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UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, 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, 2014

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 PlaceVancouver, British
Columbia V6C 3E1(Address of principal executive offices)

David N. Matheson598 - 999 Canada PlaceVancouver, British Columbia V6C 3E1Tel: (604) 638-5050Facsimile: (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                       

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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:182,402,139 common shares as at December
31, 2014 and April 21, 2015

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 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 [   ]
|--------------- | ----------------------------------------------------------- | -----------
|                | by the International Accounting
      Standards Board [X]   |            

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]

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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.                                  | 60
|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]                                                                         | 85
|ITEM
      16A. AUDIT COMMITTEE FINANCIAL EXPERT                                                  | 85
|ITEM
      16B. CODE OF ETHICS                                                                    | 85
|ITEM
      16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES                                            | 86
|ITEM
      16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES                        | 86
|ITEM
      16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS               | 87
|ITEM
      16F. CHANGE IN REGISTRANTS CERTIFYING ACCOUNTANT                                      | 87
|ITEM
      16G. CORPORATE GOVERNANCE                                                              | 87
|ITEM
      16H. MINE SAFETY DISCLOSURE                                                            | 87
|PART
      III                                                                                    | 94
|ITEM
      17. FINANCIAL STATEMENTS                                                               | 94
|ITEM
      18. FINANCIAL STATEMENTS                                                               | 94
|ITEM
      19. EXHIBITS                                                                           | 95
|SIGNATURES                                                                                        | 91

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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:

- drilling inventory, drilling plans and timing of drilling, re-completion
  and tie-in of wells;
- productive capacity of wells, anticipated or expected production rates and
  anticipated dates of commencement of production;
- drilling, completion and facilities costs;
- results of our various projects;
- ability to lower cost structure in certain of our projects;
- our growth expectations;
- timing of development of undeveloped reserves;
- the performance and characteristics of the Companys oil and natural gas
  properties;
- oil and natural gas production levels;
- the quantity of oil and natural gas reserves;
- capital expenditure programs;
- supply and demand for oil and natural gas and commodity prices;
- the impact of federal, provincial, and state governmental regulation on
  Dejour;
- expected levels of royalty rates, operating costs, general administrative
  costs, costs of services and other costs and expenses;
- expectations regarding our ability to raise capital and to continually add
  to reserves through acquisitions, exploration and development;
- treatment under governmental regulatory regimes and tax laws; and
- realization of the anticipated benefits of acquisitions and dispositions.

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

4

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

- risks related to the marketability and price of oil and natural gas being
  affected by factors outside our control;
- risks related to world oil and natural gas prices being quoted in U.S.
  dollars and our production revenues being adversely affected by an
  appreciation in the Canadian dollar;
- risks related to our ability to execute projects being dependent on factors
  outside our control;
- risks related to oil and gas exploration having a high degree of risk and
  exploration efforts failing;
- risks related to cumulative unsuccessful exploration efforts;
- risks related to oil and natural gas operations involving hazards and
  operational risks;
- risks related to seasonal factors and unexpected weather;
- risks related to competition in the oil and gas industry;
- risks related to the fact that we do not control all of the assets that are
  used in the operation of our business;
- risks related to our ability to market oil and natural gas depending on its
  ability to transport the product to market;
- risks related to high demand for drilling equipment;
- risks related to title to our properties;
- risks related to our ability to continue to meet its oil and gas lease or
  license obligations;
- risks related to our anticipated substantial capital needs for future oil
  and gas exploration, development and acquisitions;
- risks related to our cash flow from reserves not being sufficient to fund
  its ongoing operations;
- risks related to covenants in issued debt restricting the ability to
  conduct future financings;
- risks related to renewal or refinancing;
- risks related to our being exposed to third party credit risks;
- risks related to our being able to find, acquire, develop and commercially
  produce oil and natural gas;
- risks related to our properties not producing as projected;
- risks related to our estimated reserves being based upon estimates;
- risks related to future oil and gas revenues not resulting in revenue
  increases;
- risks related to our managing growth;
- risks related to our being dependent on key personnel;
- risks related to our operations being subject to federal, state, local and
  other laws, controls and regulations;
- risks related to uncertainty regarding claims of title and right of
  aboriginal people;
- risks related to environmental laws and regulations;
- risks related to our facilities, operations and activities emitting
  greenhouse gases;
- risks related to our not having paid dividends to date;
- risks related to our stock price being volatile; and
- risks related to our being a foreign private issuer.

5

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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. Dollar2014
    2013
    2012
    2011
    2010Average for the period
    1.1045
    1.0299
    0.9996
    0.9891
    1.0345


March2015
    February2015
    January2015
    December2014
    November2014
    October2014High for the period
    1.2803
    1.2635
    1.2717
    1.1643
    1.1427
    1.1289Low for the period
    1.2440
    1.2403
    1.1728
    1.1344
    1.1236
  1.1136


Exchange rates are based on the Bank of Canada nominal noon
exchange rates. The nominal noon exchange rate on April 21, 2015 as reported by
the Bank of Canada for the conversion of United States dollars into Canadian
dollars was US$1.00 = Cdn$1.2274.

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

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|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

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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, 2010  2014 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, 2014, 2013, 2012, 2011 and 2010. 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 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).

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.

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 31,2014
    2013
    2012
    2011
    2010Net Oil and Gas Revenue
    $7,561
    $7,506
    $5,766
    $7,196
    $6,774Net Loss for the Year
    ($7,203)
    ($2,577)
    ($11,753)
    ($11,043)
    ($5,124)Loss Per Share
    ($0.04)
    ($0.02)
    ($0.08)
    ($0.09)
    ($0.05)Dividends Per Share
    Nil
    Nil
    Nil
    Nil
    NilWeighted Avg. Shares, basic (,000)
    177,124
    148,916
    141,056
    120,300
    99,789Weighted Avg. Shares, diluted (,000)
    177,124
    148,916
    141,056
    120,300
    99,789Year-end Shares (,000)
    182,402
    148,916
    148,916
    126,892
    110,181Working Capital (Deficiency)
    ($4,480)
    ($8,908)
    ($8,557)
    ($7,756)
    ($3,264)Resource properties and equipment
    $21,016
    $23,667
    $25,033
    $25,043
    $24,432Long-term Liabilities
    $6,448
    $6,107
    $6,622
    $1,383
    $738Share Capital
    $97,132
    $90,274
    $90,274
    $85,076
    $79,386Retained Earnings (Deficit)
    ($98,042)
    ($90,839)
    ($88,262)
    ($76,510)
    ($65,467)Total Assets
    $23,274
    $25,499
    $27,573
    $29,438
    $30,413Net Assets
    $10,385
    $9,099
    $10,245
    $16,307
    $20,873


8

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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, 2014, 2013 and 2012. 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 IASB or IFRIC that
are mandatory for accounting periods beginning after January 1, 2015 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:

IAS 1, Presentation of Financial Statements: In December
2014, the IASB issued amendments to IAS 1, clarifying guidance on the concepts
of materiality and aggregation of items in the financial statements, the use and
presentation of subtotals in the statement of operations and comprehensive
income or loss, and providing additional flexibility in the structure and
disclosures of the financial statements to enhance understandability. The
amendments to IAS 1 may be applied immediately, and become mandatory for annual
periods beginning on or after January 1, 2016.

IFRS 9, Financial Instruments: In July 2014, the IASB
completed the final phase of its project to replace IAS 39, the current standard
on the recognition and measurement of financial instruments. IFRS 9 is now the
new standard which sets out the recognition and measurement requirements for
financial instruments and some contracts to buy or sell non-financial items.
IFRS 9 proposes a single model of classifying and measuring financial assets and
liabilities and provides for only two classification categories: amortized cost
and fair value. Hedge accounting requirements have also been updated in the new
standard and are now more aligned with the risk management activities of an
entity. IFRS 9 is effective for annual periods beginning on or after January 1,
2018. Early adoption is permitted; however, if an entity elects to apply this
standard early, it must disclose that fact and apply all of the requirements in
this standard at the same time.

IFRS 11, Joint Arrangements: In May 2014, the IASB issued
amendments to IFRS 11 to address the accounting for acquisitions of interests in
joint operations. The amendments address how a joint operator should account for
the acquisition of an interest in a joint operation in which the activity of the
joint operation constitutes a business. IFRS 11, as amended, now requires that
such transactions be accounted for using the principles related to business
combinations accounting as outlined in IFRS 3, Business Combinations. The
amendments are to be applied prospectively and are effective for annual periods
beginning on or after January 1, 2016, with earlier application permitted.

IFRS 15, Revenue from Contract with Customers. The IASB
issued the standard to replace IAS 18 which establishes principles for reporting
useful information to users of financial statements about the nature, amount,
timing and uncertainty of revenue and cash flows arising from an entitys
contracts with customers. The standard is effective for the Company for annual
periods beginning on January 1, 2017, with required retrospective application
and early adoption permitted.

IAS 16, Property, Plant and Equipment and IAS 38, Intangible
Assets:In May 2014, the IASB issued amendments to IAS 16 and IAS 38 to
clarify acceptable methods of depreciation and amortization. The amended IAS 16
eliminates the use of a revenue-based depreciation method for items of property,
plant and equipment. Similarly, amendments to IAS 38 eliminate the use of a
revenue-based amortization model for intangible assets except in certain
specific circumstances. The amendments are to be applied prospectively and are
effective for annual periods beginning on or after January 1, 2016, with earlier
application permitted.

9

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B.            
Capitalization and Indebtedness

Not Applicable.

C.            
Reasons for the Offer and Use of Proceeds

Not Applicable.

D.            
Risk Factors

An investment in a company engaged in oil and gas exploration
involves an unusually high amount of risk, both unknown and known, present and
potential, including, but not limited to the risks enumerated below. 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.

10

---

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

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

Risks related to operating an exploration, development and
production company

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

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

- the availability of adequate financing;
- the availability of processing capacity;
- the availability and proximity of pipeline capacity;
- the availability of storage capacity;
- 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.

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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.

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.

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

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

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

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

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

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, 2014, the Company had a working capital
deficiency of approximately $4.5 million. Excluding the non-cash warrant
liability of $0.8 million related to the fair value of US$ denominated warrants
issued in current and previous equity financings, the non-cash derivative
liability of $0.2 million related to the fair value of warrants issued in the
loan facility which closed in June 2013, the adjusted working capital deficiency
is approximately $3.5 million. We expect to incur general and administration
expenses of approximately $3.0 million over the next twelve months.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, 2014, the Company incurred a
loss of $7.2 million and has an accumulated deficit of $98.0 million. Whether
and when the Company can attain profitability is uncertain. The Company also has
a working capital deficiency of $4.5 million as at December 31, 2014.
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, 2014
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 December 11, 2014, 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 as appropriate or upon request but
no later than at the completion of each quarter 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.

