurred.

(o)    Changes in accounting policies

The Company has adopted the following new and revised standards, along with all consequential amendments, effective January 1, 2013. These changes are made in accordance with the applicable transitional provisions.

IFRS 10, Consolidated Financial Statements, replaces the guidance on control and consolidation in IAS 27, Consolidated and Separate Financial Statements, and SIC–12, Consolidation – Special Purpose Entities. The new standard eliminates the current risk and rewards approach and establishes control as the single basis for determining the consolidation of an entity. The Corporation assessed its consolidation conclusions on January 1, 2013 and determined that the adoption of IFRS 10 did not result in any change in the consolidation status of its wholly–owned subsidiaries, Dejour USA, DEAL, Wild Horse, and 0855524 B.C. Ltd.

IFRS 11, Joint Arrangements, supersedes IAS 31, Interests in Joint Ventures, and requires joint arrangements to be classified either as joint operations or joint ventures depending on the contractual rights and obligations of each investor that jointly controls the arrangement. For joint operations, a company recognizes its share of assets, liabilities, revenues and expenses of the joint operation. An investment in a joint venture is accounted for using the equity method as set out in IAS 28, Investments in Associates and Joint Ventures (amended in 2011). The other amendments to IAS 28 did not affect the Company. The Company classified its joint arrangements in accordance with IFRS 11 on January 1, 2013 and concluded that the adoption of the standard did not result in any changes in the accounting for its joint arrangements.

IFRS 12, Disclosure of Interests in Other Entities, combines in a single standard the disclosure requirements for subsidiaries, associates and joint arrangements, as well as unconsolidated structured entities. The adoption of the standard did not impact the disclosures in the Company’s financial statements.

IFRS 13, Fair Value Measurement, provides a consistent definition of fair value and introduces consistent requirements for disclosures related to fair value measurement. There has been no change to the Company’s methodology for determining the fair value for its financial assets and liabilities and, as such, the adoption of IFRS 13 did not result in any measurement adjustments as at January 1, 2013.

F-17



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

(p)    Future accounting pronouncements

Certain pronouncements were issued by “IASB” or “IFRIC” that are mandatory for accounting periods beginning after January 1, 2014 or later periods.

The following new standards, amendments and interpretations, have not been early adopted in these consolidated annual financial statements. The Company is currently assessing the impact, if any, of this new guidance on the Company’s future results and financial position:

IFRS 9, Financial Instruments is part of the IASB's wider project to replace IAS 39 Financial Instruments: Recognition and Measurement. IFRS 9 retains but simplifies the mixed measurement model and establishes two primary measurement categories for financial assets: amortized cost and fair value. The basis of classification depends on the entity's business model and the contractual cash flow characteristics of the financial asset. The amendments to IFRS 9 will be effective as of January 1, 2018. The Company will continue to monitor the changes to this standard as they arise and will determine the impact accordingly.

IAS 36, Impairment of Assets was amended in May 2013. This standard reduces the circumstances in which the recoverable amount of CGUs is required to be disclosed and clarify the disclosures required when an impairment loss has been recognized or reversed in the period. The amendments to IAS 36 are effective as of January 1, 2014.

NOTE 4 - CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS

The Company makes estimates and assumptions about the future that affect the reported amounts of assets and liabilities. Estimates and judgments are continually evaluated based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. In the future, actual experience may differ from these estimates and assumptions.

The effect of a change in an accounting estimate is recognized prospectively by including it in profit or loss in the period of the change, if the change affects that period only; or in the period of the change and future periods, if the change affects both.

Information about critical judgments in applying accounting policies that have the most significant risk of causing material adjustment to the carrying amounts of assets and liabilities recognized in the consolidated annual financial statements within the next financial year are discussed below:

Decommissioning liability

Decommissioning liabilities have been recognized based on the Company’s internal estimates. Assumptions, based on the current economic environment, have been made which management believes are a reasonable basis upon which to estimate the future liability. These estimates take into account any material changes to the assumptions that occur when reviewed regularly by management. Estimates are reviewed at least annually and are based on current regulatory requirements. Significant changes in estimates of contamination and restoration techniques will result in changes to provisions from period to period. Actual decommissioning costs will ultimately depend on future market prices for the decommissioning costs which will reflect the market conditions at the time the decommissioning costs are actually incurred. The final cost of the currently recognized decommissioning provisions may be higher or lower than currently provided for.

F-18



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 4 - CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS (continued)

Exploration and evaluation expenditure

The application of the Company’s accounting policy for exploration and evaluation expenditure requires judgment in determining whether it is likely that future economic benefits will flow to the Company, which is based on assumptions about future events or circumstances. Estimates and assumptions made may change if new information becomes available. If, after the expenditure is capitalized, information becomes available suggesting that the recovery of the expenditure is unlikely, the amount capitalized is written off in profit or loss in the period the new information becomes available.

Income taxes

The Company recognizes the net future tax benefit related to deferred tax assets to the extent that it is probable that the deductible temporary differences will reverse in the foreseeable future. Assessing the recoverability of deferred tax assets requires the Company to make significant estimates related to expectations of future taxable income. Estimates of future taxable income are based on forecast cash flows from operations and the application of existing tax laws in each jurisdiction. To the extent that future cash flows and taxable income differ significantly from estimates, the ability of the Company to realize the net deferred tax assets recorded at the reporting date could be impacted. Additionally, future changes in tax laws in the jurisdictions in which the Company operates could limit the ability of the Company to obtain tax deductions in future periods. All tax filings are subject to audit and potential reassessment. Accordingly, the actual income tax liability may differ significantly from the estimated and recorded amounts.

Share-based payment transactions

The Company measures the cost of equity-settled transactions with employees by reference to the fair value of the equity instruments at the date at which they are granted. Estimating fair value for share-based payment transactions requires determining the most appropriate valuation model, which is dependent on the terms and conditions of the grant. This estimate also requires determining the most appropriate inputs to the valuation model including the expected life of the share option, volatility and dividend yield.

Financial contract liability

The application of the Company’s accounting policy for financial liabilities requires the Company to adjust the carrying amounts of the financial liabilities in the event it revises its payments or receipts to reflect actual and revised estimated cash flows. The Company’s financial contract liability was originally recognized at fair value using the effective interest method which ensures that any interest expense over the period of repayment is at a constant rate on the balance of the liability carried in the balance sheet.

At December 31, 2013, the balance of the financial contract liability was revised to reflect actual and revised estimated cash flows resulting in a gain in financial contract liability of $1,268,000. The revisions to the actual and revised cash flows resulted from i) downward revisions in estimated future net revenue from the 2013 sale of ethane in Dejour USA due to poor market conditions; ii) delays in the commencement of 2013 drilling operations in Dejour USA, and iii) an industry-standard, interim natural gas marketing contract in Dejour USA which failed to credit the Company with full natural gas liquids recoveries for 2013.

Despite the reduction in the carrying value of the financial contract liability at December 31, 2013, the corresponding asset on the Company’s balance sheet required no related charge for impairment. This resulted from a successful 2013 drilling program which converted 47 “probable” drilling locations at December 31, 2012 to “proven” as at December 31, 2013 – Note 12.

F-19



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 4 - CRITICAL ACCOUNTING ESTIMATES AND JUDGMENTS (continued)

Impairment

A CGU is defined as the lowest grouping of integrated assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The allocation of assets into CGUs requires significant judgment and interpretations with respect to the integration between assets, the existence of active markets, similar exposure to market risks, shared infrastructures, and the way in which management monitors the operations. The recoverable amounts of CGUs and individual assets have been determined based on the higher of fair value less costs to sell or value-in-use calculations. The key assumptions the Company uses in estimating future cash flows for recoverable amounts are anticipated future commodity prices, expected production volumes and future operating and development costs. Changes to these assumptions will affect the recoverable amounts of CGUs and individual assets and may then require a material adjustment to their related carrying value. At December 31, 2013, the Company has two CGUs in Canada (Drake/Woodrush and Saddle Hills) and one CGU in the United States (Kokopelli) – Note 6.

Financial instrument

When estimating the fair value of financial instruments, the Company uses third-party models and valuation methodologies that utilize observable market data. In addition to market information, the Company incorporates transaction specific details that market participants would utilize in a fair value measurement, including the impact of non-performance risk.

Reserves

The estimate of reserves is used in forecasting the recoverability and economic viability of the Company’s oil and gas properties, and in the depletion and impairment calculations. The process of estimating reserves is complex and requires significant interpretation and judgment. It is affected by economic conditions, production, operating and development activities, and is performed using available geological, geophysical, engineering, and economic data. Reserves are evaluated at least annually by the Company’s independent reserve evaluators and updates to those reserves, if any, are estimated internally. Future development costs are estimated using assumptions as to the number of wells required to produce the commercial reserves, the cost of such wells and associated production facilities and other capital costs.

NOTE 5 – EXPLORATION AND EVALUATION (“E&E”) ASSETS

    Canadian     Canadian Oil     United States        
    Uranium     and Gas     Oil and Gas        
    Properties     Interests     Interests     Total  
    $     $     $     $  
Cost:                        
Balance at January 1, 2012   533     72     27,772     28,377  
Additions   -     2     315     317  
Change in decommissioning provision   -     (23 )   -     (23 )
Disposals   -     -     (2,132 )   (2,132 )
Foreign currency translation and other   -     (28 )   (492 )   (520 )
Balance at December 31, 2012   533     23     25,463     26,019  
Additions   -     10     134     144  
Change in decommissioning provision   -     37     -     37  
Disposals   (533 )   -     (8,930 )   (9,463 )
Foreign currency translation and other   -     -     1,631     1,631  
Balance at December 31, 2013   -     70     18,298     18,368  

F-20



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 5 – EXPLORATION AND EVALUATION (“E&E”) ASSETS (continued)

    Canadian     Canadian Oil     United States        
    Uranium     and Gas     Oil and Gas        
    Properties     Interests     Interests     Total  
    $     $     $     $  
Accumulated impairment losses:                        
Balance at January 1, 2012   (10 )   -     (23,084 )   (23,094 )
Impairment losses   (261 )   -     (1,245 )   (1,506 )
Disposals   -     -     2,083     2,083  
Foreign currency translation and other   -     -     388     388  
Balance at December 31, 2012   (271 )   -     (21,858 )   (22,129 )
Impairment losses (Note 7)   (132 )   -     (415 )   (547 )
Disposals   403     -     8,557     8,960  
Foreign currency translation and other   -     -     (1,371 )   (1,371 )
Balance at December 31, 2013   -     -     (15,087 )   (15,087 )

    Canadian     Canadian Oil     United States        
    Uranium     and Gas     Oil and Gas        
    Properties     Interests     Interests     Total  
    $     $     $     $  
Carrying amounts:                        
At December 31, 2012   262     23     3,605     3,890  
At December 31, 2013   -     70     3,211     3,281  

Exploration and evaluation (“E&E”) assets consist of the Company’s exploration projects which are pending the determination of proven reserves.

During the year ended December 31, 2013, the Company sold its interests in all uranium exploration leases to unrelated third parties for gross proceeds of $150,000.

United States Exploration and Evaluation Properties

As at December 31, 2013, the Company holds oil and gas leases in the Piceance, Paradox and Uinta Basins in the US Rocky Mountains, of which a portion was classified as E&E assets.

During the year ended December 31, 2013, the Company sold its working interests in certain oil and gas leases in the areas of Colorado and Utah to unrelated third parties for gross proceeds of $134,000 (US$129,000).

During the year ended December 31, 2013, the Company capitalized $79,000 (December 31, 2012 – $104,000) of general and administrative costs related to its US oil and gas interests.

The E&E asset impairment is $415,000, $1,245,000 and $4,886,000 for the year ended December 31, 2013, December 31, 2012 and December 31 2011, respectively. The impairment was recognized upon a review of each exploration license or field, carried out, at least annually, to confirm whether the Company intends further appraisal activity or to otherwise extract value from the property. The impairment was recognized based on the difference between the carrying value of the assets and their recoverable amounts. The recoverable amount was the higher of fair value less costs to sell or value in use. The fair value was estimated based on comparable market prices for which the asset could be sold in an arm’s length transaction less estimated costs to sell. There was no recoverable amount on expired leases.

F-21



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 6 – PROPERTY AND EQUIPMENT

    Canadian Oil     United States              
    and Gas     Oil and Gas     Corporate and        
    Interests     Interests     Other Assets     Total  
    $     $     $     $  
Cost:                        
Balance at January 1, 2012   23,149     4,076     326     27,551  
Additions   1,420     9,075     7     10,502  
Change in decommissioning provision   131     (1 )   -     130  
Disposals   -     -     (17 )   (17 )
Foreign currency translation and other   -     (74 )   (2 )   (76 )
Balance at December 31, 2012   24,700     13,076     314     38,090  
Additions   21     2,206     7     2,234  
Change in decommissioning provision   (171 )   23     -     (148 )
Disposals   -     (1,902 )   -     (1,902 )
Foreign currency translation and other   -     876     4     880  
Balance at December 31, 2013   24,550     14,279     325     39,154  

    Canadian Oil     United States              
    and Gas     Oil and Gas     Corporate and        
    Interests     Interests     Other Assets     Total  
    $     $     $     $  
Accumulated amortization, depletion and impairment                        
losses:                        
Balance at January 1, 2012   (7,118 )   (440 )   (233 )   (7,791 )
Amortization and depletion   (2,737 )   -     (29 )   (2,766 )
Impairment losses   (4,913 )   (1,491 )   -     (6,404 )
Disposals   -     -     10     10  
Foreign currency translation and other   -     4     1     5  
Balance at December 31, 2012   (14,768 )   (1,927 )   (251 )   (16,946 )
Amortization and depletion (Note 7)   (2,036 )   (493 )   (25 )   (2,554 )
Impairment losses (Note 7)   (529 )   -     -     (529 )
Disposals   -     1,318     -     1,318  
Foreign currency translation and other   -     (55 )   (2 )   (57 )
Balance at December 31, 2013   (17,333 )   (1,157 )   (278 )   (18,768 )

    Canadian Oil     United States              
    and Gas     Oil and Gas     Corporate and        
    Interests     Interests     Other Assets     Total  
    $     $     $     $  
Carrying amounts:                        
At December 31, 2012   9,932     11,149     63     21,144  
At December 31, 2013   7,217     13,122     47     20,386  

F-22



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 6 – PROPERTY AND EQUIPMENT (continued)

Canadian Oil and Gas Interests

At December 31, 2013, the Company had 5 property leases held on its behalf by a third party.

Amortization and depletion is computed using the unit of production method by reference to the total production for the CGU over the estimated net proved and probable reserves of oil and gas for the CGU determined by independent consultants. The calculation of amortization and depletion for the year ended December 31, 2013 included estimated future development costs of $899,000 (December 31, 2012 - $Nil; December 31, 2011 - $Nil) associated with the development of proved undeveloped reserves.

During the year ended December 31, 2013, the Company capitalized $Nil (December 31, 2012 – $2,000) of general and administrative costs related to its Canadian oil and gas interests.

At December 31, 2013, the Company performed an impairment test on certain oil and gas interests to assess the recoverable value of these properties when indicators of impairment were present.

The Developed and Proved (D&P) asset impairment is $529,000, $4,913,000 and $938,000 for the year ended December 31, 2013, December 31, 2012 and December 31, 2011, respectively. The impairment was recognized because the carrying value of certain CGU exceeded the recoverable amount. The impairment was recognized based on the difference between the carrying value of cash generating unit and their recoverable amounts. The recoverable amount was the higher of fair value less costs to sell or value in use. The fair value was estimated based on observable market prices for which the asset could be sold in a comparable arm’s length transaction, less estimated costs to sell. Recoverable amount was the fair value less costs to sell determined using cash flows attributed to the proved and probable reserves, discounted at 10%, adjusted for assumptions that an independent market participant may take into account (Note 23).

The benchmark prices on which the December 31, 2013 impairment indicators were assessed are as follows:

  Natural gas Condensate Crude oil
  (AECO) (Edmonton Pentanes Plus) (Edmonton Par)
  Cdn $ / mmbtu Cdn $ / bbl Cdn $ / bbl
2014 4.03 105.20 92.76
2015 4.26 107.11 97.37
2016 4.50 107.00 100.00
2017 4.74 107.00 100.00
2018 4.97 107.00 100.00
2019 5.21 107.00 100.00
2020 5.33 107.82 100.77
2021 5.44 109.97 102.78
2022 5.55 112.17 104.83
2023 5.66 114.41 106.93
Each benchmark price increased on average approximately 2% from 2014 and thereafter  

United States Oil and Gas Interests

Amortization and depletion is computed using the unit of production method by reference to the total production for the CGU over the estimated net proved and probable reserves of oil and gas for the CGU determined by independent consultants. The calculation of amortization and depletion for the year ended December 31, 2013 included estimated future development costs of $258.8 million (December 31, 2012 - $326.9 million) associated with the development of proved undeveloped reserves. During fiscal 2012, the Company did not have any production from its US oil and gas interests and accordingly did not deplete any of its US oil and gas interests.

F-23



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 6 – PROPERTY AND EQUIPMENT (continued)

During the year ended December 31, 2013, the Company sold its working interests in certain oil and gas leases in the area of Colorado to a related third party for gross proceeds of $477,000 (US$450,000) – Note 17(f).

During the year ended December 31, 2013, the Company capitalized $520,000 (December 31, 2012 – $539,000) of general and administrative costs related to its US oil and gas interests.

The D&P asset impairment is $Nil, $1,491,000 and $424,000 for the year ended December 31, 2013, December 31, 2012 and December 31, 2011, respectively. Of the $1.5 million impairment recorded for the year ended December 31, 2012, $1.3 million was related to South Rangely property that was disposed in December 2013. The impairment was recognized upon a review of each exploration license or field, carried out, at least annually, to confirm whether the Company intends further appraisal activity or to otherwise extract value from the property. The impairment was recognized based on the difference between the carrying value of the assets and their recoverable amounts. The recoverable amount was the higher of fair value less costs to sell or value in use. Recoverable amount was the fair value less costs to sell determined using cash flows attributed to the proved and probable reserves, discounted at 10%, adjusted for assumptions that an independent market participant may take into account (Note 23).

The benchmark prices on which the December 31, 2013 impairment indicators were assessed are as follows:

  Natural gas
  (Henry Hub)
  US$ / mmbtu
2014 4.38
2015 4.15
2016 4.00
2017 3.98
2018 4.20
2019 4.32
2020 4.49
2021 4.63
2022 4.77
2023 4.91
2024 5.06
2025 5.25
2026 and thereafter 5.49

* At December 31, 2013, the US$ to CAD$ exchange rate was 1.0636.

NOTE 7 – AMORTIZATION, DEPLETION AND IMPAIRMENT LOSSES

    Year ended December 31  
    2013     2012     2011  
    $     $     $  
Exploration and Evaluation Assets (E & E assets)                  
       Impairment losses (Note 5)   547     1,506     4,886  
                   
Property and Equipment (D & P assets)                  
       Amortization and depletion (Note 6)   2,554     2,766     2,404  
       Impairment losses (Note 6)   529     6,404     1,362  
    3,630     10,676     8,652  

F-24



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 8 – BANK LINE OF CREDIT

On March 28, 2013, DEAL signed a new agreement with the Bank to renew its $5.95 million (December 31, 2012 - $6.0 million) revolving operating demand loan under the following terms and conditions:

(a)

Credit Facility “A” – Revolving Operating Demand Loan - $3.7 million, to be used for general corporate purposes, ongoing operations, capital expenditures, and acquisition of additional petroleum and natural gas assets. Interest on Credit Facility “A” is at Prime + 1% payable monthly and all amounts outstanding are payable on demand any time, and

   
(b)

Credit Facility “B” – Non-Revolving Demand Loan - $2.25 million. Interest on Credit Facility “B” is at Prime + 3 1/2% payable monthly. Monthly principal payments of $200,000 are due and payable commencing March 26, 2013 with all amounts outstanding under Credit Facility “B” ($1.45 million) due and payable in full on June 30, 2013.