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

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

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

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

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

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

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

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

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.

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

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

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

Risks related to management of the Company

We may experience difficulty managing our anticipated
growth.

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

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

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.

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

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

ITEM 4. INFORMATION ON THE COMPANY

A.            
History and Development of the Company

Introduction

Our executive office is located at:

598  999 Canada PlaceVancouver, British Columbia, Canada
V6C 3E1Telephone: (604) 638-5050Facsimile: (604) 638-5051Website:
www.dejour.comEmail: rhodgkinson@dejour.comor 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, 2014, there were 182,402,139 common shares
issued and outstanding. As of December 31, 2014, 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.

19

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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.

|Fiscal Year | Nature of Share Issuance    | Number of Shares | Gross Proceeds
|----------- | --------------------------- | ---------------- | --------------
|            |                             |                  | (Cdn$)        
|Fiscal 2014 | Private Placement
      (1) | 7,000,000        | 770,000       
|            | Acquisition of property (2) | 9,600,000        | 1,939,000     
|            | Equity Offering
      (3)   | 6,000,000        | 1,640,000     
|            | Exercise of Warrants        | 700,000          | 168,000       
|            | Exercise of
      Options   | 10,185,765       | 2,064,000     
|            |                             |                  |               
|Fiscal 2012 | Private Placement
      (4) | 18,130,305       | 4,909,000     
|            | Exercise of Warrants        | 2,968,683        | 1,110,000     
|            | Exercise of
      Options   | 925,000          | 356,000       

|(1) | In January 2014, we completed a private placement of
      7,000,000 common shares at $0.11 per share. Gross proceeds raised were
      $770,000. In connection with this private placement, the Company paid
      finders fees of $27,000 and other related costs of $58,000. Directors and
      Officers of the Company purchased 900,000 common shares of this
      offering.                                                                                                                                                                                                                                                 
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|(2) | In July 2014, we closed the acquisition of an additional
      24% working interest in the Drake/Woodrush oilfield in Northeastern B.C.
      to increase our working interest to 99%. As consideration for the
      purchase, the Company issued 9,600,000 common shares at a price of $0.202
      per share for $1,939,000. In connection with this acquisition, the Company
      paid other related costs of $49,000. A company controlled by the CEO of
      the Company sold its 5% working interest in the Drake/Woodrush property
      for 2,000,000 common shares.                                                      
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|(3) | In August 2014, we completed an equity offering of
      6,000,000 units at US$0.25 per unit. Each unit consists of one common
      share and 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 until December 31, 2015. Gross proceeds raised
      were $1,640,000 (US$1,500,000). In connection with this private placement,
      the Company paid other related costs of $64,000.                                                                                                                        
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|(4) | 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 $4,909,000 (US$4,714,000).
      In connection with this private placement, the Company paid finders fees
      of $295,000 (US$283,000) in cash and other related costs of $187,000 in
      cash.

Past Capital Expenditures

Fiscal Year
    Cash flows used for equipment and resource
      propertiesFiscal 2014
    Cdn$3,834,000 (1)Fiscal 2013
    Cdn$2,041,000 (2)Fiscal 2012
Cdn$4,485,000 (3)


|(1) | $13,000 of these funds was spent on the purchase of
      corporate and other assets; and $3,821,000 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, 2014, filed with this annual report on Form
      20-F.)
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                                                                                                                                                                                                        
|(2) | $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.) 
|    |                                                                                                                                                                                                                                                                                                                                                                                        
|(3) | $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.) 

20

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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, 2014, the Company acquired
certain natural gas producing assets and related processing facilities adjacent
to its existing Woodrush oilfield at Ft. St. John, British Columbia, resulting
in the acquisition of an additional 9,600 net acres (44% developed).
Additionally, the Company acquired an additional 24% working interest in its
existing Woodrush oilfield to increase the working interest to 99%.

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.

Additions to property and equipment and exploration and
evaluation assets:

Year
      ended December 31, 2014
    
    
    Year
      ended December 31, 2013(CA$ thousands)
    
    $
    
    
    % of
      total
    
    
    $
    
    
    % of
      total
    
    
    %
      changeLand acquisition and
      retention
    
    102
    
    
    2.7%
    
    
    118
    
    
    5.8%
    
    
    -14%Drilling and completion
    
    554
    
    
    14.4%
    
    
    1,014
    
    
    49.7%
    
    
    -45%Facility and pipelines
    
    2,755
    
    
    71.9%
    
    
    257
    
    
    12.6%
    
    
    972%Capitalized general and administrative
    
    410
    
    
    10.7%
    
    
    645
    
    
    31.6%
    
    
    -36%Other assets
    
    13
    
    
    0.3%
    
    
    7
    
    
    0.3%
    
    
    86%Total (1)
    
    3,834
    
    
    100.0%
    
    
    2,041
    
    
    100.0%
    
    
    88%


|(1) | excludes non-cash capital expenditures of $3,440,000
      related to the acquisition of certain oil and natural gas producing assets
      in Drake/Woodrush
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------

*Daily Production*

|                                           |  | Three months ended December 31, |  |  | Year
      ended December 31, | 
|------------------------------------------ |  | ------------------------------- |  |  | ----------------------------- | 
|                                           |  | 2014                            |  |  | 2013                          | 
|By Product                                 |  |                                 |  |  |                               | 
|Oil and natural gas liquids
      (bbls/d) |  | 162                             |  |  | 167                           | 
|Natural gas (mcf/d)                        |  | 891                             |  |  | 2,714                         | 
|Total (boe/d)                              |  | 310                             |  |  | 620                           | 

The decrease in oil production for the year ended December 31,
2014 compared to the same period of 2013 was attributable to the temporary
production curtailment of the main oil producing wells at Woodrush due to the
Companys annual turnaround of its production facilities, combined with normal
declines.

The decrease in natural gas production for the three and twelve
months ended December 31, 2014 is due to the disposition of 65% of the Companys
working interest in its core natural gas property in the eastern portion of
Piceance Basin of Colorado on June 30, 2014. This was offset by the acquisition
of certain natural gas producing assets adjacent to the Companys existing
Woodrush properties in northeastern British Columbia.

21

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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 60,100 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*

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 2015.

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. Oil
prices fell down by half to a 5-1/2-year low since June 2014 under pressure from
a global glut of crude oil. In 2014, natural gas prices were remained relatively
stable 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".

22

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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
2015 and future years.

Employees:The Company had the equivalent of
approximately 10 full-time employees and consultants during 2014.

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:

| | 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*

2014

During the year ended December 31, 2014, the Company:

|1. | Completed an equity financing of 7,000,000 units at $0.11
      per common share in January 2014. Gross proceeds raised were
    $770,000;                                                                                                                                                                                                                                                                                                                                       
|-- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|2. | Completed the acquisition of certain natural gas
      producing assets and related processing facilities adjacent to the
      Companys existing Woodrush oilfield at Ft. St. John, British Columbia,
      resulting in the acquisition of an additional 9,600 net acres (44%
      developed);                                                                                                                                                                               
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|3. | Closed the sale of 65% of the Companys working interest
      in the initial four wells drilled in 2013 at its Kokopelli project in
      Colorado, together with certain related production facilities, for
      $4,136,000 (US$3,876,000) cash and a 25% carried working interest in a
      US$16.0 million eight-well drilling and completion program commenced in
      2014 and planned for completion in Q2 2015 to be funded 100% by the
      Purchaser of the assets;

23

---

|4. | Retired the related loan facility of $3.5 million due to
      a Canadian institutional lender;                                                                                                                                                                                                                                                                                                             
|-- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   |                                                                                                                                                                                                                                                                                                                                                                                                             
|5. | Closed the acquisition of an additional 24% working
      interest in the Drake/Woodrush oilfield in Northeastern B.C. to increase
      its working interest to 99%. As consideration for the purchase, the
      Company issued 9,600,000 common shares at a price of $0.202 per share for
      total share consideration of $1,939,000;                                                                 
|   |                                                                                                                                                                                                                                                                                                                                                                                                             
|6. | Completed an equity financing of 6,000,000 units at
      US$0.25 per unit in August 2014. Each unit consists of one common share
      and 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 until December 31, 2015. Gross proceeds raised were
      $1,640,000 (US$1,500,000); and
|   |                                                                                                                                                                                                                                                                                                                                                                                                             
|7. | Successfully drilled two new wells at the Companys
      Woodrush property, north of Fort St. John, British Columbia. The initial
      well is a new natural gas discovery in the Gething geological formation
      while the second well is a development well drilled into the extreme south
      end of the Companys Woodrush oil pool.                                                             

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;
|   |                                                                                                                                                                                                                                                                                                                                                                                          
|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;                                                                                                                                                                     

24

---

|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.                                                                  

United States vs. Foreign Sales/Assets

Net Revenue for fiscal year ended:
    Canada
    United States(Cdn$ in 000)
    $
    $12/31/2012
    5,766
    --12/31/2013
    6,038
    1,46812/31/2014
    5,952
    1,609


Asset Location as of:
    Canada
    United States(Cdn$ in 000)
    $
    $12/31/2012
    12,118
    15,45512/31/2013
    7,695
    17,80412/31/2014
    11,133
    12,141


Commodity Price Environment

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

Our results of operations and financial condition are
significantly affected by oil and natural gas commodity prices, which can
fluctuate dramatically. The market for oil and natural gas is beyond our control
and prices are difficult to predict. (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, 2014.

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, 2014
to be approximately $4,387,000. These obligations are expected to be settled
over the next 15 years with the majority of costs incurred between 2015 and
2029.

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.

25

---

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

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

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

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.

26

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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.

Hydraulic fracturing is an important and common practice that
is used to stimulate production of oil and/or natural gas from dense subsurface
rock formations. The hydraulic fracturing process involves the injection of
water, sand, and chemicals under pressure into the formation to fracture the
surrounding rock and stimulate production. We routinely use hydraulic fracturing
as part of our operations. The process is typically regulated by state oil and
natural gas commissions but the EPA has asserted federal regulatory authority
pursuant to the Safe Water Drinking Act, or SDWA, over certain hydraulic
fracturing activities involving the use of diesel. In addition, in May, 2014,
the EPA issued an Advance Notice of Proposed Rulemaking to collect data on
chemicals used in hydraulic fracturing operations under Section 8 of the Toxic
Substance Control Act. To date, no other action has been taken. At the state
level, several states have adopted or are considering legal requirements that
could impose more stringent permitting disclosure, and well construction
requirements on hydraulic fracturing activities.