Collateral for Credit Facilities “A” and “B” (the “Credit Facilities”) is provided by a $10.0 million first floating charge over all the assets of DEAL, a general assignment of DEAL’s book debts, a $10.0 million debenture with a first floating charge over all the assets of the Company and an unlimited guarantee provided by Dejour USA. On June 5, 2013, DEAL renewed the Credit Facilities with the Bank and the maximum amount of Credit Facility “A” was reduced to $3.5 million. On June 19, 2013, Credit Facility “B” was repaid in full (note 10). Further, on December 16, 2013 and amended on February 18, 2014, DEAL renewed the Credit Facility “A” with the Bank and contracted to utilize $600,000 of the $3.5 million to fund the proposed acquisition of certain producing natural gas properties in Canada until March 31, 2014. If the proposed acquisition fails to close for whatever reason by March 31, 2014, the maximum amount of Credit Facility “A” will be reduced by $300,000 effective April 1, 2014. Monthly principal payments of $100,000 are still due and payable commencing March 1, 2014. The next annual review is scheduled on or before May 1, 2014.

Under the terms of the Credit Facilities, DEAL is required to maintain a working capital ratio of greater than 1:1 at all times. The working capital ratio is defined as the ratio of (i) current assets (including any undrawn and authorized availability under the Credit Facilities) less unrealized hedging gains to (ii) current liabilities (excluding the current portion of outstanding balances of the facility) less unrealized hedging losses. As at December 31, 2013, DEAL was in compliance with its working capital ratio requirement.

NOTE 9 – WARRANT LIABILITY

Warrants that have their exercise prices denominated in currencies other than the Company’s functional currency of Canadian dollars, other than agents’ warrants, are accounted for as derivative financial liabilities. These warrants are recorded at the fair value at each reporting date with the change in fair value for the period recorded in profit orloss for the period.

    #     $  
             
Balance at January 1, 2011   8,075,000     1,093  
Granted, investor warrants   5,505,002     311  
Exercise of warrants – value reallocation   (3,460,418 )   (739 )
Change in fair value   -     1,580  
Balance at December 31, 2011   10,119,584     2,245  
Granted, investor warrants   13,597,729     1,308  
Exercise of warrants – value reallocation   (2,419,584 )   (286 )
Change in fair value   -     (1,842 )
Balance at December 31, 2012   21,297,729     1,425  
Change in fair value   -     (1,101 )
Balance at December 31, 2013   21,297,729     324  

F-25



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 9 – WARRANT LIABILITY (continued)

In June 2012, the Company issued 13,597,729 investor warrants each of which entitles the holder to purchase one common share of the Company at an exercise price of US$0.40 beginning 6 months from the date of issuance until June 4, 2017. The fair value of these granted investor warrants were estimated using the Hull-White Trinomial option pricing model under the following weighted average inputs:

    December 31,       December 31,                
As at   2013     2012     June 4, 2012  
                                     
Exercise price   US$     0.40     US$     0.40     US$     0.40  
Share price   US$     0.12     US$     0.22     US$     0.24  
Expected volatility         70%           85%           91%  
Expected life         2.55 years           3.55 years           5 year  
Dividends         0.0%           0.0%           0.0%  
Risk-free interest rate         0.7%           0.5%           0.7%  

During the year ended December 31, 2013, none of the US$ warrants were exercised (December 31, 2012 – 2,419,584).

NOTE 10 – LOAN FACILITY

On June 19, 2013, the Company borrowed $3.5 million (“Loan Facility”) from a Canadian institutional lender (“Lender”). The Loan Facility bears interest at 14%, payable monthly, and matures on December 14, 2014. The principal is repayable any time after December 18, 2013 without penalty. Related financing costs of $348,000 have been deducted in determining the fair value of the Loan Facility and certain incentive share purchase warrants (“Warrant” or “Warrants”) issued to the Lender. Security for the Loan Facility is comprised of a First Deed of Trust on certain of the Company’s U.S. oil and gas interests, including a general security agreement, a second mortgage on the Company’s Canadian properties, and the guaranty of the Company and Dejour USA.

As partial consideration for providing the Loan Facility, the Company issued the Lender 7,291,667 Warrants. Each Warrant entitles the holder to acquire one common share at a price of $0.24 per share any time prior to June 18, 2015. If the Company issues any common shares at a price per share less than $0.24 (the “Issue Price”) any time until December 18, 2013, then the exercise price of the Warrants would automatically be reduced to the higher of (i) the Issue Price and (ii) $0.20. Shares acquired through the exercise of Warrants prior to October 18, 2013 are restricted from sale through the facilities of the Canadian stock exchange.

The Company has determined the Loan Facility as being a financial liability with an embedded derivative liability. Therefore, the embedded derivative liability is measured first and the residual value is assigned to the financial liability. On initial recognition, the fair value of the derivative liability of $551,000 was estimated using an option pricing model.

The residual value assigned to the financial liability of $2,949,000 at initial recognition was the fair value of the entire transaction ($3.5 million) less the value assigned to the embedded derivative liability ($551,000). Related financing costs of $348,000 were apportioned to the financial liability and the embedded derivative liability. The portion attributed to the embedded derivative of $54,000 was expensed immediately and the remainder of the costs were deducted from the carrying amount of the financial liability and will be amortized over the term of the liability.

F-26



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 10 – LOAN FACILITY (continued)

At initial recognition, the carrying value of the financial liability was as follows:

    Fair Value     Financing Costs     Carrying Value  
    $     $     $  
Financial liability   2,949     (294 )   2,655  
Derivative liability   551         551  
    3,500     (294 )   3,206  

The derivative liability is carried at fair value through profit and loss and the instrument is re-measured at each reporting date using an option pricing model. For the year ended December 31, 2013, the Company recorded an unrealized gain on the derivative liability of $264,000 (year ended December 31, 2012 - $Nil). The following key inputs to obtain the valuation:

As at   December 31, 2013     June 18, 2013  
Exercise price $  0.24   $  0.24  
Share price $  0.15   $  0.20  
Expected volatility   84%     79%  
Expected life   1.5 years     2 years  
Dividends   0.0%     0.0%  
Risk-free interest rate   1.1%     1.1%  

As at December 31, 2013, the carrying value of the financial liability is:

    December 31,     December 31,  
    2013     2012  
    $     $  
Balance upon initial recognition   2,655     -  
Accretion expense   494     -  
Interest paid   (238 )   -  
Balance at December 31, 2013   2,911     -  

Accretion expense of $494,000 (year ended December 31, 2012 – $Nil) is included in financing expenses. Other terms and conditions of the Loan Facility are:

(a)

Commencing September 30, 2013, Dejour USA is required to maintain a working capital ratio of greater than 1:1, as defined, at all times. The working capital ratio is defined as the ratio of (i) current assets to (ii) current liabilities (excluding any liability pursuant to the Drilling Fund – Note 12);

(b)

Restrictions on borrowings; and

(c)

No changes to the Company’s senior management team without the Lender’s written consent.

At December 31, 2013, Dejour USA was in default of its working capital ratio covenant. As a result, the loan facility is due upon demand and classified as current liabilities. The Lender has not demanded repayment as at December 31, 2013.

F-27



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 11 – DECOMMISSIONING LIABILITY

    Canadian     United States        
    Oil and Gas     Oil and Gas        
   

Properties (1)

    Properties (1)     Total  
    $     $     $  
Balance at January 1, 2012   1,217     122     1,339  
Change in estimated future cash flows   107     -     107  
Disposals   (34 )   -     (34 )
Actual costs incurred and other   (4 )   (3 )   (7 )
Unwinding of discount   22     2     24  
Balance at December 31, 2012   1,308     121     1,429  
Change in estimated future cash flows   (134 )   23     (111 )
Disposals   -     (35 )   (35 )
Actual costs incurred   (112 )   8     (104 )
Unwinding of discount   30     3     33  
Balance at December 31, 2013   1,092     120     1,212  

(1) relates to property and equipment (note 6)

The present value of the decommissioning liability was calculated using the following weighted average inputs:

  Canadian Oil United States
  and Gas Oil and Gas
  Properties Properties
As at December 31, 2013:    
Discount rate                  2.55% 2.72%
Inflation rate                  2.00% 2.00%
     
As at December 31, 2012:    
Discount rate                  1.72% 1.82%
Inflation rate                  2.50% 2.50%

NOTE 12 – FINANCIAL CONTRACT LIABILITY

On December 31, 2012, Dejour USA entered into a financial contract with a U.S. oil and gas drilling fund (“Drilling Fund”), that is associated through a relationship with a former director of the Company, to drill up to three wells and complete up to four wells (“the Tranche 1 Wells”) in the State of Colorado. By agreement:

(a)

Dejour USA contributed four natural gas well spacing units, including one drilled and cased well with a cost of US$1.1 million;

   
(b)

The Drilling Fund contributed US$6.5 million cash directly to a drilling company, that is owned by a former consultant of Dejour USA, as prepaid drilling costs; during the year ended December 31, 2013, the Drilling Fund also committed to invest a further US$500,000 in the four wells for a total of US$7.0 million. As at December 31, 2013, US$417,000 of the incremental US$500,000 has been invested for a total of US$6.9 million;

   
(c)

Dejour USA will earn a “before payout” working interest of 10% to 14% and an “after payout” working interest of 28% to 39% in the net operating profits from the Tranche 1 Wells based on the actual cash invested in the drilling program; in September 2013, Dejour USA signed an amendment with the Drilling Fund and agreed to earn the revised “before payout” working interest of 15.88% to 22.23% and revised “after payout” working interest of 29.77% to 41.67% in the net operating profits from the Tranche 1 Wells based on the actual cash invested in the drilling program;

F-28



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 12 – FINANCIAL CONTRACT LIABILITY (continued)

(d)

The Drilling Fund has the right to require that Dejour USA purchase the Drilling Fund’s entire working interest in the Tranche 1 Wells 36 months after the commencement of production from the initial Tranche 1 Wells. In the event the Drilling Fund exercises its right, the purchase price to be paid by Dejour USA will equal 75% of the Drilling Fund’s actual investment less 75% of the Drilling Fund’s share of working interest net profits from the Tranche 1 Wells, if any, for the 36-month period, plus a “top-up” amount so that the Drilling Fund earns a minimum 8% return, compounded annually and applied on a monthly basis, on 75% of its original investment over the 36-month period; and

   
(e)

The Drilling Fund has the right to require Dejour USA to purchase all of the Drilling Fund’s interest in the Tranche 1 Wells if at any time Dejour USA plans to divest itself of greater than 51% of its Working Interest in the Tranche 1 Wells and resigns as Operator (a “Change of Control Event”). The purchase price is equal to the future net profit from the “Proven and Probable Reserves” attributable to the Drilling Funds working interest in the Tranche 1 Wells, discounted at 12%, as determined by a third party evaluator acceptable to both parties.

Dejour USA considers the transaction to be a financial contract liability as the risks and rewards of ownership have not been substantially transferred at the Agreement date. On the Drilling Fund financing advance, the Company increased property and equipment and financial contract liability by $6.5 million (US$6.5 million). During the year ended December 31, 2013, the Company increased property and equipment and financial contract liability by $443,000 (US$417,000) of the incremental US$500,000 advance received in the year. On initial recognition, the Company imputed its borrowing cost of 8.4% based on the estimated timing and amount of operating profit using the independent reserve engineer’s estimated future cash flows for the Drilling Funds working interest in the Tranche 1 Wells. Subsequent to initial measurement the financial contract liability will be increased by the imputed interest expense and decreased by the Drilling Fund’s net operating profit from the Tranche 1 Wells. Any changes in the estimated timing and amount of the net operating profit cash flows will be discounted at the initial imputed interest rate with any change in the recognized liability recognized as a gain (loss) in the period of change – Note 4. The Company has estimated the current portion of the obligation based on the expected net operating profit to be paid to the Drilling Fund in the next twelve months.

    $  
Loan advance at December 31, 2012 (US$6,500)   6,467  
Loan advance during the year (US$417)   443  
Accretion expense (US$471)   486  
Foreign exchange loss   461  
    7,857  
Less:      
(a)    Net operating income (US$441 paid in 2013)   (468 )
(b)    Gain on financial contract liability (US$1,192)   (1,268 )
Balance at December 31, 2013 (US$5,755)   6,121  
Current portion of financial contract liability (US$1,173)   (1,248 )
Non-current portion of financial contract liability (US$4,582)   4,873  

The reduction in the financial contract liability is estimated to be:

    US$     CAD$  
2014   1,173     1,248  
2015   412     438  
2016   4,170     4,435  

F-29



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 13 – SHARE CAPITAL

Authorized

The Company is authorized to issue an unlimited number of common voting shares, an unlimited number of first preferred shares issuable in series, and an unlimited number of second preferred shares issuable in series. No preferred shares have been issued and the terms of preferred shares have not been defined.

Issued and outstanding

          $value of  
    # of shares     shares  
Balance at January 1, 2011   110,180,545     79,386  
Issue of shares on exercise of warrants and options   4,751,841     1,574  
Warrant liability reallocated on exercise of warrants   -     739  
Contributed surplus reallocated on exercise of options   -     167  
Shares issued via private placements, net of issuance costs   11,010,000     2,694  
Subscriptions receivable on exercise of options   950,000     516  
Balance at December 31, 2011   126,892,386     85,076  
Issue of shares on exercise of warrants and options   3,893,683     1,466  
Warrant liability reallocated on exercise of warrants   -     286  
Contributed surplus reallocated on exercise of options   -     198  
Shares issued via private placements, net of issuance costs   18,130,305     3,248  
Balance at December 31, 2012 and 2013   148,916,374     90,274  

During the year ended December 31, 2012, the Company completed the following:

In June 2012, the Company completed a private placement of 18,130,305 units at US$0.26 per unit. Each unit consists of one common share and 3/4 of one common share purchase warrant. Each whole warrant entitles the holder to acquire one additional common share of the Company at US$0.40 per common share beginning 6 months from the date of issuance until June 4, 2017. Gross proceeds raised were $4,909,000 (US$4,714,000). In connection with this private placement, the Company paid finders’ fees of $295,000 (US$283,000) and other related costs of $187,000. The grant date fair value of the warrants, estimated to be $1,308,000, has been recognized as a derivative financial liability (Note 10). Issue costs of $129,000 related to the warrants were expensed.

During the year ended December 31, 2012, 2,968,683 warrants denominated in US dollars (including 549,099 agents’ warrants) were exercised with an average common share market price of US$0.47 and 925,000 stock options were exercised with an average common share market price of $0.51.

During the year ended December 31, 2011, the Company completed the following:

At December 31, 2011 the Company had subscriptions receivable in the amount of $516,000. The subscriptions receivable balance was received in full in January 2012.

In February 2011, the Company completed a private placement of 11,010,000 units at US$0.30 per unit. Each unit consists of one common share and one-half of one common share purchase warrant. Each whole warrant entitles the holder to acquire one additional common share of the Company at US$0.35 per common share on or before February 10, 2012. Gross proceeds raised were $3,289,000 (US$3,303,000). In connection with this private placement, the Company paid finders’ fees of $197,000 (US$200,000) and other related costs of $120,000. The grant date fair value of the warrants, estimated to be $311,000, has been recognized as a derivative financial liability (Note 9). Issue costs of $32,000 related to the warrants were expensed. Directors and Officers of the Company purchased 2,000,000 units of this offering.

In January 2011, the Company renounced $889,000 flow-through funds to investors, using the look-back rule. The flow-through funds had been fully spent by February 28, 2011. As a result of the renunciation, a deferred income tax recovery of $187,000 was recognized on settlement of the flow-through share liability.

F-30



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 14 – STOCK OPTIONS AND SHARE PURCHASE WARRANTS

(a)     Stock Options

The Stock Option Plan (the “Plan”) is a 10% “rolling” plan pursuant to which the number of common shares reserved for issuance is 10% of the Company’s issued and outstanding common shares as constituted on the date of any grant of options.

The Plan provides for the grant of options to purchase common shares to eligible directors, senior officers, employees and consultants of the Company (“Participants”). The exercise periods and vesting periods of options granted under the Plan are to be determined by the Company with approval from the Board of Directors. The expiration of any option will be accelerated if the participant’s employment or other relationship with the Company terminates. The exercise price of an option is to be set by the Company at the time of grant but shall not be lower than the market price (as defined in the Plan) at the time of grant.

The following table summarizes information about outstanding stock option transactions:

    Number of     Weighted average  
    options     exercise price  
          $  
Balance at January 1, 2011   6,946,500     0.40  
Options granted   3,212,500     0.35  
Options exercised   (1,150,000 )   0.35  
Options forfeited   (200,000 )   0.40  
Options expired   (305,000 )   0.45  
Balance at December 31, 2011   8,504,000     0.39  
Options granted   9,660,002     0.25  
Options exercised (Note 13)   (925,000 )   0.38  
Options cancelled   (2,335,001 )   0.43  
Options forfeited   (514,375 )   0.42  
Balance at December 31, 2012   14,389,626     0.29  
Options granted   3,750,000     0.18  
Options cancelled   (5,919,000 )   0.39  
Options forfeited   (1,598,125 )   0.30  
Balance at December 31, 2013   10,622,501     0.20  

Details of the outstanding and exercisable stock options as at December 31, 2013 are as follows:

    Outstanding     Exercisable  
          Weighted average                 Weighted average        
    Number     exercise     contractual     Number     exercise     contractual  
    of options     price     life (years)     of options     price     life (years)  
          $                 $        
$0.18   3,050,000     0.18     2.26     2,956,250     0.18     2.26  
$0.20   7,522,501     0.20     1.70     6,797,501     0.20     1.67  
$0.45   50,000     0.45     0.12     50,000     0.45     0.12  
    10,622,501     0.20     1.85     9,803,751     0.20     1.84  

F-31



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 14 – STOCK OPTIONS AND SHARE PURCHASE WARRANTS (continued)

(a)     Stock Options (continued)

The fair value of the options issued during the period was estimated using the Black Scholes option pricing model with the following weighted average inputs:

For the year ended December 31   2013     2012     2011  
                   
Fair value at grant date $  0.07   $  0.08   $  0.15  
Exercise price $  0.18   $  0.25   $  0.35  
Share price $  0.18   $  0.25   $  0.36  
Expected volatility   81.18%     82.70%     74.33%  
Expected option life   1.42 years     1.59 years     2.10 years  
Dividends   0.0%     0.0%     0.0%  
Risk-free interest rate   1.01%     1.12%     1.65%  

Expected volatility is based on historical volatility and average weekly stock prices were used to calculate volatility. Management believes that the annualized weekly average of volatility is the best measure of expected volatility. A weighted average forfeiture rate of 6.48% (2012 – 5.90% and 2011 – 9.92%) is used when recording stock based compensation.

(b)     Share Purchase Warrants

The following table summarizes information about warrant transactions:

    Number of     Weighted average  
    warrants     exercise price  
          $  
Balance at January 1, 2011   21,010,455     0.44  
Warrants granted   5,505,002     0.37  
Warrants exercised   (4,551,841 )   0.37  
Warrants expired   (3,540,026 )   0.48  
Balance at December 31, 2011   18,423,590     0.43  
Warrants granted   13,597,729     0.40  
Warrants exercised   (2,968,683 )   0.37  
Balance at December 31, 2012   29,052,636     0.42  
Warrants granted   7,291,667     0.24  
Balance at December 31, 2013   36,344,303     0.40  

Details of the outstanding and exercisable warrants as at December 31, 2013 are as follows:

    Outstanding     Exercisable  
          Weighted average                 Weighted average        
    Number     exercise     Contractual     Number     exercise     contractual  
    of warrants     price     life (years)     of warrants     price     life (years)  
          $                 $        
$0.24   7,291,667     0.24     1.56     7,291,667     0.24     1.56  
$0.40   3,642,856     0.40     1.88     3,642,856     0.40     1.88  
$0.55   4,015,151     0.55     0.47     4,015,151     0.55     0.47  
$0.40 US   7,700,000     0.42     0.98     7,700,000     0.42     0.98  
$0.40 US   13,597,729     0.42     3.43     13,597,729     0.42     3.43  
$0.46 US   96,900     0.49     0.84     96,900     0.49     0.84  
    36,344,303     0.40     2.04     36,344,303     0.40     2.04  

F-32



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 14 – STOCK OPTIONS AND SHARE PURCHASE WARRANTS (continued)

Warrants that have their exercise prices denominated in currencies other than the Company’s functional currency of Canadian dollars are accounted for as derivative financial liabilities, other than agents’ warrants.

NOTE 15 – CONTRIBUTED SURPLUS

Contributed surplus is used to recognize the value of stock option grants and share warrants prior to exercise. Details of changes in the Company's contributed surplus balance are as follows:

    $  
Balance at January 1, 2011   7,639  
Stock based compensation   662  
Exercise of options – value reallocation   (167 )
Balance at December 31, 2011   8,134  
Stock based compensation   866  
Exercise of options – value reallocation   (198 )
Balance at December 31, 2012   8,802  
Stock based compensation   348  
Balance at December 31, 2013   9,150  

NOTE 16 – SUPPLEMENTAL INFORMATION

(a)     Changes in working capital consisted of the following:

    Year ended December 31  
    2013     2012     2011  
      $     $     $  
Changes in working capital:                  
     Accounts receivable   (282 )   338     (199 )
     Share subscription receivable   -     516     (516 )
     Prepaids and deposits   43     9     (8 )
     Accounts payable and accrued liabilities   604     (1,939 )   1,485  
    365     (1,076 )   762  
                   
Comprised of:                  
     Operating activities   441     (1,009 )   443  
     Investing activities   (76 )   (583 )   888  
     Financing activities   -     516     (568 )
    365     (1,076 )   762  
                   
Other cash flow information:                  
     Cash paid for interest   176     234     440  
     Income taxes paid   -     -     -  

F-33



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 16 – SUPPLEMENTAL INFORMATION (continued)

(b)     Per share amounts:

Basic loss per share amounts has been calculated by dividing the net loss for the year attributable to the shareholders of the Company by the weighted average number of common shares outstanding. Stock options and share purchase warrants were excluded from the calculation. The basic and diluted net loss per share is the same as there are no dilutive effects on losses. The following table summarizes the common shares used in calculating basic and diluted net loss per common share:

    Year ended December 31,  
    2013     2012     2011  
Weighted average common shares outstanding     $       $      
       Basic   148,916,374     141,056,221     120,300,214  
       Diluted   148,916,374     141,056,221     120,300,214  

(c)     The Company had the following non-cash transaction:

    Year ended December 31,     
  2013     2012     2011  
      $     $     $  
Non-cash financing for drilling operations of property and equipment (note 12)   443     6,467     -  

NOTE 17 – RELATED PARTY TRANSACTIONS

During the years ended December 31, 2013, 2012 and 2011, the Company entered into the following transactions with related parties:

(a)

Compensation awarded to key management included a total of salaries and consulting fees of $1,173,000 (2012 - $1,194,000 and 2011 - $1,772,000) and non-cash stock-based compensation of $302,000 (2012 - $412,000 and 2011 - $451,000). Key management includes the Company’s officers and directors. The salaries and consulting fees are included in general and administrative expenses.

   
(b)

The Company incurred a total of $Nil (2012 - $Nil and 2011 - $2,000) in finance costs to a company controlled by an officer of the Company.

   
(c)

Included in interest and other income is $21,200 (2012 - $30,000 and 2011 - $30,000) received from the companies controlled by officers of the Company for rental income.

   
(d)

In December 2009, a company controlled by the CEO of the Company (“HEC”) became a 5% working interest partner in the Woodrush property. Included in accounts payable and accrued liabilities at December 31, 2013 is $10,000 (2012 - $20,000 and 2011 - $53,668) owing to HEC.

   
(e)

With respect to the private placement of 11,010,000 units issued at US$0.30 per unit completed in February 2011, directors and officers of the Company purchased 2,000,000 units of this offering (see Note 13).

   
(f)

In December 2011, HEC exercised 250,000 warrants with an exercise price of US$0.35 each that were issued in February 2011.

   
(g)

In January 2012, directors and officers of the Company exercised 750,000 warrants with an exercise price of US$0.35 each that were issued in February 2011.

F-34



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 17 – RELATED PARTY TRANSACTIONS (continued)

(h)

On December 31, 2012, Dejour USA entered into a financial contract with a U.S. oil and gas drilling fund (“Drilling Fund”) whereby the parties agreed to form an industry-standard drilling partnership for purposes of drilling three wells and completing four wells in the State of Colorado (note 12). A director of the Company provides investment advice for a fee to the Drilling Fund. The director abstained from voting when the Board of Directors approved the Company signing a financial contract with the Drilling Fund.

   
(i)

In December 2013, Dejour USA sold its working interests in certain non-core oil and gas leases in the area of Colorado to a related U.S. oil and gas corporation for gross proceeds of $477,000 (US$450,000). A director of the Company is the President of the U.S. oil and gas corporation. The sale price represented the higher of two competing offers to purchase the oil and gas leases in Colorado and the director of the Company abstained from voting to approve the Company’s sale of the leases.

NOTE 18 – INCOME TAXES

The actual income tax provisions differ from the expected amounts calculated by applying the Canadian combined federal and provincial corporate income tax rates to the Company’s loss before income taxes. The components of these differences are as follows:

    2013     2012     2011  
    $               $      $  
Loss before income taxes   (2,576 )   (11,752 )   (11,230 )
Corporate tax rate   25.21%     28.48%     33.36%  
                   
Expected tax recovery   (649 )   (3,347 )   (3,747 )
Increase (decrease) resulting from:                  
         Differences in foreign tax rates and change in effective tax rates   (352 )   475     (319 )
         Impact of foreign exchange rate changes   (452 )   259     (220 )
         Change in unrecognized deferred tax assets   2,251     2,799     3,583  
         Stock based compensation and share issue costs   (197 )   (197 )   221  
         Non deductible amounts   (601 )   (121 )   347  
         Other adjustments         132     (52 )
Deferred income tax recovery   -     -     (187 )

No deferred tax asset has been recognized in respect of the following losses and deductable temporary differences as it is not considered probable that sufficient future taxable profit will allow the deferred tax assets to be recovered.

    2013     2012  
  $     $  
Deferred income tax assets            
           Non-capital losses available   20,026     11,290  
           Capital losses available   1,072     1,030  
           Resource tax pools in excess of net book value   2,495     8,928  
           Share issue costs and other   153     247  
Unrecognized deferred tax assets   23,746     21,495  

F-35



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 18 – INCOME TAXES (continued)

The Company has the approximate amounts of tax pools available as follows:

As at December 31   2013     2012  
    $     $  
Canada:            
Exploration and development expenditures   15,050     17,218  
Unamortized share issue costs   858     988  
Capital losses   8,242     8,242  
Non-capital losses   24,918     22,762  
    49,068     49,210  
             
United States:            
Exploration and development expenditures   17,039     33,287  
Non-capital losses   36,112     15,324  
    53,151     48,611  
             
Total   102,219     97,821  

The exploration and development expenditures at December 31, 2013 can be carried forward to reduce future income taxes indefinitely. The non-capital losses for income tax purposes expire as follows:

    Canada     United States     Total  
    $     $     $  
2015   1,729     -     1,729  
2026   -     2,146     2,146  
2027   4,152     2,861     7,013  
2028   4,674     215     4,889  
2029   3,373     2,769     6,142  
2030   2,070     2,353     4,423  
2031   2,407     2,369     4,776  
2032   4,357     3,669     8,026  
2033   2,156     19,730     21,886  
    24,918     36,112     61,030  

The Company does not recognize deferred tax assets related to the foregoing tax pools because it is not probable that future taxable profit will be available against which the tax pools can be utilized.

NOTE 19 – COMMITMENTS

The Company has entered into lease agreements on office premises for its various locations. Future minimum annual lease payments under the leases are as follows:

     $  
2014   187  
2015   52  
    239  

F-36



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 20 – PERSONNEL EXPENSES

The aggregate compensation expense of key management was as follows:

    Year ended December 31  
    2013     2012     2011  
    $     $     $  
Salaries, benefits and fees   1,173     1,194     1,772  
Non-cash stock-based compensation   302     412     451  
    1,475     1,606     2,223  
Capitalized portion of salaries and fees   (251 )   (193 )   (154 )
    1,224     1,413     2,069  

NOTE 21 – OPERATING SEGMENTS

Segment information is provided on the basis of geographic segments as the Company manages its business through two geographic regions – Canada and the United States. The two geographic segments presented reflect the way in which the Company’s management reviews business performance. The Company’s revenue and losses of each geographic segment are as follows:

          Canada                 United States                 Total        
    2013     2012     2011     2013     2012     2011     2013     2012     2011  
    $     $     $     $     $     $     $     $     $  
Year ended December 31                                                      
Revenues   6,039     5,766     7,196     1,467     -     -     7,506     5,766     7,196  
Segmented income (loss)   (1,552 )   (8,361 )   (4,662 )   (1,025 )   (3,390 )   (6,381 )   (2,577 )   (11,752 )   (11,043 )
Amortization, depletion and impairment losses   2,714     7,927     3,331     916     2,749     5,321     3,630     10,676     8,652  
Interest expense   669     233     440     486     1     -     1,155     234     440  
Deferred tax recovery   -     -     187     -     -     -     -     -     187  
                                                       
As at December 31                                                      
Total capital expenditures   37     1,423     6,480     2,341     9,389     1,833     2,378     10,812     8,313  

NOTE 22 – ACCUMULATED OTHER COMPREHENSIVE LOSS

The components of accumulated other comprehensive income (loss) were as follows:

As at   December 31, 2013     December 31, 2012     December 31, 2011  
    $     $     $  
Foreign currency translation adjustment   514     (568 )   393  
    514     (568 )   393  

NOTE 23 – DETERMINATION OF FAIR VALUES

A number of the Company’s accounting policies and disclosures require the determination of fair value. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that financial asset or financial liability. Due to the use of subjective judgments and uncertainties in the determination of these fair values the values should not be interpreted as being realizable in an immediate settlement of the financial instruments.

F-37



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 23 – DETERMINATION OF FAIR VALUES (continued)

The Company classifies the fair value of financial instruments according to the following hierarchy based on the amount of observable inputs used to value the instruments:

Level 1: Values based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets or liabilities.

 

 

Level 2: Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.

 

 

Level 3: Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.

The recoverable amount of developed and producing properties was determined based on fair value less costs to sell (see Note 6). The model has significant unobservable inputs (level 3).

At December 31, 2013 and December 31, 2012, fair value of warrant liability is measured using the Hull-White Trinomial option pricing model with significant unobservable inputs (Level 3). The derivative liability is measured using an option pricing model with significant unobservable inputs (Level 3). The financial contract liability is measured at the initial transaction price, which is deemed to be fair value, and subsequently measured based on netbacks in accordance with the Joint Operating Agreement. This model also has significant unobservable inputs (Level 3).

Included in E&E assets as at December 31, 2013 of $3,281,000 (December 31, 2012 - $3,890,000) is carried at fair value. Included in property and equipment as at December 31, 2013 of $20,386,000 (December 31, 2012 - $21,144,000) is carried at fair value.

NOTE 24 – FINANCIAL INSTRUMENTS AND CAPITAL MANAGEMENT

The Company operates in the United States, giving rise to exposure to market risks from changes in foreign currency 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.

(a) Credit Risk

Credit risk arises from credit exposure to receivables due from joint venture partners and marketers included in accounts receivable. The maximum exposure to credit risk is equal to the carrying value of the financial assets.

The Company is exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company’s business, financial condition, and results of operations.

The objective of managing the third party credit risk is to minimize losses in financial assets. The Company assesses the credit quality of the partners, taking into account their financial position, past experience, and other factors. The Company mitigates the risk of non-collection of certain amounts by obtaining the joint venture partners’ share of capital expenditures in advance of a project and by monitoring accounts receivable on a regular basis. As at December 31, 2013 and 2012, no accounts receivable has been deemed uncollectible or written off during the year.

As at December 31, 2013, the Company’s receivables consist of $4,000 (2012 - $30,000) from joint interest partners, $760,000 (2012 - $494,000) from oil and natural gas marketers and $67,000 (2012 - $25,000) from other trade receivables.

F-38



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 24 – FINANCIAL INSTRUMENTS AND CAPITAL MANAGEMENT (continued)

(a)    Credit Risk (continued)

The Company considers all amounts outstanding for more than 90 days as past due. Currently, there is no indication that amounts are non-collectable; thus an allowance for doubtful accounts has not been set up. As at December 31, 2013, $Nil (2012 - $Nil) of accounts receivable are past due.

(b)     Liquidity Risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they are due. The nature of the oil and gas industry is capital intensive and the Company maintains and monitors a certain level of cash flow to finance operating and capital expenditures.

The Company’s ongoing liquidity and cash flow are impacted by various events and conditions. These events and conditions include but are not limited to commodity price fluctuations, general credit and market conditions, operation and regulatory factors, such as government permits, the availability of drilling and other equipment, lands and pipeline access, weather, and reservoir quality.

To mitigate the liquidity risk, the Company closely monitors its credit facility, production level and capital expenditures to ensure that it has adequate liquidity to satisfy its financial obligations.

The following are the contractual maturities of financial liabilities as at December 31, 2013:

    Carrying amount     2014  
    $     $  
Accounts payable and accrued liabilities   2,623     2,623  
Bank credit facilities   2,900     2,900  
Loan facility   2,911     3,500  
    8,434     9,023  

For the contractual maturities of financial contract liability as at December 31, 2013, see note 12 for details.

(c)     Market Risk

Market risk is the risk that changes in market prices, such as foreign exchange rates, commodity prices, and interest rates will affect the Company’s net earnings. The objective of market risk management is to manage and control market risk exposures within acceptable limits, while maximizing returns. The Company utilizes financial derivatives to manage certain market risks. All such transactions are conducted in accordance with the risk management policy that has been approved by the Board of Directors.

(i)    Foreign Currency Exchange Risk

Foreign currency exchange rate risk is the risk that the fair value of financial instruments or future cash flows will fluctuate as a result of changes in foreign exchange rates. Although substantially all of the Company’s oil and natural gas sales are denominated in Canadian dollars, the underlying market prices in Canada for oil and natural gas are impacted by changes in the exchange rate between the Canadian and United States dollars. Given that changes in exchange rate have an indirect influence, the impact of changing exchange rates cannot be accurately quantified. The Company had no forward exchange rate contracts in place as at or during the year ended December 31, 2013 and 2012.

F-39



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 24 – FINANCIAL INSTRUMENTS AND CAPITAL MANAGEMENT (continued)

(c)    Market Risk (continued)

(i)    Foreign Currency Exchange Risk (continued)

The Company was exposed to the following foreign currency risk at December 31:

    2013     2012  
Expressed in foreign currencies   CND$     CND$  
Cash and cash equivalents   376     1,031  
Accounts receivable   421     30  
Accounts payable and accrued liabilities   (1,613 )   (869 )
Balance sheet exposure   (816 )   192  

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

    2013     2012  
December 31, reporting date rate   1.0636     0.9949  
YTD average USD to CAD   1.0301     0.9999  

The Company has performed a sensitivity analysis on its foreign currency denominated financial instruments. Based on the Company’s foreign currency exposure noted above and assuming that all other variables remain constant, a 10% appreciation of the US dollar against the Canadian dollar would result in the increase of net loss of $82,000 at December 31, 2013 (2012 - $19,000 decrease of net loss and 2011 - $50,000 decrease of net loss). For a 10% depreciation of the above foreign currencies against the Canadian dollar, assuming all other variables remain constant, there would be an equal and opposite impact on net loss.

(ii)   Interest Rate Risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. At the year ended December 31, 2013, the Company was exposed to interest rate fluctuations on its bank credit facility which bore a floating rate of interest. Assuming all other variables remain constant, an increase or decrease of 1% in market interest rate at December 31, 2013 would have increased or decreased net loss by $41,000. The Company had no interest rate swaps or financial contracts in place at or during the year ended December 31, 2013 and 2012.

(iii)  Commodity Price Risk

Revenues and consequently cash flows fluctuate with commodity prices and the US/Canadian dollar exchange rate. Commodity prices are determined on a global basis and circumstances that occur in various parts of the world are outside of the control of the Company. The Company may protect itself from fluctuations in prices by using the financial derivative sales contracts. The Company may enter into commodity price contracts to manage the risks associated with price volatility and thereby protect its cash flows used to fund its capital program. Assuming all other variables remain constant, an increase or decrease of oil price of $1 per bbl and gas price of $0.01 per mcf at December 31, 2013 would have decreased or increased net loss by $85,000. The Company had no commodity contracts in place at December 31, 2013.

F-40



DEJOUR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For the Year Ended December 31, 2013, 2012 and 2011
(All tabular amounts are expressed in thousands of Canadian dollars unless otherwise noted)
 

NOTE 24 – FINANCIAL INSTRUMENTS AND CAPITAL MANAGEMENT (continued)

(d)     Capital Management Strategy

The Company’s policy on capital management is to maintain a prudent capital structure so as to maintain financial flexibility, preserve access to capital markets, maintain investor, creditor and market confidence, and to allow the Company to fund future developments. The Company considers its capital structure to include share capital, cash and cash equivalents, bank line of credit, and working capital. In order to maintain or adjust capital structure, the Company may from time to time issue shares or enter into debt agreements and adjust its capital spending to manage current and projected operating cash flows and debt levels.

The Company’s current borrowing capacity is based on the lender’s review of the Company’s oil and gas reserves. The Company is also subject to various covenants. Compliance with these covenants is monitored on a regular basis and at December 31, 2013, the Company is in compliance with the covenant for its bank credit facility (Note 8) and is in default of the covenant for its loan facility (note 10).

The Company’s share capital is not subject to any external restrictions. The Company has not paid or declared any dividends, nor are any contemplated in the foreseeable future. There have been no changes to the Company’s capital management strategy during the year ended December 31, 2013.

NOTE 25 – SUBSEQUENT EVENTS

(a)

Subsequent to December 31, 2013, the Company completed a non-brokered private placement of 7 million common shares at $0.11 per share. Gross proceeds raised were $770,000. In connection with this private placement, the Company paid finder fees of $27,000 in cash. Directors and Officers purchased 900,000 common shares of this placement.

   
(b)

On March 5, 2014, a lawsuit was initiated against the Company and its wholly-owned US subsidiary for alleged breach of a December 12, 2013 “Letter of Intent” with respect to a proposed farmin arrangement on oil and gas properties owned by the subsidiary and related legal claims.

   

The Company is of the opinion the lawsuit’s claims are frivolous and vexatious. The lawsuit is not expected to have a material adverse affect on the financial statements.

F-41


SUPPLEMENTARY OIL AND GAS RESERVE ESTIMATION AND DISCLOSURES – ASC 932 (UNAUDITED)

Select supplementary oil and gas reserve estimation and disclosure are provided in accordance with U.S. disclosure requirements. The standards of the SEC require that proved reserves be estimated using existing economic conditions (constant pricing). Based on this methodology, the Company’s results have been calculated utilizing the 12-month average price for each of the years presented within this supplementary disclosure.

The Company’s 2013, 2012 and 2011 financial results were prepared in accordance with IFRS.

The Company reports in Canadian currency and therefore the Reserves Data pertaining to the Company’s reserves in the United States set forth in the tables below has been converted to Canadian dollars at the prevailing conversion rate at December 31, 2013. The conversion rate used per Bank of Canada is 1.0636.

(a)            Net proved oil and gas reserves

As at December 31, 2013, the Company’s oil and gas reserves are located in both Canada and the United States.

GLJ Petroleum Consultants (“GLJ”) of Calgary, Alberta, independent petroleum engineering consultants based in Calgary, Alberta were retained by the Company to evaluate the Canadian properties of the Company. Their report, titled “Reserves Assessment and Evaluation of Oil and Gas Properties, Dejour Energy (Alberta) Ltd.”, is dated February 19, 2014 and has an effective date of December 31, 2013.

Gustavson Associates (“Gustavson”), an independent petroleum engineering consultants based in Denver, Colorado were retained by the Company to evaluate the US properties of the Company. Their report, titled “Reserve Estimate and Financial Forecast as to Dejour’s Interests in the Kokopelli Field Area, Garfield County, Colorado” is dated March 14, 2014 and has an effective date of January 1, 2014.