We believe that we follow applicable standard industry
practices and legal requirements for groundwater protection in our hydraulic
fracturing activities. Nonetheless, if new or more stringent federal, state, or
local legal restrictions relating to the hydraulic fracturing process are
adopted in areas where we operate (primarily the State of Colorado at present),
we could incur potentially significant added costs to comply with such
requirements, experience delays or curtailment in the pursuit of exploration,
development, or production activities, and perhaps even be precluded from
drilling wells.

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

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

We expect to incur abandonment and site reclamation costs as
existing oil and gas properties are abandoned and reclaimed; however, we do not
anticipate making material expenditures beyond normal compliance with
environmental regulations in 2015 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

27

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- 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.

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.

28

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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
Williams 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.

During 2013, the Company drilled three additional wells and
completed all four wells in the Williams Fork formation. Production commenced in
September, 2013.

On June 30, 2014, the Company sold 65% of its 71.43% working
interest in the 4 wells, together with 65% of its remaining 1,542 acres at
Kokopelli for US$4,000,000 cash and a commitment by the Purchaser to spend
US$16,000,000 at Kokopelli to drill, complete, and equip seven wells to the base
of the Williams Fork formation and one well to the base of the Mancos/Niobrara
formation. Pursuant to the terms of the Purchase and Sale Agreement, the Company
was carried for 25% through the entire expenditure of US$16,000,000. Following
completion of the US$16,000,000 expenditure, the Company will retain a 25%
working interest in the 8 wells and the 1,542 acres.

The Company and its partners intend to continue to develop the
Kokopelli Project acreage in 2015 and have scheduled a capital expenditure
program of US$19,100,000, of which the Companys share is 25%, or US$4,775,000.
The program will consist of lease roads, facilities, and pipeline construction
as well as the drilling of a send Mancos/Niobrara well to a depth of
approximately 13,000 ft., and is scheduled to commence in Q3 2015.

Roan Creek, Piceance Basin

During 2014, the Company commissioned a Prospective Reserve
Report, by Gustavson and Associates, on the Companys 1,980-acre lease at Roan
Creek.

The Report concluded there are 70 Bcf of contingent natural
gas resources and 51 Bcf of prospective natural gas reserves to be developed
at Roan Creek.

The Company intends to explore Roan Creek in 2016 and is
presently seeking a joint venture partner.

Canadian Oil and Gas Interests

Drake/Woodrush, Fort St. John, British Columbia

The Companys Drake/Woodrush oilfield is located about 110 km.
north of Fort St. John, British Columbia, Canada. In March 2014, the Company
purchased certain natural gas producing assets and related processing facilities
adjacent to its existing Woodrush oilfield at Ft. St. John, British Columbia.
The assets acquired included a 54% working interest in a Halfway formation well,
a 74% working interest in 2 shut-in natural gas wells, a 96.8% working interest
in a Sour Processing Facility, and an additional 9,600 net acres (44%
developed).

29

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In July 2014, the Company acquired an additional 24% working
interest in its existing Drake/Woodrush oilfield to increase its working
interest to 99%. As consideration for the purchase, the Company issued 9,600,000
common shares at a price of $0.202 per share for $1,939,000. The Company
presently owns a 99% working interest at its existing Drake/Woodrush oilfield in
4 producing oil wells and 5 producing natural gas wells.

In December 2014, the Company commenced the drilling of 2
infill wells (1 oil well and 1 natural gas well) in Northeastern, British
Columbia. In January 2015, the Company successfully completed the 2 wells and
tied them into its Woodrush production facility. The production additions have
resulted in approximately 700 BOEPD net to the Companys working interest.

Summary of Operational Highlights

|Year-to-date 2014
      vs. Year-to-date 2013    |  | Year
      ended December 31 |  |  |       | 
|------------------------------------------------ |  | ---------------------------- |  |  | ----- | 
|(CA$ thousands,
      except as otherwise noted) |  | 2014                         |  |  | 2013  | 
|Production Volumes:                              |  |                              |  |  |       | 
|Oil and natural gas liquids (bbls/d)             |  | 182                          |  |  | 215   | 
|Natural gas (mcf/d)                              |  | 1,602                        |  |  | 1,733 | 
|Total (BOE/d)                                    |  | 449                          |  |  | 504   | 
|                                                 |  |                              |  |  |       | 
|Average realized prices:                         |  |                              |  |  |       | 
|Oil and natural gas liquids ($/bbl)              |  | 87.99                        |  |  | 86.21 | 
|Natural gas
      ($/mcf)                        |  | 5.45                         |  |  | 4.06  | 
|Total ($/BOE)                                    |  | 55.14                        |  |  | 50.79 | 
|                                                 |  |                              |  |  |       | 
|Revenue, before royalties:                       |  |                              |  |  |       | 
|Oil and natural gas liquids                      |  | 5,854                        |  |  | 6,768 | 
|Natural gas                                      |  | 3,195                        |  |  | 2,547 | 
|Total                                            |  | 9,049                        |  |  | 9,317 | 

For the year ended December 31, 2014, total revenue, before
royalties, decreased by $268,000 or, 3%, due to a decline in production. This
was offset by higher combined average realized prices.

The decrease in oil production for the year ended December 31,
2014 compared to the same period of 2013 was attributable to the temporary
production curtailment of the main oil producing wells at Woodrush due to the
Companys annual turnaround (routine maintenance) of its production
facilities, combined with normal declines.

The decrease in natural gas production for the year ended
December 31, 2014 is due to the disposition of 65% of the Companys working
interest in its core natural gas property in the eastern portion of Piceance
Basin of Colorado on June 30, 2014. This was offset by the acquisition of
certain natural gas producing assets adjacent to the Companys existing Woodrush
properties in northeastern British Columbia.

Oil Operations

Average oil royalties paid for the year ended December 31, 2014
($14.77 per barrel) were consistent with those paid in the year ended December
31, 2013 ($16.81 per barrel).

Operating and transportation expenses for the year ended
December 31, 2014 ($27.65 per barrel) were consistent with those paid in the
year ended December 31, 2013 ($26.75 per barrel).

30

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Natural Gas Operations

The average price received for gas sales increased by 34% for
the year ended December 31, 2014, relative to the prior year. The increase in
Dejours average realized gas price reflected higher benchmark prices in both
Canada and the United States.

Average gas royalties paid in the year ended December 31, 2014
were higher compared to the prior year. The average gas price received in 2014
was comparatively higher than the prices received in 2013. This resulted in
higher royalty rates for marginal gas production in 2014.

Average operating and transportation expenses paid for the year
ended December 31, 2014 were higher compared to the prior year. The increase
resulted from the costs associated with the workover of one of the gas producing
wells at Drake/Woodrush, the start-up costs related to the acquisition of
certain natural gas producing assets and related production facilities adjacent
to the Drake/Woodrush oilfield, and higher contractual pipeline transportation
costs in 2014 in Canada. Further, in Q4 2014, the Company incurred a repair to
one of the Companys two compressor facilities which also contributed to an
increase in the operating and transportation expenses.

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

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
($16.81 per barrel) were consistent with those paid in the year ended December
31, 2012 ($15.06 per barrel).

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.

31

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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.

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, 2014. The conversion
rate used per Bank of Canada is 1.1601.

In 2014, 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 January
27, 2015 and has an effective date of December 31, 2014.

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 February 17, 2015 and has an effective
date of January 1, 2015.

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, 2014 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, 2014 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.

32

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As of December 31, 2014, 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.

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

Net ReservesProved Reserves Category
    Oil
      (Mbbl)
    Condensate
      (MBO)
    Natural Gas
      (Mmcf)
    Natural Gas
      Liquids(Mbbl)DevelopedCanada
    155
    -
    1,435
    4United States
    -
    13
    1,874
    109UndevelopedCanada
    -
    -
    -
    -United States
    -
    194
    28,449
    1,650TOTAL PROVED
    155
    207
    31,758
  1,763


Given economic commodity prices, the Company plans to fully
develop its reserves over the next five years.

Canada  Increase in Total Proved Oil Reserves of 41 Mbbls and
Natural Gas Reserves of 969 MMcf:

During the year ended December 31, 2014, the Company acquired
an additional 24% working interest in its northeastern British Columbia
properties and increased total proved oil and natural gas reserves by 41 Mbbls
and 969 MMcf respectively.

United States  Decrease in Total Proved Natural Gas Liquids
Reserves of 1,837 Mbbls and Natural Gas Reserves of 56,288 MMcf:

During the year ended December 31, 2014, the Company sold 65%
of its working interest at Kokopelli in Colorado, resulting in a reduction of
its total proved natural gas and natural gas liquids by 56,288 MMcf and 1,837
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, 2014Canada (Proved Developed and Undeveloped
      Reserves)
    Natural Gas
    Oil
    Natural Gas Liquids
    Total
    PV-10(2)(Mmcf)
    (Mbbl)
    (Mbbl)
    (Mmcfe)
    (in thousands
     Cdn$)2014 12-month average prices (SEC) (1)
    1,435
    155
    4
    2,389
  $7,303


33

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December 31, 2014United States (Proved Developed and
     Undeveloped Reserves)
    Natural Gas
    Condensate
    Natural Gas
     Liquids
    Total
    PV-10(2)(Mmcf)
    (Mbbl)
    (Mbbl)
    (Mmcfe)
    (in thousands
     Cdn$)2014 12-month average prices (SEC) (1)
    30,323
    207
    1,759
    42,119
  $60,792


December 31, 2014Total (Proved Developed and
    
    
    
    NaturalGasUndeveloped Reserves)
    Natural Gas
    Oil
    Condensate
    Liquids
    Total
    PV-10(2)(Mmcf)
    (Mbbl)
    (Mbbl)
    (Mbbl)
    (Mmcfe)
    (in thousands
     Cdn$)2014 12-month average prices (SEC) (1)
    31,758
    155
    207
    1,763
    44,508
  $68,095


Reconciliation to Standardized Measure

|As at December 31, 2014                                                    |   |        |  |   |         |   |   |         |  
|-------------------------------------------------------------------------- | - | ------ |  | - | ------- | - | - | ------- | -
|(in thousands of Canadian dollars)                                         |   | Canada |  |   | USA     |   |   | Total   |  
|Present value of
      estimated future net cash flows before income taxes | $ | 7,303  |  | $ | 60,792  |   | $ | 68,095  |  
|Income taxes - discounted                                                  |   | -      |  |   | (20,133 | ) |   | (20,133 | )
|Standardized measure of discounted future net cash flow                    | $ | 7,303  |  | $ | 40,659  |   | $ | 47,962  |  

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 2014, adjusted for pipeline transportation costs from
      the wellhead to the interstate pipeline prevailing at December 31, 2014.
      The 12-month average prices (SEC) used for Canadian properties were
      Cdn$87.29 per barrel of oil and Cdn$4.39 per Mcf of natural gas. The
      12-month average prices (SEC) used for US properties were US$84.16 per
      barrel of condensate, US$4.98 per Mcf of natural gas, and US$69.01 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, 2014, which is US$1.00 =
      Cdn$1.1601.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              

34

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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, 2014, 2013 and 2012. Production came from our
Canadian and United States properties. Production from our United States
properties commenced in the fiscal year ended December 31, 2013.