In accordance with the US Securities and Exchange Commission’s (“SEC”) definitions and guidelines, GLJ and Gustavson, have used constant prices and costs in estimating the reserves and future net cash flows contained in their reports. Actual future net cash flows will be affected by other factors, such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs.

The tables in this section set forth oil and gas information prepared by the Company in accordance with U.S. disclosure standards, including Accounting Standards Codification 932 (“ASC 932”). Reserves have been estimated in accordance with the US Securities and Exchange Commission’s (“SEC”) definitions and guidelines. The changes in our net proved reserve quantities are outlined below.

Net reserves are Dejour royalty and working interest remaining reserves, less all Crown, freehold, and overriding royalties and interests that are not owned by Dejour.

Proved reserves are those estimated quantities of crude oil, natural gas and natural gas liquids that can be estimated with a high degree of certainty to be economically recoverable under existing economic and operating conditions. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

Proved developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. Developed reserves may be subdivided into producing and non-producing.

Proved undeveloped reserves are those reserves that are expected to be recovered from known accumulations where a significant expenditure (e.g. when compared to the cost of drilling a well) is required to render them capable of production.

The Company cautions users of this information as the process of estimating crude oil and natural gas reserves is subject to a level of uncertainty. The reserves are based on economic and operating conditions; therefore, changes can be made to future assessments as a result of a number of factors, which can include new technology, changing economic conditions and development activity.



(a)

CONSTANT PRICES AND COSTS - YEAR ENDED DECEMBER 31, 2013


  Net Proved Developed and                                                        
  Proved Undeveloped Reserves                                                        
                                                                                 
      Canada     United States     Total  
      Light and     Natural Gas           Barrels of Oil           Natural Gas           Barrels of Oil     Light and           Natural Gas           Barrels of Oil  
      Medium Oil     Liquids     Natural Gas     Equivalent     Condensate     Liquids     Natural Gas     Equivalent     Medium Oil     Condensate     Liquids     Natural Gas     Equivalent  
      (Mbbl)     (Mbbl)     (MMcf)     (Mboe)     (Mbbl)     (Mbbl)     (MMcf)     (Mboe)     (Mbbl)     (Mbbl)     (Mbbl)     (MMcf)     (Mboe)  
  December 31, 2012   243     2     165     272     340     4,458     40,938     11,621     243     340     4,460     41,103     11,893  
  Extensions   -     -     -     -     283     1,726     41,571     8,938     -     283     1,726     41,571     8,938  
  Technical Revisions   (56 )   2     551     38     (36 )   (2,608 )   3,974     (1,982 )   (56 )   (36 )   (2,606 )   4,525     (1,944 )
  Dispositions   .-     -     -     -     -     (11 )   (109 )   (29 )   -     -     (11 )   (109 )   (29 )
  Economic Factors   -     -     -     -     4     33     302     87     -     4     33     302     87  
  Production   (73 )   (2 )   (250 )   (117 )   (1 )   (2 )   (65 )   (14 )   (73 )   (1 )   (4 )   (315 )   (131 )
  December 31, 2013   114     2     466     194     590     3,596     86,611     18,621     114     590     3,598     87,077     18,814  
                                                                                 
  Developed Producing   114     2     466     194     3     15     367     79     114     3     17     833     273  
  Developed Non-producing   -     -     -     -     -     -     -     -     -     -     -     -     -  
  Undeveloped   -     -     -     -     587     3,581     86,243     18,542     -     587     3,581     86,243     18,542  
  Total   114     2     466     194     590     3,596     86,610     18,621     114     590     3,598     87,076     18,815  
                                                                                 

(1) Canada – Increase in Total Proved Natural Gas Reserves of 551 MMcf:

During the year ended December 31, 2013, an expected increase in natural gas reserves as there are more favorable decline curves and additional solution gas from the proved undeveloped location. GLJ increased, by way of a technical revision, the Company’s total proved natural gas reserves by 551 MMcf.

(2) United States – Increase in Total Proved Natural Gas Liquids Reserves of 1,726 Mbbls and Natural Gas Reserves of 41,571 MMcfs:

During the year ended December 31, 2013, an expected increase in the natural gas reserves and natural gas liquids reserves as this resulted from a successful 2013 drilling program which converted 47 “probable” drilling locations at December 31, 2012 to “proven” as at December 31, 2013. Gustavson increased, by way of an extension, the Company’s total proved natural gas and natural gas liquids by 41,571 MMcfs and 1,726 Mbbls, respectively.


CONSTANT PRICES AND COSTS - YEAR ENDED DECEMBER 31, 2012

Net Proved Developed and                                                        
Proved Undeveloped Reserves                                                        
                                                                               
    Canada     United States     Total  
    Light and     Natural Gas           Barrels of Oil           Natural Gas           Barrels of Oil     Light and           Natural Gas           Barrels of Oil  
    Medium Oil     Liquids     Natural Gas     Equivalent     Condensate     Liquids     Natural Gas     Equivalent     Medium Oil     Condensate     Liquids     Natural Gas     Equivalent  
    (Mbbl)     (Mbbl)     (MMcf)     (Mboe)     (Mbbl)     (Mbbl)     (MMcf)     (Mboe)     (Mbbl)     (Mbbl)     (Mbbl)     (MMcf)     (Mboe)  
December 31, 2011   317     4     752     446     287     3,863     41,314     11,035     317     287     3,867     42,066     11,481  
Technical Revisions   (18 )   (1 )   (306 )   (70 )   54     705     615     862     (18 )   54     704     309     792  
Economic Factors   -     -     -     -     (1 )   (110 )   (991 )   (276 )   -     (1 )   (110 )   (991 )   (276 )
Production   (56 )   (1 )   (281 )   (104 )   -     -     -     -     (56 )   -     (1 )   (281 )   (104 )
December 31, 2012   243     2     165     272     340     4,458     40,938     11,621     243     340     4,460     41,103     11,893  
                                                                               
Developed Producing   243     -     104     260     -     11     109     29     243     -     11     213     289  
Developed Non-producing   -     2     61     12     1     7     68     19     -     1     9     129     31  
Undeveloped   -     -     -     -     339     4,440     40,761     11,573     -     339     4,440     40,761     11,573  
Total   243     2     165     272     340     4,458     40,938     11,621     243     340     4,460     41,103     11,893  
                                                                               

(1) Canada – Decrease in Total Proved Natural Gas Reserves of 306 MMcf:

During the year ended December 31, 2012, following the implementation of waterflood in 2011, an expected decrease in natural gas reserves as the influx of water into the reservoir will replace some of the natural gas reserves -in-place. AJM Deloitte decreased, by way of a technical revision, the Company’s total proved natural gas reserves by 306 MMcfs.

(2) United States – Increase in Total Proved Natural Gas Liquids Reserves of 705 Mbbls and Natural Gas Reserves of 615 MMcf:

During the year ended December 31, 2012, an expected increase in the natural gas reserves and natural gas liquids reserves as the Company’s major competitors has strong upside reserves potential in the nearby areas of the Piceance Basin of Western Colorado. Gustavson increased, by way of a technical revision, the Company’s total proved natural gas liquids reserves and natural gas reserves by 705 Mbbls and 615 MMcfs respectively.



(b)

Capitalized Costs


      December 31,     December 31,     December 31,  
  (CA$ thousands)   2013     2012     2011  
      $     $     $  
  Canada                  
  Proved oil and gas properties   24,550     24,700     23,149  
  Unproved oil and gas properties   70     23     72  
  Total capital costs   24,620     24,723     23,221  
  Accumulated depletion and depreciation   (10,593 )   (8,557 )   (5,820 )
  Impairment   (6,740 )   (6,211 )   (1,298 )
  Net capitalized costs   7,287     9,955     16,103  
                     
  United States                  
  Proved oil and gas properties   14,279     13,076     4,076  
  Unproved oil and gas properties   18,298     25,462     27,772  
  Total capital costs   32,577     38,538     31,848  
  Accumulated depletion and depreciation   (463 )   -     -  
  Impairment   (15,781 )   (23,785 )   (23,524 )
  Net capitalized costs   16,333     14,753     8,324  
                     
  Total                  
  Proved oil and gas properties   38,829     37,776     27,225  
  Unproved oil and gas properties   18,368     25,485     27,844  
  Total capital costs   57,197     63,261     55,069  
  Accumulated depletion and depreciation   (11,056 )   (8,557 )   (5,820 )
  Impairment   (22,521 )   (29,996 )   (24,823 )
  Net capitalized costs   23,620     24,708     24,427  



(c)

Costs Incurred


    December 31,     December 31,     December 31,  
(CA$ thousands)   2013     2012     2011  
    $     $     $  
Canada                  
Property acquisition costs (1)                  
   Proved oil and gas properties   17     14     47  
   Unproved oil and gas properties   -     1     9  
Exploration costs (2)   115     132     32  
Development costs (3)   4     1,407     6,410  
Capital Expenditures   136     1,553     6,498  
                   
United States                  
Property acquisition costs (1)                  
   Proved oil and gas properties   45     40     40  
   Unproved oil and gas properties   56     211     146  
Exploration costs (2)   79     104     38  
Development costs (3)   1,720     2,568     1,609  
Capital Expenditures   1,900     2,923     1,833  
                   
Total                  
Property acquisition costs (1)                  
   Proved oil and gas properties   62     54     87  
   Unproved oil and gas properties   56     212     155  
Exploration costs (2)   194     236     71  
Development costs (3)   1,724     3,975     8,019  
Capital Expenditures   2,036     4,476     8,332  

  (1)

Acquisitions are not net of disposition of properties.

  (2)

Geological and geophysical capital expenditures and drilling costs for exploraton wells drilled

  (3)

Includes equipping and facilities capital expenditures




(d)

Results of Operations of Producing Activities


    For the years ended December 31,  
(CA$ thousands)   2013     2012     2011  
             
Canada                  
Oil and gas sales, net of royalties   6,038     5,766     7,196  
Operating costs and capital taxes   (2,386 )   (3,101 )   (1,975 )
Transportation costs   (462 )   (661 )   (508 )
Depletion, depreciation and accretion   (2,037 )   (2,754 )   (2,393 )
Income taxes (1)   -     -     -  
Results of operations   1,153     (750 )   2,320  
                   
United States                  
Oil and gas sales, net of royalties   1,467     -     -  
Operating costs and capital taxes   (549 )   (31 )   (16 )
Transportation costs   -     -     -  
Depletion, depreciation and accretion   (502 )   (13 )   (11 )
Income taxes (1)   -     -     -  
Results of operations   416     (44 )   (27 )
                   
Total                  
Oil and gas sales, net of royalties   7,505     5,766     7,196  
Lease operating costs and capital taxes   (2,935 )   (3,132 )   (1,991 )
Transportation costs   (462 )   (661 )   (508 )
Depletion, depreciation and accretion   (2,539 )   (2,767 )   (2,404 )
Income taxes (1)   -     -     -  
Results of operations   1,569     (794 )   2,293  

  (1)

Dejour is currently not taxable.


(e)

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein

   

The standardized measure of discounted future net cash flows is based on estimates made by GLJ and Gustavson of net proved reserves. Future cash inflows are computed based on the average of the first day constant prices in each of the 12 months for the year ended December 31, 2013 and cost assumptions applied against annual future production from proved crude oil and natural gas reserves. Future development and production costs are computed based on the average of the first day constant prices in each of the 12 months for the year ended December 31, 2013 and assume the continuation of existing economic conditions. Future income taxes are calculated by applying statutory income tax rates. The Company is currently not taxable. The standardized measure of discounted future net cash flows is computed using a 10 percent discount factor.

   

The Company cautions users of this information that the discounted future net cash flows relating to proved oil and gas reserves are neither an indication of the fair market value of our oil and gas properties, nor of the future net cash flows expected to be generated from such properties. The discounted future cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in crude oil and natural gas prices, development, asset retirement and production costs and possible changes to tax and royalty regulations. The prescribed discount rate of 10 percent is arbitrary and may not appropriately reflect future interest rates.



Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows relating to our estimated proved reserves as of December 31, 2013 is presented below:

As at December 31, 2013                  
                   
(CA$ thousands)   Canada     USA     Total  
    $     $     $  
Future cash from revenues after royalties   11,667     694,341     706,008  
Future production, abandon and salvage costs   (7,464 )   (272,478 )   (279,942 )
Future development costs   -     (157,139 )   (157,139 )
Future income taxes   -     (29,123 )   (29,123 )
Future net cash flows   4,203     235,601     239,804  
Less: 10% annual discount factor   (555 )   (174,682 )   (175,237 )
                   
Standardized measure of discounted future net cash flow   3,648     60,919     64,567  

The standardized measure of discounted future net cash flows relating to our estimated proved reserves as of December 31, 2012 is presented below:

As at December 31, 2012                  
                   
(CA$ thousands)   Canada     USA     Total  
    $     $     $  
Future cash from revenues after royalties   20,069     234,374     254,443  
Future production, abandon and salvage costs   (10,835 )   (90,466 )   (101,301 )
Future development costs   (153 )   (95,180 )   (95,333 )
Future income taxes   (2,270 )   (9,950 )   (12,220 )
Future net cash flows   6,811     38,778     45,589  
Less: 10% annual discount factor   (1,181 )   (38,935 )   (40,116 )
                   
Standardized measure of discounted future net cash flow   5,630     (157 )   5,473  



(f)

Changes in Standardized Measure of Discounted Future Net Cash Flows

   

The principal sources of changes in the standardized measure of the future net cash flows for the year ended December 31, 2013 are presented below:


For the Year Ended December 31, 2013                  
                   
(CA$ thousands)   Canada     USA     Total  
    $     $     $  
Beginning Balance, January 1, 2013   5,630     (157 )   5,473  
                   
Sales and transfers of oil and gas produced, net of production costs   (3,640 )   (213 )   (3,853 )
Net changes in sales and transfer prices, net of production costs and royalties   (1,238 )   113,216     111,978  
Extensions, discoveries, and improved recovery, less estimated costs   -     121,937     121,937  
Changes in estimated future development costs   (153 )   (22,212 )   (22,365 )
Sales of reserves in place, less estimated future costs   -     (479 )   (479 )
Revisions of quantity estimates and timing of estimated production   1,040     (22,397 )   (21,357 )
Accretion of discount   625     (151,557 )   (150,932 )
Net change in income taxes   1,875     26,728     28,603  
Other   (491 )   (3,947 )   (4,438 )
                   
Ending Balance, December 31, 2013   3,648     60,919     64,567  

The principal sources of changes in the standardized measure of the future net cash flows for the year ended December 31, 2012 are presented below:

For the Year Ended December 31, 2012                  
                   
(CA$ thousands)   Canada     USA     Total  
    $     $     $  
Beginning Balance, January 1, 2012   18,459     33,462     51,921  
                   
Sales and transfers of oil and gas produced, net of production costs   (1,973 )   -     (1,973 )
Net changes in sales and transfer prices, net of production costs and royalties   (8,514 )   (42,572 )   (51,086 )
Changes in estimated future development costs   (3 )   -     (3 )
Revisions of quantity estimates and timing of estimated production   (2,924 )   5,319     2,395  
Accretion of discount   (385 )   -     (385 )
Net change in income taxes   970     3,634     4,604  
                   
Ending Balance, December 31, 2012   5,630     (157 )   5,473  





June 5, 2013

Dejour Energy (Alberta) Ltd.
c/o Dejour Energy Inc.
#598 - 999 Canada Place
Vancouver, BC V6C 3El

ATTENTION: Mr. David Matheson Mr. Robert Hodgkinson
  Chief Financial Officer Co-Chairman and CEO

Dear Sirs:

RE: CREDIT FACILITIES - CANADIAN WESTERN BANK / DEJOUR ENERGY (ALBERTA) LTD.

We are pleased to advise that Canadian Western Bank has approved the following amended Credit Facilities for Dejour Energy (Alberta) Ltd., subject to the terms and conditions of the accepted Commitment Letter dated March 25, 2013, which terms and conditions will remain in full force and effect, as amended below.

BORROWER:

DEJOUR ENERGY (ALBERTA) LTD. (the " Borrower ").

 

 

GUARANTOR:

DEJOUR ENERGY INC. and DEJOUR ENERGY (USA) CORP. (collectively the " Guarantor ").

 

 

The Borrower and the Guarantor are collectively referred to as " Loan Parties ", and each, a " Loan Party ".

 

 

LENDER:

CANADIAN WESTERN BANK (the " Bank ").

 

CREDIT FACILITY A:

REVOLVING OPERATING DEMAND LOAN (the " Credit Facility A ").

 

 

MAXIMUM AMOUNT:

$3,500,000.

 

CREDIT FACILITY B:

NON-REVOLVING DEMAND LOAN (the " Credit Facility B ").

 

 

MAXIMUM AMOUNT:

$1,650,000.

 

 

FOR ALL CREDIT FACILITIES

 

 

RENEWAL FEE:

A fee of $5,350 is payable upon provision of this Commitment Letter.

 

 

SECURITY:

The following security (the "Existing Security") has been completed, duly executed, delivered, perfected and registered, where necessary, to the entire satisfaction of the Bank and its counsel.


  1.

$10,000,000 Debenture with a first floating charge over all assets of the Borrower (first security interest in personal property) with an undertaking to provide fixed charges on the Borrower's petroleum and natural gas properties at the request of the Bank, and pledge of such Debenture;

 

 

Suite 200, 606 - 4 Street S.W. Calgary, Alberta T2P 1T1 TELEPHONE (403) 750-3599 FAX (403) 264-1619


2

  2.

Supplemental Debenture with fixed charges on the Borrower's Drake/Woodrush, BC petroleum and natural gas property;

     
  3.

Revolving Credit Agreement in the amount of $3,700,000 by the Borrower;

     
  4.

Variable Rate Demand Note in the amount of $2,250,000 by the Borrower;

     
  5.

General Assignment of Book Debts by the Borrower;

     
  6.

evidence of insurance coverage in accordance with industry standards designating the Bank as first loss payee in respect of the proceeds of the insurance and an additional insured;

     
  7.

appropriate title representation from the Borrower (officer's certificate as to title) including a schedule of petroleum and natural gas reserves described by lease (type, date, term, parties), legal description (wells and spacing units), interest (working interest or other APO/BPO interests), overrides (APO/BPO), gross overrides, and other liens, encumbrances, and overrides;

     
  8.

evidence of extra-provincial registrations of the Borrower where applicable;

     
  9.

Full Liability Guarantee provided by Dejour Energy Inc. supported by:


  a)

$10,000,000 Debenture with a first floating charge over all assets of the Dejour Energy Inc. (first security interest in personal property) with an undertaking to provide fixed charges on the Dejour Energy Inc.'s petroleum and natural gas properties at the request of the Bank, and pledge of such Debenture;


  10.

Subordination/Postponement Agreement regarding loan payable to Dejour Energy Inc.; and

     
  11.

legal opinion of the Bank's counsel.

The following security (the "Additional Security") shall be completed, duly executed, delivered, perfected and registered, where necessary, to the entire satisfaction of the Bank and its counsel, and shall form part of the Security.

  1.

Commitment Letter dated June 5,2013;

     
  2.

Unlimited Guaranty Agreement provided by Dejour Energy (USA) Corp. supported by:


  a.

Second Charge Mortgage, Assignment of Production, Security Agreement and Financing Statement; and


  3.

such other security, documents, and agreements that the Bank or its legal counsel may reasonably request.

The Existing Security and Additional Security (together the "Security") to be perfected/registered, at a minimum, in the Province of Alberta and British Columbia in a first priority position, and in a second position in such jurisdictions in the United States as required, subject only to Permitted Encumbrances. All present and future Security shall be held by the Bank as continuing security for all present and future debts, obligations and liabilities (whether direct or indirect, absolute or contingent) of the Loan Parties to the Bank including without limitation for the repayment of all loans and advances made herein and for other loans and advances that may be made from time to time in the future whether herein or otherwise. The Security shall be in form and substance satisfactory to the Bank and its counsel.


3

REPRESENTATIONS  
AND WARRANTIES:

Each Loan Party represents and warrants to the Bank (all of which representations and warranties each Loan Party hereby acknowledges are being relied upon by the Bank in entering into this Commitment Letter) that:


  5.

there has been no adverse material change in the financial position of any Loan Party since the date of its most recent consolidated and non-consolidated financial statements dated March 31, 2013 which were furnished to the Bank. Such financial statements fairly present the financial position of each Loan Party at the date that they were drawn up.


CONDITIONS

 

PRECEDENT:

Prior to each advance under the Credit Facilities, the Borrower shall have provided, executed or satisfied the following, to the Bank's satisfaction (collectively with all other conditions precedent set out in this Commitment Letter, called the " Conditions Precedent "):


  1.

all Additional Security shall be duly completed, authorized, executed, delivered by each Loan Party which is a party thereto, and perfected and registered, all to the satisfaction of the Bank and its counsel;

     
  2.

no further Default or Event of Default shall exist;

     
  3.

no Material Adverse Effect has occurred with respect to any Loan Party or the Security;

     
  4.

all representations and warranties of each Loan Party shall be true and correct; and

     
  5.

any other document that may be reasonably requested by the Bank.


The above conditions are inserted for the sole benefit of the Bank, and may be waived by the Bank in whole or in part (with or without terms or conditions) in respect of any particular Advance, provided that any waiver shall not be binding unless given in writing and shall not derogate from the right of the Bank to insist on the satisfaction of any condition not expressly waived in writing or to insist on the satisfaction of any condition waived in writing which may be requested in the future.

 

CONDITIONS

SUBSEOUENT:

The Loan Parties agree that, subject to Review and the Bank's right of demand in its discretion at any time and other provisions of the Commitment Letter and the Security requiring earlier repayment of the amounts outstanding under Credit Facility B, if any of the following conditions subsequent below are not fulfilled, satisfied or completed or the Bank does not receive evidence, in form and substance satisfactory to the Bank, that each of the following conditions subsequent below are fulfilled, satisfied or completed, then all amounts outstanding under Credit Facility B will immediately become due and payable:


  1.

a portion of the $3,500,000 non-amortizing term facility provided to Dejour Energy Inc. by Invico Performance Yield Fund Limited Partnership ("Invico"), shall be utilized as follows:


  a.

full repayment of the principal plus interest balance outstanding under Credit Facility B on or before June 30, 2013.


NEGATIVE  
COVENANTS:

No Loan Party shall, without the prior approval of the Bank (each of the following being a " Negative Covenant "):


  4.

incur further secured indebtedness, pledge or encumber assets, or guarantee the obligations of others. Notwithstanding the foregoing, the following security is permitted in support of secured indebtedness owed by Dejour Energy Inc. to Invico:



4

  a.

guarantee provided by the Borrower and Dejour Energy (USA) Corp. to Dejour Energy Inc.;

     
  b.

$3,500,000 Debenture with a second floating charge over all assets of the Dejour Energy Inc. (second security interest in personal property); and

     
  c.

$3,500,000 First Charge Mortgage, Assignment of Production, Security Agreement and Financing Statement over all the assets of Dejour Energy (USA) Corp., including fixed charges over the Kokopelli lease or leases as the case maybe.


REVIEW:

Without detracting from the demand nature of the Credit Facilities, the Credit Facilities are subject to periodic review by the Bank periodically in its sole discretion (each such review is referred to in this Commitment Letter as a "Review") and at a minimum will be reviewed on an annual basis. The next interim Review is scheduled on or before November 1, 2013, and the next annual Review is scheduled on or before June 1,2014, but either may be set at an earlier or later date at the sole discretion of the Bank.

 

EXPIRY DATE:

This Commitment Letter is open for acceptance until June 10, 2013 (as may be extended from time to time as follows, the "Expiry Date") at which time it shall expire unless extended by mutual consent in writing. We reserve the right to cancel this Commitment Letter at any time prior to acceptance.

- intentionally left blank -


5

If the foregoing terms and conditions are acceptable, please sign two copies of this Commitment Letter and return one copy to the Bank by the Expiry Date. This Commitment Letter may be executed in any number of counterparts and delivered by facsimile or other electronic copy, each of which when executed and delivered shall be deemed to be an original, and such counterparts together shall constitute one and the same agreement.


6

APPENDIX A

CREDIT: Terri Lawrence, Doug Clark  
  Sr. Account Manager, Senior AVP & Manager,  
  Energy Lending Group Energy Lending Group  
       
  Direct: (403) 268-7847 Direct: (403) 750-3581  
  Cell: (403) 990-6083 Cell: (403) 880-1882  
  Facsimile: (403) 264-1619 Facsimile: (403) 264-1619  
  Email: TerrLLawrence@cwbank.com Email: Doug.Clark@cwbank.com
       
ADMINISTRATION: UC/Gs; Visa; Loan / Account Account Representative: Monique Thompson
  Balances; Payments; Bank Drafts; Telephone: (403) 268-7841
  Bank Confirmations; General Facsimile: (403) 750-3596
    E-mail: Monique.Thompson@cwbank.com
       
    Account Representative: Mayra Mercado O'Brien
    Telephone: (403) 750-3583
    Facsimile: (403) 750-3596
    E-mail: Mayra.Mercado@cwbank.com
       
BRANCH: Calgary Main Branch Telephone: (403) 262-8700
  #100,606 - 4 Street SW Facsimile: (403) 262-4899
  T2P 1Tl    
       
BUSINESS Order Cheques; Current Account Account Representative: Anita Latif
ACCOUNTS Documents/ Operations; Signing Telephone: (403) 750-3576
  Authorities; Rates; Investments; Facsimile: (403) 750-4899
  Customer Automated Funds Transfer E-mail Anita.Latif@cwbank.com
  (CAFT)    
       
INTERNET Loan/Account Balances; Traces; Stop Website: www.CWBANK.com
BANKING Payments, List of Current Account    
  Transactions; Pay Bills; Transfer    
  Between Accounts; Exchange Rates    
  Quotes    
       
OTHER: Persona/Retail Banking Manager: William Lee
    Telephone: (403) 268-7842
    Facsimile: (403) 262-4899
    E-mail: William. Lee@cwbank.com
       
       
       
VALIANT TRUST: Corporate Trust Services; Stock Website: www.VALIANTTRUST.com
  Transfer Agent; Employee Incentive Contact: Les Stastook
  Plans   Director, Business Development
    Telephone: (403) 781-8754
    Cell: (403) 818-6244
    Facsimile: (403) 233-2857
    E-mail: Les.Stastook@valianttrust.com




June 7, 2013

Dejour Energy (Alberta) Ltd.
c/o Dejour Energy Inc.
#598 - 999 Canada Place
Vancouver, BC V6C 3El

ATTENTION: Mr. David Matheson Mr. Robert Hodgkinson
  Chief Financial Officer Co-Chairman and CEO

Dear Sirs:

RE: SUBORDINATION AGREEMENT

Permitted Payments of the Loan Payable to Dejour Energy Inc. ("DEI") by Dejour Energy (Alberta) Ltd. ("DEAL") are outlined under Section 10 in the Subordination Agreement dated September 7, 2011.

DEAL was in default of item (i) under Section 10 with a non-compliant Adjusted Working Capital Ratio as at March 31, 2013, and is in default of item (iii) under Section 10 with Credit Facility B requiring full repayment by June 30, 2013. All interest payments to DEI are hereby suspended pending (a) full repayment of Credit Facility B and (b) satisfactory evidence of a compliant Adjusted Working Capital Ratio as at June 30, 2013.

 

 

Suite 200, 606 - 4 Street S.W. Calgary, Alberta T2P 1T1 TELEPHONE (403) 750-3599 FAX (403) 264-1619



June 11,2013

Dejour Energy Inc.
#598 - 999 Canada Place
Vancouver, BC
V6C 3EI

Attention: Mr. David Matheson, Chief Financial Officer

Dear David,

Re:        Loan Facility

Invico Performance Yield Fund Limited Partnership C'Invico") has agreed to provide you with a loan in the amount of $3,500,000 in Canadian funds, and such other advances as Invico may, without obligation, choose to make in accordance with, and subject to the terms and conditions precedent set forth herein (the "Loan Facility").

Upon execution hereof, this Commitment Letter shall create binding obligations between the parties, provided that, unless and until the Conditions Precedent shall have been satisfied, Invico shall be under no obligation to make any advance under the Loan Facility.

Terms of the Loan Facility and Conditions Precedent

Borrower(s): Dejour Energy Inc. (the "Borrower")
   
Guarantor(s): Dejour Energy (Alberta) Ltd. ("Dejour Alberta")
   
Dejour Energy (USA) Corp. (the "US Guarantor" and together, the "Guarantors")
   
Lender: Invico
   
Canadian Lender: Canadian Western Bank (the "Canadian Lender")
   
Canadian Lender Amount: Maximum amount of $3,500,000 in Canadian funds.
   
Loan Facility: CAD $3,500,000 non-amortizing, non-revolving Term Facility (the "Loan")

Page 1 of 12

Dejour Commitment Letter



Purpose:

The First Advance shall be used to repay and cancel "Credit Facility B" (or any replacement or substitution thereof) as described in the commitment letter dated March 25, 2013 between the Canadian Lender and Dejour Alberta. The Second Advance shall be made and used for the purpose of the US Guarantor to fund its drilling programs in the KokopelJi region and to fund the US Guarantor's working capital requirements.

 

 

Avai lability of advances and
Funding Date

Subject to satisfaction of the Conditions Precedent, the Loan Facility will be available in two advances of $2,500,000 (the "First Advance") and $1,000,000 (the "Second Advance") respectively, each available upon satisfaction of the Conditions Precedent at the time of advance. Invico and the Borrower shall make reasonable commercial efforts to have the First Advance available on or before June 17, 2013 and the Second Advance available on or before July 22, 2013.

 

 

The Borrower's obligation to pay interest to Invico in respect of the Loan or any portion thereof shall commence upon the date that Invico has: (i) funded the applicable amount into the trust account of Invico's solicitor; (ii) confinned that the due diligence condition has been satisfied or otherwise waived; and (iii) the Loan Documents to be prepared by Invico's solicitor have been provided to the Borrower for execution (the "Funding Date").

 

 

The Borrower's obligation to pay interest shall commence notwithstanding that the funds, or any portion thereof cannot be released to the Borrower due to the inability of the Borrower to satisfy the "Conditions Precedent" to advance of the funds.

 

 

Interest Rate:

14% per annum, payable monthly in arrears.

 

 

Repayment:

The Borrower shall make interest payments and repay the Loan in accordance with the payment schedule attached hereto as Schedule "A"; provided that Invico may, at its option and upon making any future advance, provide the Borrower with an updated payment schedule.

Page 2 of 12

Dejour Commitment Letter



Maturity Date:

December 22,2014.

   
Prepayment:

No prepayment permitted prior to six months from the First Advance. Post six months, prepayment is permitted with two months advance notice.

   
Warrant Coverage:

In addition to the repayment of principal and interest on the Loan, at the time of the First Advance, the Borrower shall grant to the Lender warrants (the "Warrants"), each to purchase one common share in the capital of the Borrower (a "Common Share") for a purchase price equal to the Exercise Price (as defined below) as follows:

   

Number of Warrants: Such number of Warrants as is, at the date of funding the first advance, equivalent to fifty percent (50%) of the fully funded Loan amount of$3,500,000 divided by the Exercise Price.

   

The Common Shares purchased pursuant to the exercise of the Warrants shall be freely tradeable upon their issuance and shall be free from any restrictions on trading other than the hold period imposed by applicable securities legislation.

   

The Warrants shall not expire prior to the date that is two (2) years after the date that the second advance is made to the Borrower.

   

For the purpose of the Warrants, the "Exercise Price" shall be equal to the volume weighted average trading price of the Common Shares for the ten ( 10 ) days (the " 10  Day VWAP ") immediately preceding the date 'of funding the First Advance, plus a premium of 20%.

   

The tenns of the Warrants shall include: (i) typical adjustment provisions to adjust the number of Warrants and the Exercise Price in the event of any share consolidation, recapitalization, reclassification, or similar transaction or reorganization of share capital; (ii) provisions allowing exercise in the event of any change in control, business combination or other transaction involving the Borrower; and (iii) price protection to be granted to Invico in the event that, within six (6) months of the date of the First Advance, additional Common Shares of the Borrower are issued at a price lower than the 10 Day VWAP.

Page 3 of 12

Dejour Commitment Letter



Due Diligence Fees and Deposit:

Fees: lnvico acknowledges receipt of the Due Diligence Fee (as referred to in the Indicative Term Sheet) of$15,000.

   

Deposit: lnvico acknowledges receipt by lnvico's solicitor of a deposit on legal fees of $15,000 paid into trust to the account set forth in Schedule "B" hereto.

   
Failure to Complete Conditions Precedent:

If, subsequent to the Funding Date, the Borrower fails, within thirty (30) calendar days, to complete all Conditions Precedent required to enable the funds to be released from trust to the Borrower, then Invico shall be entitled to instruct its solicitor to return all funds to Invico.

   

Notwithstanding the foregoing, the Borrower shall be obligated to pay any accrued interest since the Funding Date, earned fees and other expenses to Invico in respect of the Loan.

   
Payment of Set Up Fees and Expenses:

Regardless as to whether advances are released to the Borrower, the Borrower shall be responsible for: (i) any reasonable out of pocket costs, including due diligence costs, incurred by lnvico; and (ii) legal costs of Invico, in each case . on a full indemnity basis, which expenses shall be payable at the Funding Date, and from time to time, as Invico may require.

   
Fees and Expenses:

Invico shall, at the time of making any advance, be entitled to withhold as payment therefor, any set up fees, legal expenses or other expenses owed to it by the Borrower.


Security and other documents to be
executed, delivered and

Provision to Invico of:

registered (the "Loan I)

Executed loan agreement in lnvico's standard form (the "Loan Agreement").

Documents")    
  2)

Grid Promissory Note for $3,500,000.

     
3)

Executed guarantees, in Invico's standard form from each Guarantor.

     
4)

General Security Agreement providing a security interest over all present and after acquired personal and real property of the Borrower and Dejour Alberta and confirmation that Invico is in second place only to the Canadian Lender.

Page 4 of 12

Dejour Commitment Letter



  5)

General Security Agreement providing a first priority security interest over all present and after acquired personal and real property ofthe US Guarantor.

     
  6)

Assignment and Postponement Agreement by the Borrower in favour of Invico in respect of all indebtednesses to it of the US Guarantor.

     
  7)

Intercreditor agreement among Invico the Canadian Lender and the Borrower on tenns satisfactory to Invico.

     
  8)

Deed of trust and security interest registered against two Kokopelli leases, specifically the following (the "Leases"):

Serial Number: COC-066370
Effective Date: 12/01/2002
Lessor: USA Federal DOI-BLM
Land Description:
Township 6 South, Range 91 West of the 6th P.M.
Section 21: EI/2NE1I4, SE1/4SW1/4, SW1I4SEI/4
Section 22: SW1/4NW1I4, WI/2SW1I4,SEI/4SW1/4
Section 25: SWI/4SW1I4
Section 26: S112
Containing 680.00 acres, more or less in Garfield County, CO

Serial Number: COC-065531
Effective Date: 12/01/200 I
Lessor: USA Federal DOI-BLM
Land Description:
Township 6 South, Range 91 West of the 6th P.M.
Section 13: Wl/2SWI/4;
Section 14: SI/2;
Section 15: NWI/4NWI/4, SW 1I4NElI4,NE1I4NW 1/4
       WI/2NWI/4, SEl/4NWI/4, Nl/2SWI/4, SE1/4;
Section 23: NEI/4, Nl/2NWI/4;
Section 24: NE1I4NE1I4, W1INEII4, NWI/4, Nl/2SEI/4
Section 25: SEl/4SEI/4
Containing 1,520.00 acres, more or less, in Garfield County, CO

  9)

Invico shall have been provided with a certificate in form satisfactory to it and its solicitors in respect of the Warrants.

Page 5 of 12

Dejour Commitment Letter



 

 

     
  10)

Opinion including title opinion on the Leases from the Borrower's and Guarantor's solicitors in form satisfactory to Invico and its solicitor.

     
  11)

Such other security as Invico and its solicitors may reasonably require.


Conditions Precedent:

Notwithstanding the making of any prior advance of the Loan, or the advance of any portion thereof to the trust account of Invico's Solicitor and the accumulation of interest on the Loan as of the Funding Date, said funds will not be released to the Borrower unless and until the following conditions precedent (the "Conditions Precedent") have been completed, or Invico has otherwise expressly authorized the release of funds in writing:


  1)

Completion of all due diligence including confirmation of asset value.

     
  2)

A consent from the Canadian Lender to the making of the Loan and completion of the transactions described herein.

     
  3)

Execution and delivery of the Loan Documents, including closing certificates, and corporate resolutions, satisfactory to Invico.

     
  4)

All securities commISSIons, stock exchanges and other regulatory approvals shall have been obtained in connection with the transactions contemplated herein.

     
  5)

Registration and perfection by Invico of all security interests and charges granted pursuant to the Loan Documents.

     
  6)

Such other documents, instruments and security as Invico shall determine are necessary in connection with the completion of its due diligence.

     
  7)

Invico shall be satisfied with the appraised value of the Borrower's and Guarantors' assets in the United States.


Reporting Conditions:

In addition to such information as shall be required to be provided pursuant to the Loan Agreement, the Borrower shall furnish the following reports to lnvico:

Page 6 of 12

Dejour Commitment Letter



  1)

Annual non-consolidated and consolidated audited statements of the Borrower to be provided within 120 days of year end.

   

 

  2)

Annual unconsolidated financial statements of the Guarantors to be provided within 120 days of year end.

   

 

  3)

Quarterly interim statements of the Borrower and the Guarantors to be provided within 60 days of quarter end.

   

 

  4)

Quarterly aged listing of receivables to be received within 30 days of quarter end.

   

 

  5)

Quarterly aged listing of payables to be received within 30 days of quarter end.

   

 

  6)

Annual Engineering Reserve Report completed by a firm at the choice of the Borrower and acceptable to lnvico in compliance with National Instrument 51- 10 I - Standards of Disclosure for Oil and Gas Activities on the petroleum and natural gas reserves of the US Guarantor to be provided within 120 days of the Borrower's year end.

   

 

  7)

Annual and quarterly compliance certificate and certificate of no default to be provided within 120 days of fiscal year end, and 60 days of quarter end respectively.

   

 

  8)

Quarterly commodity hedging summary.

   

 

  9)

All TSX and other regulatory filings with respect to the Loan Facility, and all other public disclosures or press releases.

   

 

  10)

Other information regarding the financial position and assets as lnvico may reasonably request.


Additional Covenants:

In addition to the covenants of the Borrower and the Guarantors, as shall be set forth in the Loan Agreement, each Borrower and Guarantors further covenants that:


  1)

The Borrower and Guarantors shall not incur any indebtedness other than: (i) to the Canadian Lender in an amount not to exceed the Canadian Lender Amount; (ii) pursuant to the Loan Facility; or (ii) IIPermitted Encumbrances" as described below.

Page 7 of 12

Dejour Commitment Letter



  2)

The following may not be completed without Invico's prior written consent:


  a)

any merger, acquisition, reorganization, arrangement, asset disposition, or transfer of property, provided that Invico shall not unreasonably withhold its consent to any transaction, prior to, or concurrent with the consummation of which, and subject to the prepayment conditions hereof, Invico receives repayment of the Loan in full;

     
  b)

any change in the nature of the business;

     
  c)

payment of any dividend, distribution, bonus, or indebtedness (other than to the Canadian Lender or Invico) or return on capital; or

     
  d)

any grant to any third party of any gross overriding royalty or other rights or charge over the assets or petroleum produced.


  3)

From and after September 30, 2013, the US Guarantor shall maintain an Adjusted Working Capital Ratio of greater than 1.0, calculated as the US Guarantor's Current Assets divided by Current Liabilities, provided that Current Liabilities shall not include any amount of liability pursuant to the Bakken Drilling Fund.