ProductionFiscal Year
      Ended
    Oil and Natural Gas
      Liquids(bbls)
    Natural Gas
      (Mcf)
    Total (BOE)December 31, 2014
    66,485
    584,566
    163,911December 31, 2013
    78,566
    632,467
    183,977December 31, 2012
    72,567
    380,780
  136,031


The following table includes the average prices the Company
received for its production for the fiscal years ended December 31, 2014, 2013
and 2012.

Average Sales PricesFiscal Year
      Ended
    Oil and Natural Gas
      Liquids($/bbls)
    Natural Gas
      ($/Mcf)
    Total
      ($/BOE)December 31, 2014
    87.99
    5.45
    55.14December 31, 2013
    86.21
    4.06
    50.79December 31, 2012
    81.37
    2.57
  50.59


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, 2014, 2013 and 2012.

Average Production CostsFiscal Year Ended
    Oil and Natural GasLiquids($/bbls)
    Natural Gas($/Mcf)
    Total($/BOE)December 31, 2014
    42.42
    4.72
    34.03December 31, 2013
    42.91
    2.83
    28.03December 31, 2012
    36.64
    2.80
    27.36


Drilling and Other Exploratory and Development Activities

During the fiscal year ended December 31, 2014, we drilled the
following wells in Canada and the United States:

Net Exploratory Wells
    **Net Development Wells**Canada
    Productive
    Dry
    Productive
    DryOil
    -
    -
    0.99
    -Natural Gas
    -
    -
    0.99
    -Total Wells
    -
    -
    1.98
    -


35

---

Net Exploratory Wells
    **Net Development
    Wells**U.S.A
    Productive
    Dry
    Productive
    DryNatural Gas
    -
    -
    2.00
    -Total Wells
    -
    -
    2.00
    -


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
    DryNatural 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
    DryNatural Gas
    -
    -
    0.20
    -Total Wells
    -
    -
    0.20
    -


*Delivery Commitments*

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

Oil and Gas Properties and Wells

The following tables summarizes the number of producing and
non-producing wells as at December 31, 2014:

Producing WellsCountry
    Oil
    Natural GasGross
    Net
    Gross
    NetCanada
    3
    2.97
    5
    4.34USA
    -
    -
    4
    0.29Total
    3
    2.97
    9
  4.63


Non-Producing WellsCountry
    Oil(1)
    Natural Gas(2)Gross
    Net
    Gross
    NetCanada
    5
    4.95
    25
    18.58USA
    -
    -
    -
    -Total
    5
    4.95
    25
  18.58


|(1) | Includes water source wells and injection wells                                        
|--- | ---------------------------------------------------------------------------------------
|    |                                                                                        
|(2) | Includes non-producing wells, shut-in wells and wells
      being temporarily suspended

36

---

The following tables summarizes the number of producing and
non-producing wells as at December 31, 2013:

Producing WellsCountry
    Oil
    Natural GasGross
    Net
    Gross
    NetCanada
    3
    2.25
    5
    3.63USA
    -
    -
    4
    0.83Total
    3
    2.25
    9
  4.46


Non-Producing WellsCountry
    Oil(1)
    Natural Gas(2)Gross
    Net
    Gross
    NetCanada
    5
    3.75
    8
    5.17USA
    -
    -
    -
    -Total
    5
    3.75
    8
  5.17


|(1) | Includes water source wells and injection wells                                        
|--- | ---------------------------------------------------------------------------------------
|    |                                                                                        
|(2) | Includes non-producing wells, shut-in wells and wells
      being temporarily suspended

The following tables summarizes the number of producing and
non-producing wells as at December 31, 2012:

Producing WellsCountry
    Oil
    Natural GasGross
    Net
    Gross
    NetCanada
    3
    2.25
    4
    2.94USA
    -
    -
    1
    0.39Total
    3
    2.25
    5
  3.33


Non-Producing WellsCountry
    Oil(1)
    Natural Gas(2)Gross
    Net
    Gross
    NetCanada
    5
    3.75
    9
    5.86USA
    -
    -
    -
    -Total
    5
    3.75
    9
  5.86


|(1) | Includes water source wells and injection wells                                        
|--- | ---------------------------------------------------------------------------------------
|    |                                                                                        
|(2) | Includes non-producing wells, shut-in wells and wells
      being temporarily suspended

*Interest in Oil and Gas Properties*

The following table sets forth information for our interest in
oil and gas properties as of December 31, 2014 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, 2014, the Companys developed and
undeveloped acres are as follows:

Developed Acreage
    Undeveloped Acreage
    TotalGross
    Net
    Gross
    Net
    Gross
    NetCanada
    12,184
    8,009
    10,626
    8,613
    22,810
    16,622U.S.A
    2,240
    1,407
    62,107
    42,098
    64,347
    43,505TOTAL
    14,424
    9,416
    72,733
    50,711
    87,157
  60,127


37

---

The Companys net undeveloped acres as of December 31, 2014,
together with expiries for the period from 2015 to 2017 and thereafter is as
follows.

Undeveloped AcreageAs of December 31,
      2014
    Net
    2015 Expirations
    2016 Expirations
    2017 and thereafter
     ExpirationsCanada:Manning
    506
    -
    -
    506Woodrush/Hunter
    8,107
    2,057
    -
    6,050Subtotal:
    8,613
    2,057
    -
    6,556U.S.A:Ashley
    480
    -
    -
    480Book Cliffs
    2,082
    320
    
    1,762Dinosaur
    26,642
    -
    7,670
    18,971Gunnison
    753
    -
    753
    -North Rangely
    4,910
    2,350
    1,280
    1,280Pinyon Ridge
    2,237
    -
    1,584
    653Plateau
    3,014
    -
    535
    2,479Roan Creek
    1,981
    21
    -
    1,961Subtotal:
    42,098
    2,691
    11,822
    27,586TOTAL:
    50,711
    4,748
    11,822
  34,141


38

---

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, 2014 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, 2014, 2013 and 2012 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 AND ASSUMPTIONS

The Company makes estimates and assumptions about the future
that affect the reported amounts of assets and liabilities. Estimates and
assumptions 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 results 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 assumptions 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 in which the new information becomes available.

39

---

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. Effective June 30, 2014, the Companys financial contract
liability was reduced by the residual reserve value of the working interest in
the wellbores at September 30, 2016.

At December 31, 2014, the financial contract liability was
adjusted to reflect the present value of the amount outstanding at September 30,
2016, net of the present value of the residual reserves of the working interest
in the wellbores to be acquired upon repayment of the financial contract
liability in full.

Impairment

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.
In determining the recoverable amount, the key assumptions the Company uses in
estimating future cash flows for recoverable amounts are anticipated future
commodity prices, expected production volumes, future operating and development
costs, and discount rate. 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, 2014, 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 valuation methodologies that utilize observable market data where
available. 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.

FUTURE ACCOUNTING PRONOUNCEMENTS

Certain pronouncements were issued by IASB or IFRIC that
are mandatory for accounting periods beginning after January 1, 2015 or later
periods.

40

---

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:

IAS 1, Presentation of Financial Statements: In December
2014, the IASB issued amendments to IAS 1, clarifying guidance on the concepts
of materiality and aggregation of items in the financial statements, the use and
presentation of subtotals in the statement of operations and comprehensive
income or loss, and providing additional flexibility in the structure and
disclosures of the financial statements to enhance understandability. The
amendments to IAS 1 may be applied immediately, and become mandatory for annual
periods beginning on or after January 1, 2016.

IFRS 9, Financial Instruments: In July 2014, the IASB
completed the final phase of its project to replace IAS 39, the current standard
on the recognition and measurement of financial instruments. IFRS 9 is now the
new standard which sets out the recognition and measurement requirements for
financial instruments and some contracts to buy or sell non-financial items.
IFRS 9 proposes a single model of classifying and measuring financial assets and
liabilities and provides for only two classification categories: amortized cost
and fair value. Hedge accounting requirements have also been updated in the new
standard and are now more aligned with the risk management activities of an
entity. IFRS 9 is effective for annual periods beginning on or after January 1,
2018. Early adoption is permitted; however, if an entity elects to apply this
standard early, it must disclose that fact and apply all of the requirements in
this standard at the same time.

IFRS 11, Joint Arrangements: In May 2014, the IASB issued
amendments to IFRS 11 to address the accounting for acquisitions of interests in
joint operations. The amendments address how a joint operator should account for
the acquisition of an interest in a joint operation in which the activity of the
joint operation constitutes a business. IFRS 11, as amended, now requires that
such transactions be accounted for using the principles related to business
combinations accounting as outlined in IFRS 3, Business Combinations. The
amendments are to be applied prospectively and are effective for annual periods
beginning on or after January 1, 2016, with earlier application permitted.

IFRS 15, Revenue from Contract with Customers. The IASB
issued the standard to replace IAS 18 which establishes principles for reporting
useful information to users of financial statements about the nature, amount,
timing and uncertainty of revenue and cash flows arising from an entitys
contracts with customers. The standard is effective for the Company for annual
periods beginning on January 1, 2017, with required retrospective application
and early adoption permitted.

IAS 16, Property, Plant and Equipment and IAS 38, Intangible
Assets:In May 2014, the IASB issued amendments to IAS 16 and IAS 38 to
clarify acceptable methods of depreciation and amortization. The amended IAS 16
eliminates the use of a revenue-based depreciation method for items of property,
plant and equipment. Similarly, amendments to IAS 38 eliminate the use of a
revenue-based amortization model for intangible assets except in certain
specific circumstances. The amendments are to be applied prospectively and are
effective for annual periods beginning on or after January 1, 2016, with earlier
application permitted.

A.            
Operating Results

The Companys annual audited Consolidated Financial Statements
for the year ended December 31, 2014, including 2013 and 2012 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, 2014 compared to the year ended
December 31, 2013

1.Revenues

For the year ended December 31, 2014, total revenue, before
royalties, decreased by $268,000 or, 3%, due to a decline in production. This
was offset by higher combined average realized prices..

2.Oil Operations

Average oil royalties paid for the year ended December 31, 2014
($14.77 per barrel) were consistent with those paid in the year ended December
31, 2013 ($16.81 per barrel).

41

---

Operating and transportation expenses for the year ended
December 31, 2014 ($27.65 per barrel) were consistent with those paid in the
year ended December 31, 2013 ($26.75 per barrel).

3.Natural Gas Operations

The average price received for gas sales increased by 34% for
the year ended December 31, 2014, relative to the prior year. The increase in
Dejours average realized gas price reflected higher benchmark prices in both
Canada and the United States.

Average gas royalties paid in the year ended December 31, 2014
were higher compared to the prior year. The average gas price received in 2014
was comparatively higher than the prices received in 2013. This resulted in
higher royalty rates for marginal gas production in 2014.

Average operating and transportation expenses paid for the year
ended December 31, 2014 were higher compared to the prior year. The increase
resulted from the costs associated with the workover of one of the gas producing
wells at Drake/Woodrush, the start-up costs related to the acquisition of
certain natural gas producing assets and related production facilities adjacent
to the Drake/Woodrush oilfield, and higher contractual pipeline transportation
costs in 2014 in Canada. Further, in Q4 2014, the Company incurred a repair to
one of the Companys two compressor facilities which also contributed to an
increase in the operating and transportation expenses.

4.General and Administrative Expenses

G&A expenses in fiscal 2014 were consistent with the amount
recorded for fiscal 2013. G&A expenses included the cost of non-recurring
severance payments of approximately $306,000 associated with the termination of
a number of the Companys service providers in the 2nd half of 2014.
Adjusting for these payments results in a 6% reduction in G&A expenses from
the year ended December 31, 2013 to the year ended December 31, 2014.

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
($16.81 per barrel) were consistent on a percentage basis with those paid in the
year ended December 31, 2012 ($15.06 per barrel).

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.

42

---

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 expenses included 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 expenses from the year ended December 31, 2012 to the year ended
December 31, 2013.

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.

B.            
Liquidity and Capital Resources

Bank Credit Facility

Under the terms of the Credit Facility, 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 Facility) 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, 2014, DEAL was in default of its working capital ratio covenant
with a 0.56 to 1 ratio.

Cash Balances

The Company had cash and cash equivalents of $1,215,000 as at
December 31, 2014.

Financial Contract

On December 31, 2012, Dejour USA entered into a financial
contract with a U.S. oil and gas drilling fund (Drilling Fund) to fund the
drilling of up to three wells and the completion of up to four wells in the
State of Colorado. The Drilling Fund contributed US$6.5 million cash to earn
working interests in production from the wellbores ranging from 55.56% to 77.78%
before payout and 44.44% to 58.33% after payout. This amount was subsequently
increased by US$500,000 to US$7,000,000 with the Companys consent.

The December 31, 2012 financial contract states the Drilling
Fund has the right to require Dejour USA to purchase its working interests in
the wellbores for cash in September 2016, 36-months after the final well in the
4-well program is placed in production. The repurchase price is based on a
predetermined formula which ensures the Drilling Fund earns a minimum return,
compounded annually and applied on a monthly basis, on 75% of its original
US$7,000,000 investment over the 36-month period. Accordingly, the Company
considered the transaction to be a financial contract as the risks and rewards
of ownership were not substantially transferred to the Drilling Fund and, on
December 31, 2012, the Company recorded the transaction in its accounts by
increasing property and equipment and financial contract liability by
US$6,500,000 on its balance sheet. This amount was subsequently increased to
US$7,000,000.

43

---

On June 30, 2014, the financial contract was amended and the
Drilling Fund agreed to retain its working interest in the wells as at September
30, 2016, should it exercise its right to require Dejour USA to pay the minimum
return calculated in accordance with the provisions of the contract. In
determining the minimum return to be paid, the Drilling Fund agreed to deduct
the residual reserve value of its working interest in the 4 wellbores at
September 30, 2016. The parties also agreed to have a third party engineering
firm calculate the residual value of the reserves in accordance with industry
accepted valuation standards.

Finally, the parties agreed to limit the cash consideration to
be paid by Dejour USA, should it be required to pay the minimum return provided
for in the December 31, 2012 contract to US$3,000,000. Additional consideration,
if any, may be paid by Dejour USA by an assignment of a working interest in
certain proven assets at a jointly owned oil and gas property in Colorado
applying an industry-standard valuation approach.

The June 30, 2014 amendment transferred the risks of ownership
of the 4 wellbores back to the Drilling Fund and the financial contract
liability was adjusted to reflect the present value of the amount owing to the
Drilling Fund under the financial contract at September 30, 2016 ($5,519,000),
net of the present value of the residual reserves ($2,780,000), or $2,739,000,
as follows:

|                                                                     |  | $      |  
|-------------------------------------------------------------------- |  | ------ | -
|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  |  
|Loan advance during the year (US$181)                                |  | 210    |  
|Accretion expense (US$388)                                           |  | 450    |  
|Foreign exchange
      loss                                          |  | 351    |  
|                                                                     |  | 7,132  |  
|Less:                                                                |  |        |  
|(a)      Net
      operating income (US$846)                         |  | (982   | )
|(b)      Adjustment to financial
      contract liability (US$3,117) |  | (3,411 | )
|Balance at December 31, 2014 (US$2,361)                              |  | 2,739  |  

Working Capital Position

|As at December 31, 2014 (CA$ thousands)                                |  | $      |  
|---------------------------------------------------------------------- |  | ------ | -
|Working capital deficit                                                |  | (4,480 | )
|Non-cash warrant liability                                             |  | 755    |  
|Non-cash derivative liability                                          |  | 216    |  
|Adjusted working capital deficit                                       |  | (3,509 | )
|Add: Bank line of credit                                               |  | 1,955  |  
|Adjusted working
      capital deficit (excluding bank line of credit) |  | (1,554 | )

Working capital is defined as current assets less current
liabilities.

44

---

As at December 31, 2014, the Company had a working capital
deficit of $4.5 million. Excluding the non-cash warrant liability of $0.8
million related to the fair value of US$ denominated warrants issued in previous
equity financings, the non-cash derivative liability of $0.2 million related to
the fair value of warrants issued in loan facility closed in June 2013, the
adjusted working capital deficit was $3.5 million. The majority of the working
capital deficit relates to the $2.0 million outstanding bank line of credit.
And, the remainder of the deficit relates to the costs associated with the
drilling of the 2 new wells at the Companys Woodrush property. Our independent
auditors have included an explanatory paragraph in their report on our
consolidated financial statements for the year ended December 31, 2014 that
describes uncertainties that cast substantial doubt about our ability to
continue as a going concern.

Subsequent to December 31, 2014, the Company secured a $2
million loan from a director of the Company to support its operations. Further,
the Company expects to fund operations and capital expenditures with cash flows
from operations, drawings on bank credit facilities, additional loans from the
director, existing cash and cash equivalents and by accessing the capital
markets, as required. However, there is no assurance that these activities or
any attempt to raise additional capital will be successful.

Capital Resources

a)Canada

In December 2014, the Company incurred approximately $2.3
million to drill 2 infill wells at Drake/Woodrush in northeastern British
Columbia. In 2015, the Company will continue to complete these 2 infill wells.
These capital expenditures will be funded by cash on hand and an operating line
of credit of $2,050,000 provided by DEALs Canadian bank.

b)United States

In the U.S., the Companys share of expenditures for the
ongoing Kokopelli development program is estimated to be US$8 million. The
Company expects to fund this program through the use of a combination of cash
provided by operating activities and new equity or debt offerings, as required.

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

None.

D.            
Trend Information

a)Oil Prices

Over the past three-to-four years, oil production from
unconventional oil shale projects in the USA has experienced major growth. This
has come at a time when demand from the developed world has been subdued and
demand growth form China and the other major emerging economies has slowed. The
growing imbalance between supply and demand was brought to a head at the
Organization of Petroleum Exporting Countries (OPEC) meeting in November 2014
when Saudi Arabia stated they were no longer prepared to cede market share to
accommodate rising production from the USA.

As a result of these pressures, the oil price collapsed from a
peak of US$115.00/Bbl. in mid-2014 to $53.00/Bbl. at the end of the 2014. These
softer oil prices will likely continue until supply decreases from a reduction
in the number of active US drilling rigs and demand strengthens as the economies
in the developed world improve.

45

---

b)Natural gas

During 2014, there was continued strong production growth in
North America driven by increased shale gas development in the United States and
the availability of lower-cost capital for development projects of merit. The
combination of these factors resulted in ongoing lower natural gas prices for
producers.

This situation will likely continue until demand increases as a
result of new liquid natural gas initiatives (LNG), industrial growth,
increased exports to Mexico, and commencement of operations of new power
generation facilities currently under construction.

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, 2014.

F.            
Tabular Disclosure of Contractual Obligations

As of December 31, 2014, and in the normal course of business
we have obligations to make future payments, representing contracts and other
commitments that are known and committed.

(CA$ thousands)
    
    2015
    
    
    2016
    
    
    2017
    
    
    2018
    
    
    2019
    
    
    Thereafter
    
    
    Total$
    
    
    $
    
    
    $
    
    
    $
    
    
    $
    
    
    $
    
    
    $Operating lease obligations
    
    130
    
    
    49
    
    
    -
    
    
    -
    
    
    -
    
    
    Nil
    
    
    179Bank credit facility
    
    1,955
    
    
    -
    
    
    -
    
    
    -
    
    
    -
    
    
    Nil
    
    
    1,955Financial contract liability(1)
    
    -
    
    
    2,739
    
    
    -
    
    
    -
    
    
    -
    
    
    Nil
    
    
    2,739Total
    
    2,085
    
    
    2,788
    
    
    -
    
    
    -
    
    
    
    
    
    Nil
    
    
    4,873


|(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 details.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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.