     
  4)

There shall be no change in the senior management team of the Borrower without Invico's prior written consent, which consent, may, for greater certainty be arbitrarily withheld in the case of any change involving David Matheson and Robert Hodgkinson.


Permitted Encumbrances:

Liens and security interests granted to secured parties for the purpose of leasing or financing the acquisition of equipment in connection with the grant of a "purchase money security interest" not to exceed $100,000 in the aggregate on a consolidated basis for the Borrower and the Guarantors.

 

The US Guarantor has a contingent liability of not more than USD $6,500,000 pursuant to a pre~existing contract in respect of its drilling program as previously disclosed to the Lender (the "Bakken Drilling Fund").

Page 8 of 12

Dejour Commitment Letter



Representations and Warranties:

In addition to the representations and warranties of the Borrower and the Guarantors, as shall be set forth in the Loan Agreement, each Borrower and Guarantor further represents that the execution and delivery by it of this Commitment Letter and the performance by it of its obligations hereunder have been duly authorized by all necessary corporate action and do not conflict with the terms of any other agreement document or instrument by which it is bound.

   
Notice to be provided to Invico 300, 116 8 th Avenue SW
at: Calgary, AB
  T2P lB3

Attn:                Jason Brooks
Telecopier:     (403) 5384770
Email:                jwbrooks@invicocapital.com

Notice to be provided to #598 - 999 Canada Place
Borrower(s) at: Vancouver, B.C. V6C 3El

Attn:                David Matheson
Telecopier:     (604) 638-5051
Email:              dmatheson@dejour.com

Confidentiality:

This Commitment Letter, the Schedules hereto, and, when executed and delivered the Loan Documents and the contents therein are confidential and may not be disclosed by any party hereto to any third party except with the written consent of the other pal1ies, provided that each party consents to the disclosure hereof to the Canadian Lender for the purpose of obtaining its consent.

   
Acceptance:

This Commitment Letter will remain open for acceptance until 5:00 pm Mountain Daylight Time June 12,2013.

This Commitment Letter may be executed in any number of counterparts and by different parties in separate counterparts, each of which when so executed shaH be deemed to be an original and all of which taken together shaH constitute one and the same instrument.

If the foregoing terms and conditions are acceptable, please sign both copies of this Commitment Letter and return one copy to Invico by the expiry date, along with your cheque to cover the legal deposit and due diligence fees.

[SIGNATURE PAGE FOLLOWS]

Page 9 of 12

Dejour Commitment Letter 


GUARANTORS:



Page 10 of 12

Dejour Commitment Letter


SCHEDULE "A"

Dejour Energy    
     
Interest Period Interest Rate 0.14

    Number of Principal              
2013   Days     Outstanding     Interest Due  
June 17 - July 21   34   $  2,500,000.00   $  32,602.74  
Principal Adv.ance July 22       $  1,000,000.00        
July 22 - August 21   31   $  3,500,000.00   $  41,616.44  
August 22- September 21   31   $  3,500,000.00   $  41,616.44  
Septerrber 21 - October 21   30   $  3,500,000.00   $  40,273.97  
October 22 - November 21   31   $  3,500,000.00   $  41,616.44  
November 22 - December 21   30   $  3,500,000.00   $  40,273.97  
2014                  
December 22 - January 21   31   $  3,500,000.00   $  41,616.44  
January 22 - February 21   31   $  3,500,000.00   $  41,616.44  
February 22 - March 21   28   $  3,500,000.00   $  37,589.04  
March 22 - April 21   31   $  3,500,000.00   $  41,616.44  
April 22 - May 21   30   $  3,500,000.00   $  40,273.97  
May 22 - June 21   31   $  3,500,000.00   $  41,616.44  
June 22 - July 21   30   $  3,500,000.00   $  40,273.97  
July 22 - August 21   31   $  3,500,000.00   $  41,616.44  
August 22- September 21   31   $  3,500,000.00   $  41,616.44  
SepterT'ber 21 - October 21   30   $  3,500,000.00   $  40,273.97  
October 22 - November 21   31   $  3,500,000.00   $  41,616.44  
Noverrber 22 - December 22   31   $  3,500,000.00   $  41,616.44  
Principal Repayment       $  (3,500,000.00 )      

Page 11 of 12

Dejour Commitment Letter


SCHEDULE "B"

Wiring Instructions to Bennett Jones LLP CAD Trust Account - Calgary

Beneficiary Name: Bennett Jones LLP, in trust
  4500 Bankers Hall East, 855 2nd Street SW
  Calgary, Alberta T2P 4K7
   
Beneficiary Bank Name: Royal Bank of Canada
  339 - 8th Avenue SW
  Calgary, Alberta
  Canada, T2P 1C4

Bank Number: 003
Transit Number: 00009
Beneficiary Account No: 172-596-9
Swift Code: ROYCCATI
ABA Routing Number: 021 000021

Please note the following particulars:

I. When wiring from the U.S., please indicate:
     
  a. Bennett Jones LLP, in trust as the beneficiary; and
     
  b. CAD account number 00009-172-596-9.
     
2. Please also indicate: Attention: Richard Stone

Page 12 of 12

Dejour Commitment Letter




Oejour Energy (USA) Corp.
a subsidiary of Oejour Energy Inc.
1401 1ih St., Ste. 850
Denver, CO 80202
P: (303) 296-3535
F: (303) 296-3888

September 10,2013

Randall Kenworthy
Bakken Drilling Fund III Manager LLC
5251 DTC Parkway, Suite 200
Denver, CO 80111

Re:

Second Amendment to Operating Agreement dated December 31, 2012 by and between Dejour Energy (USA) Corp. and Bakken Drilling Fund III, L.P.; Garfield County, Colorado

Dear Mr. Kenworthy:

             Dejour Energy (USA) Corp. ("Dejour") and Bakken Drilling Fund III, L.P. ("Bakken") are parties to that certain Operating Agreement dated December 31, 2012, as amended by the Amendment to Operating Agreement dated March 6, 2013 (the "lOA"). The parties hereby agree to further amend the lOA as follows:

             1.        Article XVI.B(i) of the lOA is amended by deleting "$6,500,000" in the first line thereof and replacing it with "$7,000,000".

             2.        Article XVI.C(iii) of the lOA is amended by deleting "$15,000,000" in the second line thereof and replacing it with "$15,500,000".

             3.        Article XVI.F. is amended by, in the first line thereof, deleting "125%" and replacing it with "150%".

             4.         Exhibit "A" to the lOA is amended by deleting Paragraph (3) III its entirety and replacing it with the following:

             (3)        Percentages of Working Interest of the Parties:

  Party Percentage Interest
  Dejour Energy (USA) Corp. 22.229%
     
  Bakken Drilling Fund III, LP 77.771%

             5.        All other provisions of the lOA remain unchanged and in full force and effect.


            This letter may be executed in any number of counterparts, each of which when so executed shall constitute in the aggregate but one and the same document. Copies or facsimiles of signatures to this letter have the same effect as if the signatures were placed on the originals and shall be deemed to be fully executed by each signatory.

             If you are in agreement with the above amendments to the lOA, please so indicate by signing in the space provided on the next page and returning an executed, notarized copy to Dejour.

Very Truly Yours,

DElOUR ENERGY (USA) CORP.  

 
  Harrison F. Blacker, President

STATE OF COLORADO §  
  §  
CITY AND COUNTY OF DENVER §  

             This instrument was acknowledged before me this 10th day of September. 2013 by Harrison F. Blacker, as President of Dejour Energy (USA) Corp.

              WITNESS my hand and official seal.  

 
  Notary Public, State of Colorado

2


 

3





December 16, 2013

Dejour Energy (Alberta) Ltd.
c/o Dejour Energy Inc.
#598 - 999 Canada Place
Vancouver, BC V6C 3E1

ATTENTION: Mr. David Matheson Mr. Robert Hodgkinson
  Chief Financial Officer Co-Chairman and CEO

Dear Sirs:

RE: CREDIT FACILITIES - CANADIAN WESTERN BANK I DEJOUR ENERGY (ALBERTA) LTD.

We are pleased to advise that Canadian Western Bank has approved the following amended Credit Facilities for Dejour Energy (Alberta) Ltd., subject to the terms and conditions of the accepted Commitment Letter dated March 25,2013 and the amending Commitment Letter dated June 5, 2013, which terms and conditions will remain in full force and effect, as amended below.

BORROWER:

DEJOUR ENERGY (ALBERTA) LTD. (the " Borrower ").

   
GUARANTOR:

DEJOUR ENERGY INC. and DEJOUR ENERGY (USA) CORP. (collectively the " Guarantor ").

   

The Borrower and the Guarantor are collectively referred to as " Loan Parties ", and each, a " Loan Party ".

   
LENDER:

CANADIAN WESTERN BANK (the " Bank ").

 

CREDIT FACILITY A:

REVOLVING REDUCING OPERATING DEMAND LOAN (the " Credit Facility A ").

   
MAXIMUM AMOUNT:

$3,500,000. (the "Availability A")

 

AVAILABILITY:

Prime Rate Loan ("Prime Rate Loan"). Revolving in whole multiples of $50,000.

   

All amounts outstanding under this Credit Facility A are payable on demand and subject to the Bank's right to make such demand at any time.

   

In the event the proposed acquisition from Arduro Energy ("Arduro") does not proceed, Availability A will reduced by $300,000 to $3,200,000 effective February 1, 2014 and $100,000 per month thereafter on the first of each month beginning March 1, 2014.

   

In the event the Arduro acquisition proceeds, Availability A will reduce by $100,000 per month on the first of each month beginning March 1, 2014.

 

 

Suite 200, 606 - 4 Street S.W. Calgary, Alberta T2P 1T1 TELEPHONE (403) 750-3599 FAX (403) 264-1619


2

SECURITY:

The following security (the "Existing Security") has been completed, duly executed, delivered, perfected and registered, where necessary, to the entire satisfaction of the Bank and its counsel.


  1.

$10,000,000 Debenture with a first floating charge over all assets of the Borrower (first security interest in personal property) with an undertaking to provide fixed charges on the Borrower's petroleum and natural gas properties at the request of the Bank, and pledge of such Debenture;

     
  2.

Supplemental Debenture with fixed charges on the Borrower's Drake/Woodrush, BC petroleum and natural gas property;

     
  3.

Revolving Credit Agreement in the amount of $3,700,000 by the Borrower;

     
  4.

General Assignment of Book Debts by the Borrower;

     
  5.

evidence of insurance coverage in accordance with industry standards designating the Bank as first loss payee in respect of the proceeds of the insurance and an additional insured;

     
  6.

appropriate title representation from the Borrower (officer's certificate as to title) including a schedule of petroleum and natural gas reserves described by lease (type, date, term, parties), legal description (wells and spacing units), interest (working interest or other APOIBPO interests), overrides (APOIBPO), gross overrides, and other liens, encumbrances, and overrides;

     
  7.

evidence of extra-provincial registrations of the Borrower where applicable;

     
  8.

Full Liability Guarantee provided by Dejour Energy Inc. supported by:


  a)

$10,000,000 Debenture with a first floating charge over all assets of the Dejour Energy Inc. (first security interest in personal property) with an undertaking to provide fixed charges on the Dejour Energy Inc.'s petroleum and natural gas properties at the request of the Bank, and pledge of such Debenture;


  9.

Subordination/Postponement Agreement regarding loan payable to Dejour Energy Inc.;

     
  10.

Unlimited Guaranty Agreement provided by Dejour Energy (USA) Corp. supported by:


  a.

Second Charge Mortgage, Assignment of Production, Security Agreement and Financing Statement; and


  11.

legal opinion of the Bank's counsel.

The following security (the "Additional Security") shall be completed, duly executed, delivered, perfected and registered, where necessary, to the entire satisfaction of the Bank and its counsel, and shall form part of the Security.

  1.

Commitment Letter dated December 16, 20l3; and

     
  2.

such other security, documents, and agreements that the Bank or its legal counsel may reasonably request.



3

The Existing Security and Additional Security (together the "Security") to be perfected/registered, at a minimum, in the Province of Alberta and British Columbia in a first priority position, and in a second position in such jurisdictions in the United States as required, subject only to Permitted Encumbrances. All present and future Security shall be held by the Bank as continuing security for all present and future debts, obligations and liabilities (whether direct or indirect, absolute or contingent) of the Loan Parties to the Bank including without limitation for the repayment of all loans and advances made herein and for other loans and advances that may be made from time to time in the future whether herein or otherwise. The Security shall be in form and substance satisfactory to the Bank and its counsel.

REPRESENTATIONS

AND WARRANTIES:

Each Loan Party represents and warrants to the Bank (all of which representations and warranties each Loan Party hereby acknowledges are being relied upon by the Bank in entering into this Commitment Letter) that:


  5.

there has been no adverse material change in the financial position of any Loan Party since the date of its most recent consolidated and non-consolidated financial statements dated September 30, 2013 which were furnished to the Bank. Such financial statements fairly present the financial position of each Loan Party at the date that they were drawn up.


CONDITIONS  
PRECEDENT:

Prior to each advance under the Credit Facilities, the Borrower shall have provided, executed or satisfied the following, to the Bank's satisfaction (collectively with all other conditions precedent set out in this Commitment Letter, called the " Conditions Precedent "):


  1.

all Additional Security shall be duly completed, authorized, executed, delivered by each Loan Party which is a party thereto, and perfected and registered, all to the satisfaction of the Bank and its counsel;

     
  2.

no further Default or Event of Default shall exist;

     
  3.

no Material Adverse Effect has occurred with respect to any Loan Party or the Security;

     
  4.

all representations and warranties of each Loan Party shall be true and correct; and

     
  5.

any other document that may be reasonably requested by the Bank.


The above conditions are inserted for the sole benefit of the Bank, and may be waived by the Bank in whole or in part (with or without terms or conditions) in respect of any particular Advance, provided that any waiver shall not be binding unless given in writing and shall not derogate from the right of the Bank to insist on the satisfaction of any condition not expressly waived in writing or to insist on the satisfaction of any condition waived in writing which may be requested in the future.

 

REVIEW:

Without detracting from the demand nature of the Credit Facilities, the Credit Facilities are subject to periodic review by the Bank periodically in its sole discretion (each such review is referred to in this Commitment Letter as a "Review") and at a minimum will be reviewed on an annual basis. The Annual Review is scheduled on or before May 1, 2014, but may be set at an earlier or later date at the sole discretion of the Bank.

 

EXPIRY DATE:

This Commitment Letter is open for acceptance until December 23, 2013 (as may be extended from time to time as follows, the "Expiry Date") at which time it shall expire unless extended by mutual consent in writing. We reserve the right to cancel this Commitment Letter at any time prior to acceptance.



4

If the foregoing terms and conditions are acceptable, please sign two copies of this Commitment Letter and return one copy to the Bank by the Expiry Date. This Commitment Letter may be executed in any number of counterparts and delivered by facsimile or other electronic copy, each of which when executed and delivered shall be deemed to be an original, and such counterparts together shall constitute one and the same agreement.



5

APPENDIX A

CREDIT: Tracey M. Schultz Doug Clark  
  Manager, Senior AVP & Manager,  
  Energy Lending Group Energy Lending Group  
       
  Direct: (403) 750-3595 Direct: (403) 750-3581  
  Cell: (403) 993-0716 Cell: (403) 880-1882  
  Facsimile: (403) 264-1619 Facsimile: (403) 264-1619  
  Email: Tracey.Schultz@cwbank.com Email: Doug.Clark@cwbank.com
       
ADMINISTRATION: LlC/Gs; Visa; Loan / Account Account Representative: Monique Thompson
  Balances; Payments; Bank Drafts; Telephone: (403) 268-7841
  Bank Confirmations; General Facsimile: (403) 750-3596
    E-mail: Monique.Thompson@cwbank.com
       
    Account Representative: Mayra Mercado O'Brien
    Telephone: (403) 750-3583
    Facsimile: (403) 750-3596
    E-mail: Mayra.Mercado@cwbank.com
       
BRANCH: Calgary Main Branch Telephone: (403) 262-8700
  #100, 606 - 4 Street SW Facsimile: (403) 262-4899
  T2P 1T1    
       
BUSINESS Order Cheques; Current Account Account Representative: Anita Latif
ACCOUNTS Documents/ Operations; Signing Telephone: (403) 750-3576
  Authorities; Rates; Investments; Facsimile: (403) 750-4899
  Customer Automated Funds Transfer E-mail Anita.Latif@cwbank.com
  (CAPT)    
       
INTERNET Loan/Account Balances; Traces; Stop Website: www.CWBANK.com
BANKING Payments, List of Current Account    
  Transactions; Pay Bills; Transfer    
  Between Accounts; Exchange Rates    
  Quotes    
       
OTHER: Personal/Retail Banking Manager: William Lee
    Telephone: (403) 268-7842
    Facsimile: (403) 262-4899
    E-mail: William. Lee@cwbank.com
       
       
       
VALIANT TRUST: Corporate Trust Services; Stock Website: www.VALIANTTRUST.com
  Transfer Agent; Employee Incentive Contact: Les Stastook
  Plans   Director, Business Development
    Telephone: (403) 781-8754
    Cell: (403) 818-6244
    Facsimile: (403) 233-2857
    E-mail: Les.Stastook@valianttrust.com



February 18, 2014

 

Dejour Energy (Alberta) Ltd.
c/o Dejour Energy Inc.
#598 – 999 Canada Place
Vancouver, BC V6C 3E1

 

ATTENTION: Mr. David Matheson Mr. Robert Hodgkinson
  Chief Financial Officer Co-Chairman and CEO

Dear Sirs:

RE: CREDIT FACILITIES – CANADIAN WESTERN BANK / DEJOUR ENERGY (ALBERTA) LTD.

We are please to advise that Canadian Western Bank has approved the following amended Credit Facilities for Dejour Energy (Alberta) Ltd., subject to the terms and conditions of the accepted Commitment Letter dated March 25, 2013 and the amending Commitment Letters dated June 5, 2013, December 16, 2013 and January 28, 2014, which terms and conditions will remain in full force and effect, as amended below.

BORROWER :

DEJOUR ENERGY (ALBERTA) LTD, (the “ Borrower ”).

   
GUARANTOR :

DEJOUR ENERGY INC. and DEJOUR ENERGY (USA) CORP. (collectively the “ Guarantor ”).

   
LENDER :

CANADIAN WESTERN BANK (the Bank ”).

   
CREDIT FACILITY A :

REVOLVING REDUCING OPERATING DEMAND LOAN (the “ Credit Facility A ”).

   
MAXIMUM AMOUNT :

$3,500,000. (the “Availability A”)

   
AVAILABILITY :

Prime Rate Loan (“Prime Rate Loan”). Revolving in whole multiples of $50,000.

   

All amounts outstanding under this Credit Facility A are payable on demand and subject to the Bank’s right to make such demand at any time.

   

In the event the proposed acquisition from Aduro Resources Ltd. (“Aduro) does not proceed by March 31, 2014, Availability A will reduce by $300,000 effective April 1, 2013 or earlier, upon the Borrower advising the Bank that the Aduro acquisition will not proceed. Availability A will still reduce by $100,000 per month on the first of each month beginning March 1, 2014.

Suite 204, 606 – 4 Street S.W., Calgary, Alberta T2P 1T1 TELEPHONE (403) 750-3599 FAX: (403) 264-1619                


2

SECURITY :

The following security (the “Existing Security”) has been completed, duly executed, delivered, perfected and registered, where necessary, t the entire satisfaction of the Bank and its counsel.


  1.

$10,000,000 Debenture with a first floating charge over all assets of the Borrower (first security interest in personal property) with an understanding to provide fixed charges on the Borrower’s petroleum and natural gas properties at the request of the Bank, and pledge of such Debenture;

     
  2.

Supplemental Debenture with fixed charges on the Borrower’s Drake/Woodrush, BC petroleum and natural gas property;

     
  3.

Revolving Credit Agreement in the amount of $3,700,000 by the Borrower;

     
  4.