46

---

Name, Jurisdictionof
        Residence andPosition**(1)**
    Principal occupation oremployment during the past5 years
    Number of Dejour CommonShares beneficially owned,directly or indirectly,
        orcontrolled or directed (2)
    Percentage of DejourCommon Sharesbeneficially owned, directlyor indirectly, or controlledor directed(2)
    DirectorSinceRobert L.HodgkinsonBritish Columbia, CanadaDirector, Chairman and Chief
      Executive Officer(Age: 65)
    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).
    10,000,000
    5.48%
    May 18, 2004Craig Sturrock(3)(4)(5)British Columbia, CanadaDirector
     (Age: 71)
    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
    0.36%
    August 22, 2005Dr. A. Gorrell(5)(6)British Columbia, CanadaDirector(Age: 70)
    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.
    50,000
    0.03%
    December 14, 2012Richard Kennedy(4)(5)Alberta, CanadaDirector(Age: 59)
    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
    0.16%
    December 14, 2012Ronnie Bozzer(3)(4)(6)British Columbia, CanadaDirector(Age: 65)
    Mr. Bozzer has extensive years of legal practice
      encompassing mergers and acquisitions, banking and finance transactions,
      public private partnerships, syndications and securitizations.
    450,000
    0.25%
  January 15, 2014


47

---

Name, Jurisdictionof
      Residence andPosition**(1)**
    Principal occupation oremployment during the past5 years
    Number of Dejour CommonShares beneficially owned,directly or indirectly,
      orcontrolled or directed (2)
    Percentage of DejourCommon Sharesbeneficially owned, directlyor indirectly, or controlledor directed(2)
    DirectorSinceJames Dai(3)(6)British Columbia, CanadaDirector(Age: 33)
    Mr. Dai is a capital markets professional in Canada.
      Currently, he is the CFO of four private and public companies focused in
      the lumber, O&G, mining and biotech sectors of Western Canada. He has
      an investment banking background from Raymond James and has assisted Asian
      investors invest over $200 million into Canadian capital markets.
    -
    -
    March 16, 2015David MathesonBritish Columbia,
      CanadaChief Financial Officer(Age: 65)
    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


|(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 governance and nominating committee.                                                                                                                                                                                                                              
|(5) | Member of compensation committee.                                                                                                                                                                                                                                           
|(6) | Member of reserves
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.

48

---

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.

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.

Ronnie Bozzer:Mr. Bozzer's legal practice encompasses
mergers and acquisitions, banking and finance transactions, public private
partnerships, syndications and securitizations. His honours include receiving
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 Canadian
Leading Lawyer in the field of Corporate Law by "Law Day".

James Dai:Mr. Dai is a capital markets professional in
Canada. Currently, he is the CFO of four private and public companies focused in
the lumber, O&G, mining and biotech sectors of Western Canada. He has an
investment banking background from Raymond James and has assisted Asian
investors invest over $200 million into Canadian capital markets.

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.

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

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.

49

---

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.

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.

50

---

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 10,731,616 stock options to the
executive officers in 2014.

Summary Compensation Table

The following table provides a summary of the compensation
earned during the fiscal year ended December 31, 2014 for the Named Executive
Officers and Directors listed in the table below.

51

---

Annual Compensation
    Long Term CompensationName and
     principalposition
    Year
    Salary($)
    ConsultingFees
     ($)
    Bonus($)
    Awards
    Payouts($)
    All other
     compensation($)SecuritiesUnder
     Option/SAR'sGranted(#)
    Shares/Units
     Subject toResaleRestrictions
     ($)Robert Hodgkinson,Director, Chairman and
     Chief Executive Officer
    201420132012
    78,000
      78,00078,000
    174,600
      177,000177,000
    100,000(4)
      NilNil
    3,411,914
      775,000775,000
    Nil
      NilNil
    Nil
      NilNil
    Nil
      NilNilDavid Matheson,Chief Financial Officer
    20142013
    199,038
      188,141
    Nil
      Nil
    100,000(4)
      Nil
    2,109,570
      750,000
    Nil
      Nil
    Nil
      Nil
    Nil
      NilCraig Sturrock,Director
    201420132012
    Nil
      NilNil
    Nil
      NilNil
    Nil
      NilNil
    994,703
      250,000250,000
    Nil
      NilNil
    Nil
      NilNil
    8,500
      7,5007,500Dr. A. GorrellDirector
    201420132012
    Nil
      NilNil
    Nil
      NilNil
    Nil
      NilNil
    448,633
      Nil300,000
    Nil
      NilNil
    Nil
      NilNil
    7,000
      7,000500Richard KennedyDirector
    201420132012
    Nil
      NilNil
    Nil
      NilNil
    Nil
      NilNil
    543,359
      Nil300,000
    Nil
      NilNil
    Nil
      NilNil
    8,000
      6,500500Ronnie BozzerDirector
    2014
    Nil
    Nil
    Nil
    695,313
    Nil
    Nil
    8,500Harrison Blacker,Director and President
      of Dejour Energy (USA) (1)
    201420132012
    US$ 60,606
      US$ 310,000US$ 326,688
    Nil
      NilNil
    US$ Nil
      US$ NilUS$ Nil
    Nil
      775,000775,000
    Nil
      NilNil
    Nil
      NilNil
    Nil
      NilNilNeyeska Mut,EVP Operations of Dejour
      Energy(USA) (2)
    201420132012
    US$ 124,009
      US$ 200,470US$ 200,470
    Nil
      NilNil
    US$ Nil
      US$ NilUS$ Nil
    1,795,312
      450,000400,000
    Nil
      NilNil
    Nil
      NilNil
    Nil
      NilNilPhillip Bretzloff,VP and General Counsel
      (3)
    201420132012
    Nil
      NilNil
    204,130
      141,647141,584
    Nil
      NilNil
    732,812
      225,000225,000
    Nil
      NilNil
    Nil
      NilNil
    Nil
  NilNil


|(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) | Mrs. Mut left her position with Dejour Energy (USA) Corp.
      as Executive Vice President, Operations on July 16, 2014 and ceased to be
      an executive officer of the Corporation. On July 16, 2014, Mrs. Mut
      entered into a consulting agreement with the Corporation.                                                                                                                                
|    |                                                                                                                                                                                                                                                                                                                                                                                                                    
|(3) | Mr. Bretzloff was the VP and General Counsel of the
      Corporation until his departure on June 30, 2014. He ceased to be an
      executive officer of the Corporation effective that date. Amount
      represents Mr. Bretzloffs remuneration from January 1, 2014 to June 30,
      2014 in his capacity as VP and General Counsel, $72,130 of paid consulting
      fees and $132,000 of severance payment.
|    |                                                                                                                                                                                                                                                                                                                                                                                                                    
|(4) | Included in accounts payable and accrued liabilities at
      December 31, 2014. The repayment is subject to the availability of cash
      after all other key obligations are met.                                                                                                                                                                                                                               

52

---

Stock Option Grants

Name
    Number of
      Options Granted
    Exercise Price
      per Share
    Grant Date
    Expiration DateRobert Hodgkinson
    450,000
    $0.20
    January 31, 2014
    January 30, 2019Robert Hodgkinson
    2,325,000
    $0.26
    April 9, 2014
    April 8, 2017Robert Hodgkinson
    70,312
    $0.26
    April 25, 2014
    April 24, 2017Robert Hodgkinson
    566,602
    $0.29
    August 18, 2014
    August 17, 2017Craig Sturrock
    100,000
    $0.20
    January 31, 2014
    January 30, 2019Craig Sturrock
    750,000
    $0.26
    April 9, 2014
    April 8, 2017Craig Sturrock
    15,625
    $0.26
    April 25, 2014
    April 24, 2017Craig Sturrock
    129,078
    $0.29
    August 18, 2014
    August 17, 2017Dr. A. Gorrell
    50,000
    $0.20
    January 31, 2014
    January 30, 2019Dr. A. Gorrell
    289,062
    $0.26
    April 25, 2014
    April 24, 2017Dr. A. Gorrell
    50,000
    $0.25
    July 3, 2014
    July 2, 2017Dr. A. Gorrell
    59,571
    $0.29
    August 18, 2014
    August 17, 2017Richard Kennedy
    100,000
    $0.20
    January 31, 2014
    January 30, 2019Richard Kennedy
    300,000
    $0.26
    April 9, 2014
    April 8, 2017Richard Kennedy
    46,875
    $0.26
    April 25, 2014
    April 24, 2017Richard Kennedy
    96,484
    $0.29
    August 18, 2014
    August 17, 2017Ronnie Bozzer
    400,000
    $0.20
    January 31, 2014
    January 30, 2019Ronnie Bozzer
    100,000
    $0.26
    April 9, 2014
    April 8, 2017Ronnie Bozzer
    62,500
    $0.26
    April 25, 2014
    April 24, 2017Ronnie Bozzer
    132,813
    $0.29
    August 18, 2014
    August 17, 2017David Matheson
    750,000
    $0.20
    January 31, 2014
    January 30, 2019David Matheson
    600,000
    $0.26
    April 9, 2014
    April 8, 2017David Matheson
    226,562
    $0.26
    April 25, 2014
    April 24, 2017David Matheson
    533,008
    $0.29
    August 18, 2014
    August 17, 2017Neyeska Mut
    450,000
    $0.20
    January 31, 2014
    January 30, 2019Neyeska Mut
    1,275,000
    $0.26
    April 9, 2014
    April 8, 2017Neyeska Mut
    70,312
    $0.26
    April 25, 2014
    April 24, 2017Phillip Bretzloff
    50,000
    $0.20
    January 31, 2014
    January 30, 2019Phillip Bretzloff
    675,000
    $0.26
    April 9, 2014
    April 8, 2017Phillip Bretzloff
    7,812
    $0.26
    April 25, 2014
  April 24, 2017


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.

For the most recently completed fiscal year, each
non-management director of the Company received total compensation for services
provided to the Company in his capacity as director as follows:

Name
    Fees earned$Craig Sturrock
    8,500Dr. A. Gorrell
    7,000Richard Kennedy
    8,000Ronnie Bozzer
    8,500


53

---

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, 2014. 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, 2014.

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:
| |    |                                                                        
| |    | i)                                                                     
| |    |                                                                        
| |    | ii)                                                                    

| |    | 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;
| | - | ---------------------------------------

54

---

| |  | 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
2014 to provide pension, retirement or similar benefits for Directors or Senior
Management.