General Assignment of Book Debts by the Borrower;

     
  5.

evidence of insurance coverage in accordance with industry standards designating the Bank as first loss payee in respect of the proceeds of the insurance and an additional insured;

     
  6.

appropriate title representation from the Borrower (officer’s certificate as to title) including a schedule of petroleum and natural gas reserves described by lease (type, date, term, parties), legal description (wells and spacing units), interest (working interest or other APO/BPO interests), overrides (APO/BPO), gross overrides, and other liens, encumbrances, and overrides;

     
  7.

evidence of extra-provincial registrations of the Borrower where applicable;

     
  8.

Full Liability Guarantee provided by Dejour Energy Inc. supported by:


  a)

$10,000,000 Debenture with a first floating charge over all assets of the Dejour Energy Inc. (first security interest in personal property) with an undertaking to provide fixed charges on the Dejour Energy Inc.’s petroleum and natural gas properties at the request of the Bank, and pledge of such Debenture;


  9.

Subordination/Postponement Agreement regarding loan payable to Dejour Energy Inc.;

     
  10.

Unlimited Guaranty Agreement provided by Dejour Energy (USA) Corp. supported by:


  a)

Second Charge Mortgage, Assignment of Production, Security Agreement and Financing Statement; and


  11.

legal opinion of the Bank’s counsel.

The following security (the “Additional Security”) shall be completed, duly executed, delivered, perfected and registered, where necessary, to the satisfaction of the Bank and its counsel, and shall form part of the Security.

  1.

Commitment Letter dated February 18, 2014; and



3

  2.

such other security, documents, and agreements that the Bank or its legal counsel may reasonably request.


The Existing Security and Additional Security (together the “ Security ”) to be perfected/registered, at a minimum, in the Province of Alberta and British Columbia in a first priority position, and in the second position in such jurisdictions in the United Stated as required, subject only to Permitted Encumbrances. All present and future Security shall be held by the Bank as continuing security for all present and future debts, obligations and liabilities (whether direct or indirect, absolute or contingent) of the Loan Parties to the Bank including without limitation for the repayment of all loans and advances made herein and for other loans and advances that may be made from time to time in the future whether herein or otherwise. The Security shall be in form and substance satisfactory to the Bank and its counsel.

   
REPRESENTATONS AND WARRANTIES :

Each Loan Party represents and warrants to the Bank (all of which representations and warranties each Loan Party hereby acknowledges are being relied upon by the Bank in entering into this Commitment Letter) that:


  1.

there has been no adverse material change in the financial position of any Loan Party since the date of its most recent consolidated and non- consolidated financial statements dated September 30, 2013 which was furnished to the Bank. Such financial statements fairly present the financial position of each Loan Party at the date that they were drawn up.


CONDITIONS PRECEDENT :

Prior to each advance under Credit Facility A, the Borrower shall have provided, executed or satisfied the following, to the Bank’s satisfaction (collectively with all other conditions precedent set out in this Commitment Letter, called the “ Conditions Precedent ”):


  1.

all Additional Security shall be duly completed, authorized, executed delivered by each Loan Party which is a party thereto, and perfected and registered, all to the satisfaction of the Bank and its counsel;

     
  2.

no further Default or Event Default shall exist;

     
  3.

no Material Adverse Effect has occurred with respect to an Loan Party or the Security;

     
  4.

all representations and warranties of each Loan Party shall be true and correct;

     
  5.

The Borrower confirming that a minimum of $100,000 equity (after any fees or expenses) has been contributed to complete the Aduro acquisition; and

     
  6.

Any other document that may be reasonably requested by the Bank.

The above conditions are inserted for the sole benefit of the Bank, and may be waived by the Bank in whole or in part (with or without terms or conditions) in respect of any particular Advance, provided that any waiver shall not be binding unless given in writing and shall not derogate from the Bank to insist on the satisfaction of any condition not expressly waived in writing or to insist on the satisfaction of any condition waived in writing which may be requested in the future.


4

REVIEW :

Without detracting from the demand nature of the Credit Facilities, the Credit Facilities are subject to periodic review by the Bank periodically in its sole discretion (each such review is deferred to in this Commitment Letter as a “ Review ”) and at a minimum will be reviews on an annual basis. The Annual Review is scheduled on or before May 1, 2014, but may be set at an earlier or later date at the sole discretion of the Bank.

   
EXPIRY DATE :

The Commitment Letter is open for acceptance until February 25, 2014 (as may be extended from time to time as follows, the “ Expiry Date ”) at which time it shall expire unless extended by mutual consent in writing. We reserve the right to cancel this Commitment Letter at any time prior to acceptance.

If the foregoing terms and conditions are acceptable, please sign two copies of this Commitment Letter and return one copy to the Bank by the Expiry Date. This Commitment Letter may be executed in any number of counterparts and delivered by facsimile or other electronic copy, each of which when executed and delivered shall be deemed to be an original, and such counterparts together shall constitute one and the same agreement.

Sincerely,

CANADIAN WESTERN BANK

/s/ Daryl Anderson /s/ Tim Bacon
Senior Manager, AVP,
Energy Lending Group Energy Lending Group

AGREED AND ACCEPTED this 19 th day of February, 2014



5

APPENDIX A

CREDIT : Daryl Anderson Tim Bacon
  Senior Manager, AVP,
  Energy Lending Group Energy Lending Group
     
  Direct: (403) 750-3598 Direct: (403) 750-3579
  Cell: (403) 554-4870 Cell: (403) 701-8492
  Facsimile: (403) 264-1619 Facsimile: (403) 264-1619
  Email: Daryl.Anderson@cwbank.com Email: Tim.Bacon@cwbank.com

ADMINISTRATION : L/C/Gs: Visa: Loan/Account Balances; Account Representative: Monique Thompson
  Payments; Bank Drafts; Bank Telephone: (403) 268-7841
  Confirmations; General Facsimile: (403) 750-3596
    E-Mail: Monique.Thompson@cwbank.com
       
    Account Representative: Mayra Mercado O’Brien
    Telephone: (403) 268-7841
    Facsimile: (403) 750-3596
    E-Mail: Myra.Mercado@cwbank.com
       
BRANCH : Calgary Main Branch Telephone: (403) 262-8700
  #100, 606 – 4 Street S.W. Facsimile: (403) 262-4899
  T2P 1T1    
       
BUSINESS Order Cheques; Current Account Account Representative: Anita Latif
ACCOUNTS Documents/ Operations; Signing Telephone: (403) 750-3576
  Authorities; Rates; Investments; Facsimile: (403) 750-4899
  Customer Automated Funds Transfer E-mail Anita.Latif@cwbank.com
  (CAFT)    
       
INTERNET Loan/Account Balances; Traces, Stop Website: www.CWBANK.com
BANKING Payments, List of Current Account    
  Transactions; Pay Bills; Transfer    
  Between Accounts; Exchange Rates    
  Quotes    
       
OTHER : Personal/Retail Banking Manager: William Lee
    Telephone: (403) 268-7842
    Cell: (403) 818-6244
    Facsimile: (403) 233-2857
    E-mail: William.Lee@cwbank.com
       
VALIANT TRUST : Corporate Trust Services; Stock Website: www.VALIANTTRUST.com
  Transfer Agent; Employee Incentive Contact: Les Stastook
  Plans   Director, Business Development
    Telephone: (403) 781-8754
    Cell: (403) 848-6244
    Facsimile: (403) 233-2857
    E-mail: Les.Stastook@valianttrust.com



Exhibit 12.1

CERTIFICATION

I, Robert L. Hodgkinson, certify that:

1.              I have reviewed this annual report on Form 20-F of Dejour Energy Inc.;

2.              Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.              Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

4.              The company’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting 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 International Financial Reporting Standards;

(c) Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and

5.              The company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

Date: April 24, 2014 /s/ Robert L. Hodgkinson
  Robert L. Hodgkinson
  Chairman and Chief Executive Officer
  Principal Executive Officer


W

Exhibit 12.2

CERTIFICATION

I, David Matheson, certify that:

1.               I have reviewed this annual report on Form 20-F of Dejour Energy Inc.;

2.               Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.               Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report;

4.              The company’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the company and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting 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 International Financial Reporting Standards;

(c) Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and

5.              The company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting.

Date: April 24, 2014 /s/ David Matheson
  David Matheson
  Chief Financial Officer
  Principal Accounting and Financial Officer



Exhibit 13.1

CERTIFICATION PURSUANT TO
18 U.S.C. §1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Dejour Energy Inc. (the “Company”) on Form 20-F for the fiscal year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert Hodgkinson, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

             (1)           The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

             (2)           The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Robert Hodgkinson
_________________________________
Robert Hodgkinson
Chief Executive Officer
Principal Executive Officer
April 24, 2014

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished solely pursuant to 18 U.S.C. §1350 and is not being filed as part of the annual report or as a separate disclosure document.



Exhibit 13.2

CERTIFICATION PURSUANT TO
18 U.S.C. §1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Dejour Energy Inc. (the “Company”) on Form 20-F for the fiscal year ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David Matheson, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

             (1)           The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

             (2)           The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ David Matheson
__________________________________
David Matheson
Chief Financial Officer
Principal Accounting and Financial Officer
April 24, 2014

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished solely pursuant to 18 U.S.C. §1350 and is not being filed as part of the annual report or as a separate disclosure document.



 



 
Principal Officers:
Keith M. Braaten, P. Eng.
   President & CEO
Jodi L. Anhorn, P. Eng.
   Executive Vice President & COO
 
Officers / Vice Presidents:
Terry L. Aarsby, P. Eng.
Caralyn P. Bennett, P. Eng.
Leonard L. Herchen, P. Eng.
Myron J. Hladyshevsky, P. Eng.
Todd J. Ikeda, P. Eng.
Bryan M. Joa, P. Eng.
Mark Jobin, P. Geol.
  John E. Keith, P. Eng.
  John H. Stilling, P. Eng.
  Douglas R. Sutton, P. Eng.
  James H. Willmon, P. Eng.

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

Dejour Energy Inc.
598-999 Canada Place
Vancouver, BC V6C 3E1

We hereby consent to the use and reference to our name and reports evaluating a portion of Dejour Energy Inc.’s petroleum and natural gas reserves as of December 31, 2013, and the information derived from our reports, as described or incorporated by reference in: (i) Dejour Energy Inc.’s Annual Report on Form 20-F for the year ended December 31, 2013, (ii) Dejour Energy Inc.’s Registration Statement on Form F-3 (File No. 333-183587), and (iii) Dejour Energy Inc.’s Registration Statements on Form S-8 (Files No. 333-179540 and 333-156772), filed with the United States Securities and Exchange Commission.

 

 

Yours truly,

 
 

GLJ PETROLEUM CONSULTANTS LTD.

 
  Chad P. Lemke, P. Eng.
  Manager, Engineering

Calgary, Alberta
April 24, 2014
CANADA

 

4100, 400 – 3rd Avenue S.W., Calgary, Alberta, Canada T2P 4H2 • (403) 266-9500 • Fax (403) 262-1855 • GLJPC.com



 
Deloitte LLP
700, 850 – 2 nd Street SW
Calgary, AB T2P oR8
Canada
 
  Tel: 403-267-1700
  Fax: 587-774 -5398
  www.deloitte.ca

Dejour Energy Inc.
598-999 Canada Place
Vancouver, BC V6C 3E1

Consent of Independent Petroleum Engineers

We hereby consent to the use and reference to our name and reports evaluating a portion of Dejour Energy Inc.’s petroleum and natural gas reserves as of December 31, 2013, and the information derived from our reports, as described or incorporated by reference in: (i) Dejour Energy Inc.’s Annual Report on Form 20-F for the year ended December 31, 2013, (ii) Dejour Energy Inc.’s Registration Statement on Form F-3 (File No. 333-183587), and (iii) Dejour Energy Inc.’s Registration Statements on Form S-8 (File No. 333-179540 and 333-156772), filed with the United States Securities and Exchange Commission.  

 

Yours truly,

   
  Robin G. Bertram, P. Eng.
  Partner
  Deloitte LLP

Dated: April 24, 2014
Calgary, Alberta
CANADA



April 24, 2014

Dejour Energy Inc.
598-999 Canada Place
Vancouver, BC
V6C 3E1

Consent of Independent Petroleum Engineers

We hereby consent to the use and reference to our name and reports evaluating a portion of Dejour

Energy Inc.’s petroleum and natural gas reserves as of December 31, 2013, and the information derived from our reports, as described or incorporated by reference in: (i) Dejour Energy Inc.’s Annual Report on Form 20-F for the year ended December 31, 2013, (ii) Dejour Energy Inc.’s Registration Statement on Form F-3 (File No. 333-183587), and (iii) Dejour Energy Inc.’s Registration Statements on Form S-8 (Files No. 333-179540 and 333-156772), filed with the United States Securities and Exchange Commission.

Sincerely,

GUSTAVSON ASSOCIATES, LLC


Dated: April 24, 2014
Boulder, Colorado
USA

 

 

5757 Central Ave.     Suite D     Boulder, Co. 80301 USA      1-303-443-2209      FAX 1-303-443-3156      http:/ / www.gustavson.com



THIRD PARTY REPORT ON RESERVES

By GLJ Petroleum Consultants - (Independent Qualified Reserves Evaluator)

This report is provided to satisfy the requirements contained in Item 1202(a)(8) of U.S. Securities and Exchange Commission Regulation S-K.

The numbering of items below corresponds to the requirements set out in Item 1202(a)(8) of Regulation S-K. Terms to which a meaning is ascribed in Regulation S-K and Regulation S-X have the same meaning in this report.

i.

We have prepared an independent evaluation of certain reserves of Dejour Energy (Alberta) Inc. (the "Company") for the management and the board of directors of the Company. The primary purpose of our evaluation report was to provide estimates of reserves information in support of the Company’s year-end reserves reporting requirements under US Securities Regulation S-K and for other internal business and financial needs of the Company.

   
ii.

We have evaluated certain reserves of the Company as at December 31, 2013. The completion date of our report is February 19, 2014.

   
iii.

The following table sets forth the geographic area covered by our report, proved reserves estimated using constant prices and costs, and the proportion of the total company that we have evaluated.


    Company Net Proved Reserves  
             
        Natural Oil Proportion
Location of Reserves Crude Oil Natural Gas Gas Liquids Equivalent of Oil Eq.
             
Country Region Mbbl MMcf Mbbl Mboe Reserves
             
Canada B.C. 114 466 2 194 1.0%
             
Other Party Evaluation(s)   86,610 4,185 18,620 99.0%
             
Total Company         18,814 100%

1 Oil equivalence factors: Crude Oil 1 bbl/bbl , Natural Gas 6 Mcf/bbl , NGL 1 bbl/bbl

The Company provided to us the total Company reported reserves. We have derived the “Other Party Evaluation” figures by difference. We express no opinion on this portion of the Company’s reserves that we did not evaluate

   
iv.

As required under SEC Regulation S-K, reserves are those quantities of oil and gas that are estimated to be economically producible under existing economic conditions. As specified, in determining economic production, constant product reference prices have been based on a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the effective date of our report. In our economic analysis, operating and capital costs are those costs estimated as applicable at the effective date of our report, with no future escalation. Where deemed appropriate, the capital costs and revised operating costs associated with the implementation of committed projects designed to modify specific field operations in the future may be included in economic projections.




v.

Our report has been prepared assuming the continuation existing regulatory and fiscal conditions subject to the guidance in the COGE Handbook and SEC regulations. Notwithstanding that the Company currently has regulatory approval to produce the reserves identified in our report, there is no assurance that changes in regulation will not occur; such changes, which cannot reliably be predicted, could impact the Company’s ability to recovery the estimated reserves.

   
vi.

Oil and gas reserves estimates have an inherent degree of associated uncertainty the degree of which is affected by many factors. Reserves estimates will vary due to the limited and imprecise nature of data upon which the estimates of reserves are predicated. Moreover, the methods and data used in estimating reserves are often necessarily indirect or analogical in character rather than direct or deductive. Furthermore, the persons involved in the preparation of reserves estimates and associated information are required, in applying geosciences, petroleum engineering and evaluation principles, to make numerous unbiased judgments based upon their educational background, professional training, and professional experience. The extent and significance of the judgments to be made are, in themselves, sufficient to render reserves estimates inherently imprecise. Reserves estimates may change substantially as additional data becomes available and as economic conditions impacting oil and gas prices and costs change. Reserves estimates will also change over time due to other factors such as knowledge and technology, fiscal and economic conditions, contractual, statutory and regulatory provisions.

   
vii.

In our opinion, the reserves information evaluated by us have, in all material respects, been determined in accordance with all appropriate industry standards, methods and procedures applicable for the filing of reserves information under U.S. SEC Regulation S-K.

   
viii.

A summary of the Company reserves evaluated by us is provided in item iii.

GLJ Petroleum Consultants Ltd.
Calgary, Alberta, Canada
April 16, 2014

 


Chad P. Lemke, P. Eng.
Manager, Engineering



March 14, 2014

Mr. David Matheson
Chief Financial Officer, CFO
Dejour Energy (USA) Corp.
1100-808 West Hastings Street
Vancouver, BC
V6C 2X4
Canada

Subject:

Reserve Estimate and Financial Forecast as to Dejour’s Interests in the Kokopelli Field Area, Garfield County, Colorado.

Dear David:

As you requested, Gustavson Associates has completed reserves and economics as to Dejour Energy’s interests in future oil and gas production associated with the Kokopelli Field Area located in Garfield County. Reserves have been estimated based on analysis of analogous well production data. Estimates and projections have been made as of January 1, 2014. Reserves have been estimated in accordance with the US Securities and Exchange Commission’s (SEC) definitions and guidelines, and the report was prepared for the purpose of inclusion as an exhibit in a filing made with the SEC. This report was completed on March 5, 2014.

In general, Proved Developed Producing (PDP) reserves have been assigned to the four Kokopelli Federal wells, and Proved Undeveloped (PUD) reserves have been assigned to 139 well locations. Gustavson is of the opinion that no current regulations, and no anticipated changes to regulations, would inhibit the ability of Dejour to recover the estimated reserves in the manner projected herein. It is our understanding that the reserves estimated herein represent all of Dejour’s US reserves.

The estimated net reserves volumes and associated net cash flow estimates are summarized in Table 1 below.

 

 

5757 Central Ave.      Suite D      Boulder, Co. 80301 USA      1-303-443-2209      FAX 1-303-443-3156      http:/ / www.gustavson.com


Mr. David Matheson
March 14, 2014
Page 2

Table 1 Summary of Net Reserves and Projected Before Tax Cash Flow

Reserves Category Net Gas
Reserves
(MMCF)
Net Light
Crude Oil
Reserves
(MBO)
Net NGL
Reserves
(MBO)
Net Present Value, thousands of US$
Discounted at
0% 10% 15%
Proved Developed Producing 367.1 2.5 15.2 $1,450.5 $1,069.6 $956.3
Proved Developed Non-Producing - - - $0.0 $0.0 $0.0
Proved Undeveloped 86,243.3 587.3 3,580.3 $247,444.2 $83,588.3 $53,379.4
Total Proved 86,610.4 589.8 3,595.6 $248,894.7 $84,657.9 $54,335.7

The proportion of the Company’s total reserves represented by the reserves included in this report is shown below.

 Location of Reserves           Proportion of
    Gas Light Crude Oil NGL Oil Equivalent Oil Equiv.
Country Area (MMCF) (MBBL) (MBBL) (MBOE) Reserves
             
United States Colorado 86,610 590 3,596 18,620 99%
Total Company         18,815 100%

Kokopelli Field Area Assumptions, Garfield County, Colorado

Gustavson Associates has performed an evaluation of the reserves associated with both developed and undeveloped locations located in the Kokopelli Field Project Area, Garfield County, Colorado. Proved Developed Producing (PDP) Reserves have been assigned to the Federal 6/7-16-21, Federal 6/7-14-21, Federal 6/7-15-21, and Federal 6/7-13-21 wells, which began producing in July and August of 2013. Logs for these well were reviewed and found to indicate similar response in the target formations to the response in analogous producing wells. Proved Undeveloped reserves have been assigned to locations within the area delineated by successful wells and logged net pay, comprising of 139 locations. The 139 PUD locations and the PDP locations are displayed in Figure 1.