C.           
 Board Practices

The Companys Governance Committee has establish the following
committees to ensure the Company maintains the highest possible governance
standards in the conduct of its business:

|1. | Governance and Nominating Committee;
|-- | ------------------------------------
|2. | Compensation Committee;             
|3. | Audit Committee, and                
|4. | Reserves Committee.                 

Each of the primary functions of these committees is located on
the Companys website at www.dejour.com as
follows:

Governance and Nominating Committee

The Governance and Nominating Committee is comprised of three
Directors, Ronnie Bozzer (Chairman), Richard Kennedy, and Craig Sturrock.

|(a) | Responsibilities for the Governance and Nominating
      Committee can be found on the Companys website at www. dejour.com under Investors/Corporate
      Governance/Committees and Responsibilities/Governance and Nominating
      Committee.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                                                                      
|(b) | The Companys Charter for the Governance and Nominating
      Committee can be found on the Companys website at www. dejour.com under Investors/Corporate
      Governance/Governance and Nominating Committee
Charter.                         

Compensation Committee

The Companys Compensation Committee is comprised of three
Directors, Richard Kennedy (Chairman), A. Ross Gorrell, and Craig Sturrock.

|(a) | Responsibilities for the Compensation Committee can be
      found on the Companys website at www.dejour.com under Investors/Corporate Governance/Committees and
      Responsibilities/Compensation Committee.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                                     
|(b) | The Companys Charter for the Compensation Committee
      can be found on the Companys website at www.dejour.com under Investors/Corporate
      Governance/Compensation Committee Charter.                   

55

---

Audit Committee

The Companys Audit Committee is comprised of three Directors,
Craig Sturrock (Chairman), Ronnie Bozzer, and James Dai.

|(a) | Responsibilities for the Audit Committee can be found
      on the Companys website at www.dejour.com under Investors/Corporate Governance/Committees and
      Responsibilities/Audit Committee.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                       
|(b) | The Companys Charter for the Audit Committee can be
      found on the Companys website at www.dejour.com under Investors/Corporate Governance/Audit Committee
      Charter.                   

Reserves Committee

The Company has a Reserves Committee comprised of three
directors, A. Ross Gorrell (Chairman), Ronnie Bozzer, and James Dai.

|(a) | Responsibilities for the Reserves Committee can be
      found on the Companys website at www.dejour.com under Investors/Corporate Governance/Committees and
      Responsibilities/Reserves Committee.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                             
|(b) | The Companys Charter for the Reserves Committee can be
      found on the Companys website at www.dejour.com under Investors/Corporate Governance/Reserves Committee
      Charter.                   

Differences between Canadian and NYSE Governance
Standards

Dejours corporate governance practices satisfy all the
existing guidelines for effective corporate governance established by Canadian
National Instrument 58-1-1 and National Policy 58-201 (collectively CSA Rules).
The NYSE corporate governance listing standards applicable to Dejours corporate
governance policies satisfy all the existing guidelines for effective corporate
governance established by the CSA Rules. The rules of the New York Stock
Exchange (the NYSE), as set for the in the NYSE Listed Company Manual (the
NYSE Manual), permit listed companies that are foreign private issuers, as
defined under the U.S. Securities Exchange Act of 1934, as amended (The
Exchange Act), including Dejour, to follow home country practice in lieu of
certain NYSE corporate governance provisions.

The significant differences between Dejours corporate
governance practices and those followed by NYSE-listed U.S. companies pursuant
to the NYSE Manual can be found on the Companys website at www.dejour.com under Investors/Corporate
Governance/Dejour Energy Inc. Differences between Canadian and NYSE Governance
Standards.

D.             Employees

The Company had the equivalent of approximately 12 full-time
employees and consultants during 2014 (Canada: 8 and United States: 4).

E.             Share
Ownership

Directors and Officer Beneficial Ownership

The following table discloses as of April 21, 2015, 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.

56

---

Shareholdings of Directors and Senior Management as of April
21, 2015

Title ofClass
    Name of Beneficial Owner
    Note
    Amount and Natureof Beneficial
     Ownership
    Percent of ClassCommon
    Robert L. Hodgkinson
    (1)
    13,500,000
    7.40%Common
    Craig Sturrock
    (2)
    1,649,000
    0.90%Common
    Dr. A. Gorrell
    (3)
    600,000
    0.33%Common
    Richard Kennedy
    (4)
    919,900
    0.50%Common
    Ronnie Bozzer
    (5)
    1,200,000
    0.66%Common
    James Dai
    (6)
    500,000
    0.27%Common
    David Matheson
    (7)
    2,500,000
    1.37%Total Directors/Management
    
    20,868,900
    11.43%


|(1) | Of these shares, 10,000,000 are represented by common
      shares and 1,779,468 are represented by vested stock options. 3,500,000 of
      these shares are owned by 7804 Yukon Inc. (1,500,000 shares) and
      Hodgkinson Equities Corp. (2,000,000 shares), private companies owned by
      Robert Hodgkinson. A further 1,720,532 stock options have been granted but
      not yet vested.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | Of these shares, 650,000 are represented by common shares
      and 498,014 are represented by vested stock options. A further 500,986
      stock options have been granted but not yet vested.                                                                                                                                                                                                   
|(3) | Of these shares, 50,000 are represented by common shares
      and 318,237 are represented by vested stock options. A further 231,763
      stock options have been granted but not yet vested.                                                                                                                                                                                                    
|(4) | Of these shares, 294,900 are represented by common shares
      and 353,761 are represented by vested stock options. A further 271,239
      stock options have been granted but not yet vested.                                                                                                                                                                                                   
|(5) | Of these shares, 450,000 are represented by common shares
      and 435,742 are represented by vested stock options. A further 314,258
      stock options have been granted but not yet vested.                                                                                                                                                                                                   
|(6) | Of these shares, 500,000 are represented by vested stock
      options.                                                                                                                                                                                                                                                                                                                            
|(7) | Of these shares, 1,472,339 are represented by vested
      stock options. A further 1,027,661 stock options have been granted but not
      yet vested.                                                                                                                                                                                                                                            

All percentages based on 182,402,139 shares outstanding as of
April 21, 2015.

57

---

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 21, 2015:

58

---

Stock Options Outstanding as of April 21, 2015

Name
    Number of Options
    Number of
    Exercise Price
    Grant Date
    Expiration DateHeld
    Options
    per OptionVestedRobert Hodgkinson
    337,500
    168,750
    $0.20
    1/31/2014
    1/30/20192,034,375
    871,875
    $0.26
    4/9/2014
    4/8/201761,523
    26,367
    $0.26
    4/25/2014
    4/24/2017566,602
    212,476
    $0.29
    8/18/2014
    8/17/2017500,000
    500,000
    $0.16
    4/2/2015
    4/1/2017Craig Sturrock
    75,000
    37,500
    $0.20
    1/31/2014
    1/30/2019656,250
    281,250
    $0.26
    4/9/2014
    4/8/201713,672
    5,860
    $0.26
    4/25/2014
    4/24/2017129,078
    48,404
    $0.29
    8/18/2014
    8/17/2017125,000
    125,000
    $0.16
    4/2/2015
    4/1/2017Dr. A. Gorrell
    50,000
    50,000
    $0.20
    12/18/2012
    12/17/201537,500
    18,750
    $0.20
    1/31/2014
    1/30/2019252,929
    108,398
    $0.26
    4/25/2014
    4/24/201750,000
    18,750
    $0.25
    7/3/2014
    7/2/201759,571
    22,339
    $0.29
    8/18/2014
    8/17/2017100,000
    100,000
    $0.16
    4/2/2015
    4/1/2017Richard Kennedy
    50,000
    50,000
    $0.20
    12/18/2012
    12/17/201575,000
    37,500
    $0.20
    1/31/2014
    1/30/2019262,500
    112,500
    $0.26
    4/9/2014
    4/8/201741,016
    17,579
    $0.26
    4/25/2014
    4/24/201796,484
    36,182
    $0.29
    8/18/2014
    8/17/2017100,000
    100,000
    $0.16
    4/2/2015
    4/1/2017Ronnie Bozzer
    300,000
    150,000
    $0.20
    1/31/2014
    1/30/201987,500
    37,500
    $0.26
    4/9/2014
    4/8/201754,687
    23,437
    $0.26
    4/25/2014
    4/24/2017132,813
    49,805
    $0.29
    8/18/2014
    8/17/2017175,000
    175,000
    $0.16
    4/2/2015
    4/1/2017James Dai
    500,000
    500,000
    $0.16
    4/2/2015
    4/1/2017David Matheson
    125,000
    125,000
    $0.20
    2/12/2013
    2/11/201656,250
    56,250
    $0.18
    4/4/2013
    4/3/2016562,500
    281,250
    $0.20
    1/31/2014
    1/30/2019525,000
    225,000
    $0.26
    4/9/2014
    4/8/2017198,242
    84,961
    $0.26
    4/25/2014
    4/24/2017533,008
    199,878
    $0.29
    8/18/2014
    8/17/2017500,000
    500,000
    $0.16
    4/2/2015
    4/1/2017Total Officers/Directors
    9,424,000
    5,357,561


59

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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 21, 2015 persons and/or companies holding 5% or more beneficial interest
in the Companys outstanding common stock.

5% or Greater Shareholders as of April 21, 2015

Title of Class
    Name of Owner
    Amount and Nature ofBeneficial Ownership
    Percent of ClassCommon
    Robert L. Hodgkinson (1)
    13,500,000
    7.40%


|(1) | Of these shares, 10,000,000 are represented by common
      shares and 1,779,468 are represented by vested stock options. 3,500,000 of
      these shares are owned by 7804 Yukon Inc. (1,500,000 shares) and
      Hodgkinson Equities Corp. (2,000,000 shares), private companies owned by
      Robert Hodgkinson. A further 1,720,532 stock options have been granted but
      not yet vested.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|All percentages
  based on 182,402,139 shares outstanding as of April 21, 2015.
|-------------------------------------------------------------------------------

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 21, 2015, there were approximately 8,086 registered
holders of the Companys shares in the United States, with combined holdings of
134,195,494 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, 2014 and 2013, the Company
entered into the following transactions with related parties:

60

---

|(a) | Compensation awarded to key management included a total
      of salaries and consulting fees of $1,092,000 (2013 - $1,173,000) and
      non-cash stock-based compensation of $823,000 (2013 - $302,000). Key
      management includes the Companys officers and directors. The salaries and
      consulting fees are included in general and administrative expenses.
      Included in accounts payable and accrued liabilities at December 31, 2014
      is $200,000 (December 31, 2013 - $Nil) owing to the two officers of the
      Company. The repayment is subject to the availability of cash after all
      other key obligations of the Company are met.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|(b) | Included in interest and other income is $15,000 (2013 -
      $21,200) 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. Effective July 3, 2014, HEC ceased to be the working interest
      partner in the Woodrush property and sold its 5% working interest to the
      Company for 2,000,000 common shares.                                                                                                                                                                                                                                                                                                                               

C.            
Interests of Experts and Counsel

Not Applicable.