Dejour entered into a farmout agreement on December 31, 2012 with a private Denver-based drilling fund for a four-well drilling and completion program which included all the aforementioned PDP locations. The drilling of these four locations was completed in mid-2013. Dejour will have a 22.23% working interest (WI) and 17.78% net revenue interest (NRI) before payout of 150% of the capital investments (BPO), and 41.67% WI and 33.34% NRI APO, in the joint venture for three of the wells. For the Federal 6/7 16-21 well, Dejour maintains a 15.88% working interest (WI) and 12.70% net revenue interest (NRI) before payout of 150% of the capital investments (BPO), and 29.77% WI and 23.81% NRI APO, in the joint venture. Payout of 150% of investment is expected to occur in 2023. Dejour’s interests in these four wells can be found in Table 2 below:


Mr. David Matheson
March 14, 2014
Page 3

Table 2 Farmout and Non Farmout Working Interests and Net Revenue Interests



Company

No Farmout    Farmout
Federal 6/7 13, 14, & 15-21 Federal 6/716-21 well 
BPO APO BPO APO
WI NRI WI NRI WI  NRI WI NRI WI NRI
Dejour 71.43 57.14 22.23 17.78 41.67 33.34 15.88 12.70 29.77 23.81
Brownstone 28.57 22.86 0.00 0.00 0.00  0.00 28.57 22.86 28.57 22.86
Drilling Fund  0.00 0.00 77.77 62.22 58.33 46.66 55.55 44.44 41.66 33.33

Figure 1 Map of Dejour PDP, PUD, and Offset Well Locations

Dejour expects to start the remainder of their drilling program with 54 wells drilled per year, beginning 2014 through 2017. On this schedule, the last PUD location will be drilled in November 2016. The estimated ultimate recovery (EUR) for each location was based on the average performance of wells in the immediate area. Many of these wells were completed in multiple zones, including Williams Fork, Rollins, Cozette, and Corcoran. Figure 1 also displays the location s of Dejour’s PDP wells, and offsetting producing wells. All of the PUD locations are within 1.5 miles and flanked by producing wells.


Mr. David Matheson
March 14, 2014
Page 4

The type curve utilized for the undeveloped locations was the same as that determined in the Dejour 2012 year-end reserve report. While there have been some new wells drilled and completed in the area, their performance on average appears to have been negatively impacted by operator completion practices in 2013, namely, the smaller size of fracture treatments. Dejour has stated their intentions to maintain the larger fracture treatments; therefore, we have stayed with the type curve based on the wells drilled prior to 2013. The average EUR was based on the average composite performance of the total well production from each well. When the economic parameters were considered, this EUR was found to be approximately 1.15 BCF. This average reserve per well is dry gas after a shrinkage of 5% is deducted. The Proved Undeveloped location type curve can be found in Figure 2 below. The estimated net reserves volumes and associated net cash flow estimates are summarized in Table 1 above.

Figure 2 Composite Type Curve, Kokopelli Area

Oil and Gas Pricing

In order to determine the flat pricing in accordance with SEC guidelines, the Dejour’s revenue statements were analyzed. A differential was calculated based on the price that Dejour was paid versus the West Texas Intermediate (WTI) and Henry Hub (HH) spot prices averaged for that given month. These differentials were then applied to the WTI and HH spot prices for the first day of each month in 2013 in order to estimate prices for Dejour’s products on the first day of the month, per SEC guidelines. These values were averaged and applied in the cash flows presented herein.


Mr. David Matheson
March 14, 2014
Page 5

The oil prices were determined to be 11% lower than WTI prices. Gas prices were determined to be 9% higher than Henry Hub prices. NGL’s were found to be sold at 79.5% the price of Dejour’s paid price for oil. The utilized flat hydrocarbon pricing can be found in the table below.

Flat Price Forecast For Effective Date of January 1, 2014
Oil, Gas & NGL Pricing Includes Differentials

Piceance
Oil, $/B
Piceance
Gas, $/MCF
Piceance
NGL, $/B
Flat Pricing $86.58 $4.09 $68.84

Expenses

The drilling and completion costs utilized for the first 50 undeveloped locations is $1.65 million per well; the next 50 locations is $1.50 million per well; and the remaining locations have a drilling and completion cost of $1.40 million per well. Operating costs for the PDPs and first 50 undeveloped locations is estimated at $3,759 per well per month; the next 50 locations utilize a monthly operational expense of $3,000 per well; the remaining undeveloped locations have an anticipated monthly operational expense of $2,500 per well. This is based on information provided by Dejour and is consistent with our experience with similar wells in the area. The reduction in costs reflects economies of scale and contractual advantages expected to be gained when a large drilling program is executed. Severance tax and conservation taxes are deducted at the rate of 1.07% of revenue. County ad valorem tax was estimated at approximately 3.35% of revenue after discussion with Garfield County personnel. NGL yield of 39 Bbl/MMCF and condensate/gas ratio of 6.5 Bbl/MMCF were based on actual 2013 sales. Contractual gas transportation, gathering, and processing fees of $0.71/MCF were deducted as operating costs.

Capital and operating costs were held flat. Abandonment costs of $15,000 per well was assumed. Dejour’s interests in the property are reported to be 71.43% working interest with a 20% royalty burden for net revenue interest of 57.14%, with the exception of the four PDP wells included in the farmout as described previously.

Detailed cash flow projections by category are shown in Table 3 and Table 4 below. Note that the NGL volumes shown in these tables represent total NGL sales as expected based on the revenue statements provided by the Client. 1

____________________________________________
1
In some previous reports, ethane and heavier NGLs were reported separately. Here they are reported together.


Mr. David Matheson
March 14, 2014
Page 6

Limiting Conditions and Disclaimers

The accuracy of any reserve report or resource evaluation is a function of available data and of engineering and geologic interpretation and judgment. While the evaluation presented herein is believed to be reasonable, it should be viewed with the understanding that subsequent reservoir performance or changes in pricing structure, market demand, or other economic parameters may justify its revision. The assumptions, data, methods, and procedures used are appropriate for the purpose served by the report. Gustavson has used all methods and procedures as we considered necessary under the circumstances to prepare the report.

Gustavson Associates, LLC, holds neither direct nor indirect financial interest in the subject property, the company operating the subject acreage, or in any other affiliated companies.

All data and work files utilized in the preparation of this report are available for examination in our offices. Please contact us if we can be of assistance. We appreciate the opportunity to be of service and look forward to further serving Dejour Energy (USA) Corp.

Sincerely,

 


Table 3 Summary Cash Flow Forecast, Proved Developed Producing Reserves

TOTAL PROVED DEVELOPED DATE : 03/05/2014
KOKOPELLI FIELD TIME : 16:03:42
GARFIELD COUNTY, COLORADO DBS : Dejour1-12
TO THE INTERESTS OF DEJOUR ENERGY SETTINGS : SETDATA
  SCENARIO : Dejour

R E S E R V E S   A N D   E C O N O M I C S

EFF DATE: 01/2014
PW DATE: 01/2014

--END-- GROSS OIL GROSS GAS GROSS NGL NET OIL NET GAS NET NGL NET OIL NET GAS NET NGL TOTAL
MO-YEAR PRODUCTION PRODUCTION PRODUCTION PRODUCTION    PRODUCTION    PRODUCTION    REVENUE REVENUE REVENUE REVENUE
-------
---MBBLS--- ----MMCF--- ---MBBLS--- ---MBBLS-- ----MMCF-- ---MBBLS-- ---M$--- ---M$--- ---M$--- ----M$---
                     
12-2014 3.091 478.730 18.845 0.508 74.568 3.096 43.966 304.982 213.103 562.050
12-2015 1.757 272.050 10.709 0.288 42.320 1.757 24.952 173.090 120.945 318.987
12-2016 1.297 200.848 7.906 0.213 31.235 1.297 18.416 127.749 89.263 235.429
12-2017 1.050 162.634 6.402 0.172 25.288 1.050 14.910 103.429 72.270 190.609
12-2018 0.893 138.266 5.443 0.146 21.498 0.892 12.675 87.925 61.436 162.036
                     
12-2019 0.782 121.165 4.770 0.128 18.838 0.782 11.107 77.046 53.835 141.988
12-2020 0.700 108.402 4.267 0.115 16.853 0.700 9.936 68.928 48.162 127.026
12-2021 0.636 98.456 3.876 0.104 15.306 0.635 9.024 62.602 43.742 115.368
12-2022 0.584 90.453 3.561 0.096 14.062 0.584 8.291 57.512 40.186 105.989
12-2023 0.541 83.854 3.301 0.089 13.035 0.541 7.686 53.315 37.253 98.254
                     
12-2024 0.506 78.304 3.082 0.083 12.173 0.505 7.177 49.786 34.787 91.750
12-2025 0.475 73.561 2.896 0.078 11.435 0.475 6.742 46.770 32.680 86.192
12-2026 0.448 69.455 2.734 0.074 10.797 0.448 6.366 44.159 30.855 81.379
12-2027 0.425 65.853 2.592 0.070 10.237 0.425 6.036 41.868 29.255 77.159
12-2028 0.404 62.556 2.462 0.066 9.724 0.404 5.733 39.772 27.790 73.296
                     
S TOT 13.590 2104.586 82.845 2.229 327.367 13.590 193.017 1338.932 935.562 2467.512
                     
AFTER 1.694 262.365 10.328 0.271 39.753 1.650 23.439 162.591 113.609 299.639
                     
TOTAL 15.284 2366.952 93.172 2.500 367.121 15.241 216.456 1501.524 1049.171 2767.151

--END-- NET OIL NET GAS NET NGL SEVERANCE AD VALOREM NET OPER OPERATING EQUITY UNDISC NET DISC NET
MO-YEAR PRICE    PRICE   PRICE TAXES TAXES EXPENSES CASH FLOW INVESTMENT CASH FLOW CASH FLOW
------- ---M$--- ---M$--- ---M$--- -----M$---- -----M$---- ----M$---- ----M$---- ----M$---- -----M$---- -----M$----
                     
12-2014 86.58 4.09 68.84 3.734 18.704 104.167 435.446 0.000 435.446 415.181
12-2015 86.58 4.09 68.84 2.119 10.615 76.307 229.946 0.000 229.946 199.313
12-2016 86.58 4.09 68.84 1.564 7.834 67.244 158.787 0.000 158.787 125.122
12-2017 86.58 4.09 68.84 1.266 6.343 62.757 120.243 0.000 120.243 86.136
12-2018 86.58 4.09 68.84 1.076 5.392 60.199 95.369 0.000 95.369 62.107
                     
12-2019 86.58 4.09 68.84 0.943 4.725 58.661 77.659 0.000 77.659 45.976
12-2020 86.58 4.09 68.84 0.844 4.227 57.738 64.218 0.000 64.218 34.562
12-2021 86.58 4.09 68.84 0.766 3.839 57.221 53.542 0.000 53.542 26.197
12-2022 86.58 4.09 68.84 0.704 3.527 56.989 44.769 0.000 44.769 19.913
12-2023 86.58 4.09 68.84 0.653 3.270 56.968 37.363 0.000 37.363 15.108
                     
12-2024 86.58 4.09 68.84 0.610 3.053 57.111 30.977 0.000 30.977 11.387
12-2025 86.58 4.09 68.84 0.573 2.868 57.382 25.369 0.000 25.369 8.478
12-2026 86.58 4.09 68.84 0.541 2.708 56.816 21.315 0.000 21.315 6.476
12-2027 86.58 4.09 68.84 0.513 2.568 56.319 17.760 0.000 17.760 4.905
12-2028 86.58 4.09 68.84 0.487 2.439 55.864 14.506 4.229 10.277 2.622
                     
S TOT 86.58 4.09 68.84 16.392 82.113 941.741 1427.267 4.229 1423.038 1063.483
                     
AFTER 86.58 4.09 68.84 1.991 9.971 248.741 38.936 11.478 27.458 6.137
                     
TOTAL 86.58 4.09 68.84 18.382 92.084 1190.481 1466.203 15.707 1450.496 1069.620

  OIL GAS       P.W. % P.W., M$
  --------- ---------       ------ --------
GROSS WELLS 0.0 4.0   LIFE, YRS. 22.25 5.00 1225.246
GROSS ULT., MB & MMF 15.284 2790.128   DISCOUNT % 10.00 10.00 1069.620
GROSS CUM., MB & MMF 0.000 423.177   UNDISCOUNTED PAYOUT, YRS. 0.00 15.00 956.298
GROSS RES., MB & MMF 15.284 2366.951   DISCOUNTED PAYOUT, YRS. 0.00 20.00 870.137
NET RES., MB & MMF 2.500 367.121   UNDISCOUNTED NET/INVEST. 93.35 25.00 802.291
NET REVENUE, M$ 216.456 1501.524   DISCOUNTED NET/INVEST. 418.07 30.00 747.328
INITIAL PRICE, $ 86.580 4.090   RATE-OF-RETURN, PCT. 100.00 40.00 663.265
INITIAL N.I., PCT. 16.427 16.427   INITIAL W.I., PCT. 20.564 60.00 553.783
            80.00 484.132
            100.00 435.050


Table 4 Summary Cash Flow Forecast, Proved Undeveloped Reserves

TOTAL PROVED UNDEVELOPED DATE : 03/05/2014
KOKOPELLI FIELD TIME : 16:04:03
GARFIELD COUNTY, COLORADO DBS : Dejour1-12
TO THE INTERESTS OF DEJOUR ENERGY SETTINGS : SETDATA
  SCENARIO : Dejour

R E S E R V E S   A N D   E C O N O M I C S

EFF DATE: 01/2014
PW DATE: 01/2014

--END-- GROSS OIL GROSS GAS GROSS NGL NET OIL NET GAS NET NGL NET OIL NET GAS NET NGL TOTAL
MO-YEAR PRODUCTION PRODUCTION PRODUCTION   PRODUCTION PRODUCTION    PRODUCTION    REVENUE REVENUE REVENUE REVENUE
------- ---MBBLS--- ----MMCF--- ---MBBLS--- ---MBBLS--- ----MMCF--   ---MBBLS-- ---M$--- ---M$--- ---M$--- ----M$---
                     
12-2014 38.329 5935.913 233.660 21.901 3216.090 133.513 1896.223 13153.798 9191.061 24241.100
12-2015 91.965 14242.327 560.633 52.549 7716.526 320.345 4549.700 31560.566 22052.543 58162.863
12-2016 114.939 17800.160 700.682 65.676 9644.151 400.370 5686.247 39444.645 27561.430 72692.297
12-2017 78.662 12182.042 479.531 44.947 6600.252 274.004 3891.543 26995.006 18862.451 49749.000
12-2018 56.993 8826.265 347.436 32.566 4782.093 198.525 2819.544 19558.771 13666.435 36044.746
                     
12-2019 46.206 7155.794 281.679 26.402 3877.023 160.951 2285.913 15857.042 11079.906 29222.842
12-2020 39.406 6102.697 240.226 22.517 3306.453 137.265 1949.505 13523.406 9449.306 24922.217
12-2021 34.636 5363.999 211.147 19.791 2906.224 120.650 1713.525 11886.456 8305.516 21905.492
12-2022 31.068 4811.355 189.393 17.752 2606.805 108.219 1536.984 10661.817 7449.817 19648.643
12-2023 28.279 4379.393 172.390 16.158 2372.763 98.503 1398.996 9704.614 6780.972 17884.580
                     
12-2024 26.028 4030.797 158.667 14.872 2183.895 90.663 1287.635 8932.122 6241.211 16460.971
12-2025 24.166 3742.518 147.320 13.809 2027.702 84.178 1195.544 8293.302 5794.843 15283.692
12-2026 22.597 3499.462 137.752 12.912 1896.014 78.712 1117.901 7754.699 5418.498 14291.104
12-2027 21.253 3291.287 129.558 12.144 1783.228 74.029 1051.401 7293.401 5096.180 13440.983
12-2028 20.120 3115.849 122.652 11.496 1688.173 70.083 995.355 6904.632 4824.523 12724.509
                     
S TOT 674.647 104479.859 4112.725 385.493 56607.391 2350.010 33376.012 231524.281 161774.688 426675.000
                     
AFTER 353.201 54698.793 2153.152 201.819 29635.916 1230.311 17473.492 121210.906 84694.617 223378.984
                     
TOTAL 1027.848 159178.656 6265.877 587.312 86243.312 3580.321 50849.504 352735.188 246469.312 650054.000

--END-- NET OIL NET GAS NET NGL SEVERANCE AD VALOREM NET OPER OPERATING EQUITY UNDISC NET DISC NET
MO-YEAR PRICE PRICE PRICE         TAXES         TAXES EXPENSES CASH FLOW INVESTMENT CASH FLOW CASH FLOW
------- ---M$--- ---M$--- ---M$--- -----M$---- -----M$---- ----M$---- ----M$---- ----M$---- -----M$---- -----M$----
                     
12-2014 86.58 4.09 68.84 161.035 806.682 3362.669 19910.703 56756.844 -36846.148 -35410.023
12-2015 86.58 4.09 68.84 386.380 1935.510 8608.683 47232.273 56182.695 -8950.458 -7973.347
12-2016 86.58 4.09 68.84 482.900 2419.014 11520.249 58270.145 32898.117 25372.057 19405.477
12-2017 86.58 4.09 68.84 330.486 1655.521 9188.992 38573.988 0.000 38573.988 27632.482
12-2018 86.58 4.09 68.84 239.448 1199.477 7641.883 26963.900 0.000 26963.900 17559.641
                     
12-2019 86.58 4.09 68.84 194.129 972.462 6906.530 21149.725 0.000 21149.725 12521.168
12-2020 86.58 4.09 68.84 165.560 829.348 6469.428 17457.881 0.000 17457.881 9395.918
12-2021 86.58 4.09 68.84 145.520 728.959 6184.893 14846.141 0.000 14846.141 7263.873
12-2022 86.58 4.09 68.84 130.527 653.856 5991.237 12872.992 0.000 12872.992 5725.878
12-2023 86.58 4.09 68.84 118.809 595.154 5857.071 11313.544 0.000 11313.544 4574.756
                     
12-2024 86.58 4.09 68.84 109.351 547.779 5764.457 10039.385 0.000 10039.385 3690.489
12-2025 86.58 4.09 68.84 101.531 508.602 5702.350 8971.216 0.000 8971.216 2998.025
12-2026 86.58 4.09 68.84 94.937 475.571 5585.466 8135.127 0.000 8135.127 2471.471
12-2027 86.58 4.09 68.84 89.289 447.281 5485.363 7419.042 0.000 7419.042 2049.022
12-2028 86.58 4.09 68.84 84.530 423.440 5400.999 6815.539 0.000 6815.539 1711.221
                     
S TOT 86.58 4.09 68.84 2834.433 14198.656 99670.266 309971.656 145837.641 164133.922 73616.055
                     
AFTER 86.58 4.09 68.84 1483.923 7433.485 129262.508 85199.086 1888.811 83310.281 9972.262
                     
TOTAL 86.58 4.09 68.84 4318.356 21632.141 228932.766 395170.750 147726.469 247444.188 83588.320

  OIL GAS       P.W. % P.W., M$
  --------- ---------       ------ --------
GROSS WELLS 0.0 139.0   LIFE, YRS. 42.83 5.00 136375.953
GROSS ULT., MB & MMF 1027.848 159178.656   DISCOUNT % 10.00 10.00 83588.328
GROSS CUM., MB & MMF 0.000 0.000   UNDISCOUNTED PAYOUT, YRS. 3.53 15.00 53379.430
GROSS RES., MB & MMF 1027.848 159178.656   DISCOUNTED PAYOUT, YRS. 3.87 20.00 33964.258
NET RES., MB & MMF 587.313 86243.352   UNDISCOUNTED NET/INVEST. 2.68 25.00 20544.215
NET REVENUE, M$ 50849.547 352735.250   DISCOUNTED NET/INVEST. 1.64 30.00 10813.058
INITIAL PRICE, $ 86.580 4.090   RATE-OF-RETURN, PCT. 38.14 40.00 -2086.993
INITIAL N.I., PCT. 57.140 57.140   INITIAL W.I., PCT. 71.430 60.00 -15022.593
            80.00 -20700.264
            100.00 -23389.502