61

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ITEM 8. FINANCIAL INFORMATION.

A.             Consolidated
Statements and Other Financial Information

Financial Statements

|Description                                                                                  | Page      
|-------------------------------------------------------------------------------------------- | ----------
|                                                                                             |           
|Consolidated Financial Statements for the
      Years Ended December 31, 2014, 2013 and 2012 | F-1 - F-38

Supplementary Oil and Gas Reserve Estimation and Disclosures
(Unaudited) for the years ending December 31, 2014 and 2013

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.

62

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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  
|2014                          | $0.36 | $0.13
|2013                          | $0.25 | $0.10
|2012                          | $0.59 | $0.12
|2011                          | $0.61 | $0.24
|2010                          | $0.48 | $0.29
|                              |       |      
|NYSE Amex (US$)               |       |      
|                              | High  | Low  
|2014                          | $0.33 | $0.11
|2013                          | $0.25 | $0.09
|2012                          | $0.57 | $0.12
|2011                          | $0.61 | $0.21
|2010                          | $0.50 | $0.26

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  
|2015                          |       |      
|Q1                            | $0.22 | $0.15
|2014                          |       |      
|Q1                            | $0.32 | $0.13
|Q2                            | $0.34 | $0.19
|Q3                            | $0.36 | $0.23
|Q4                            | $0.31 | $0.19
|2013                          |       |      
|Q4                            | $0.20 | $0.10
|Q3                            | $0.23 | $0.18
|Q2                            | $0.23 | $0.16
|Q1                            | $0.25 | $0.17

63

---

|NYSE Amex (US$) |       |      
|--------------- | ----- | -----
|                | High  | Low  
|2015            |       |      
|Q1              | $0.19 | $0.12
|2014            |       |      
|Q1              | $0.29 | $0.11
|Q2              | $0.31 | $0.17
|Q3              | $0.33 | $0.22
|Q4              | $0.28 | $0.16
|2013            |       |      
|Q4              | $0.19 | $0.09
|Q3              | $0.24 | $0.18
|Q2              | $0.24 | $0.17
|Q1              | $0.25 | $0.16

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,
      2015             | $0.20 | $0.16
|February, 2015                | $0.22 | $0.16
|January,
      2015           | $0.22 | $0.15
|December, 2014                | $0.24 | $0.19
|November,
      2014          | $0.31 | $0.21
|October, 2014                 | $0.30 | $0.20
|                              |       |      
|NYSE Amex (US$)               |       |      
|                              | High  | Low  
|March,
      2015             | $0.17 | $0.12
|February,
      2015          | $0.19 | $0.13
|January,
      2015           | $0.19 | $0.13
|December,
      2014          | $0.20 | $0.16
|November,
      2014          | $0.28 | $0.19
|October,
      2014           | $0.28 | $0.17

On April 21, 2015, the closing price of our common shares on
the TSX was Cdn $0.17 per common share and on the NYSE was US $0.14 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.

64

---

E.             Dilution

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.

65

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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

66

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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:

|(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)                                                                                                                                                                                                                                                                                                                      
|    |                                                                                                                                                                                                                                                                                                                          
|    | (ii)                                                                                                                                                                                                                                                                                                                     

|(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 21, 2015, 182,402,139 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

67

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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, except a meeting of the
holders of shares of another class, as such, and except 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.

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.

68

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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.

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.

69

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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) to fund the
drilling of up to three wells and the completion of up to four wells in the
State of Colorado. The Drilling Fund contributed US$6.5 million cash to earn
working interests in production from the wellbores ranging from 55.56% to 77.78%
before payout and 44.44% to 58.33% after payout. This amount was subsequently
increased by US$500,000 to US$7,000,000 with the Companys consent.

The December 31, 2012 financial contract states the Drilling
Fund has the right to require Dejour USA to purchase its working interests in
the wellbores for cash in September 2016, 36-months after the final well in the
4-well program is placed on production. The repurchase price is based on a
predetermined formula which ensures the Drilling Fund earns a minimum return,
compounded annually and applied on a monthly basis, on 75% of its original
US$7,000,000 investment over the 36-month period. Accordingly, the Company considered
the transaction to be a financial contract as the risks and rewards of ownership
were not substantially transferred to the Drilling Fund and, on December 31,
2012, the Company recorded the transaction in its accounts by increasing
property and equipment and financial contract liability by US$6,500,000 on its
balance sheet. This amount was subsequently increased to US$7,000,000.

70

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On June 30, 2014, the financial contract was amended and the
Drilling Fund agreed to retain its working interest in the wells as at September
30, 2016, should it exercise its right to require Dejour USA to pay the minimum
return provided for in the December 31, 2012 contract. The Drilling Fund further
agreed to deduct the residual reserve value of its working interest in the 4
wellbores at September 30, 2016 in determining the net liability owed by Dejour
USA to the Drilling Fund at September 30, 2016. The parties also agreed to have
a third party engineering firm calculate the residual value of the reserves in
according with industry-accepted valuation standards.

Finally, the parties agreed to limit the cash consideration to
be paid by Dejour USA, should it be required to pay the minimum return provided
for in the December 31, 2012 contract to US$3,000,000. Additional consideration,
if any, may be paid by Dejour USA by an assignment of a working interest in
certain proven assets at a jointly owned oil and gas property in Colorado
applying an industry-standard valuation approach.

The June 30, 2014 amendment transferred the risks of ownership
of the 4 wellbores back to the Drilling Fund and the financial contract
liability was adjusted to reflect the present value of the amount owing to the
Drilling Fund under the financial contract at September 30, 2016 ($5,519,000),
net of the present value of the residual reserves ($2,780,000), or $2,739,000 at
December 31, 2014.

Bank Credit Facility

On June 5, 2014 and amended on June 27, 2014, DEAL renewed its
Credit Facility with its Bank for a maximum amount of $2.9 million. Effective
July 1, 2014, the Credit Facility reduces by $100,000 per month. Interest on the
loan is Prime + 3% payable monthly and the amount outstanding is payable on
demand any time. Collateral for the Credit Facility is provided by a $10.0
million first floating charge over all the assets of DEAL, a general assignment
of DEALs book debts and a $10.0 million debenture with a first floating charge
over all the assets of the Company. Additionally, an amount of US$385,000 was
deposited in the Companys US$ account with the Bank at June 30, 2014 upon the
Banks request to be applied to DEALs general operations.

On July 29, 2014, the Company renewed the Credit Facility with
its Bank for a maximum of $2.8 million, reducing $100,000 per month through
November 1, 2014. As part of the renewal, the Company can utilize the US$385,000
on deposit with its Bank at June 30, 2014 on the operations and capital programs
of DEAL at the Companys discretion. Further, on November 24, 2014 and amended
on March 16, 2015, the Company renewed the Credit Facility with its Bank for a
maximum of $2.2 million. Monthly principal payments of $100,000 are due and
payable on March 16, 2015 and commencing on the 28th of each month
thereafter. The Bank is currently conducting its annual review of the Companys
Canadian oil and gas reserves for loan purposes.

Under the terms of the Credit Facility, 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 Facility) 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, 2014, DEAL was in default of its working capital ratio covenant
with a 0.56 to 1 ratio.

Acquisition of additional 24% working interest in
Drake/Woodrush, northeastern British Columbia, Canada

In July 2014, the Company closed the acquisition of an
additional 24% working interest in the Drake/Woodrush oilfield in Northeastern
B.C. to increase its working interest to 99%. As consideration for the purchase,
the Company issued 9,600,000 common shares at a price of $0.202 per share for
$1,939,000. A company controlled by the CEO of the Company (HEC) sold its 5%
working interest in the Drake/Woodrush property for 2,000,000 common shares
included in the above.

HEC loan to the Company

71

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On March 12, 2015, the Company issued a promissory note for up
to $2,000,000 to HEC, a private company controlled by the CEO of the Company.
The promissory note is secured by all assets of Dejour USA, bears interest at
the Canadian prime rate plus 5% per annum. The principal and interest were
repayable by the earlier of (i) within 10 business days of receipt of written
demand from HEC for the repayment and (ii) June 10, 2015 or such later date to
which the term of the promissory note may be extended. Upon an event of default,
all the indebtedness under the promissory note become due and payable and the
interest rate is immediately increased to the Canadian prime rate plus 8.5% per
annum. On March 12, 2015, $1,250,000 had been advanced to the Company.

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.

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                

72

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|(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.

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.

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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.

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.

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

Scope of this Summary

Authorities

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

U.S. Holders

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

- an individual who is a citizen or resident of the U.S.;
- a corporation (or other entity taxable as a corporation for U.S. federal
  income tax purposes) organized under the laws of the U.S., any state thereof
  or the District of Columbia;
- an estate whose income is subject to U.S. federal income taxation
  regardless of its source; or
- a trust that (a) is subject to the primary supervision of a court within
  the U.S. and the control of one or more U.S. persons for all substantial
  decisions or (b) has a valid election in effect under applicable Treasury
  regulations to be treated as a U.S. person.

Non-U.S. Holders

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

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

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

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

Tax Consequences Not Addressed

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

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

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

Distributions on Common Shares

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

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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

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.

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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.

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.

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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.

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

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Not Applicable.

G.             Statements
by Experts

Not Applicable.

H.             Documents
on Display

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

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

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

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

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

I.             Subsidiary
Information

Not applicable.

80

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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, 2014 and 2013, no accounts receivable has been deemed
uncollectible or written off during the year.

As at December 31, 2014, the Companys receivables consist of
$57,000 (2013 - $4,000) from joint interest partners, $409,000 (2013 - $760,000)
from oil and natural gas marketers and $139,000 (2013 - $67,000) 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, 2014, $Nil (2013 - $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. At December 31, 2014, the Conpany was in default of its working
capital ratio covenant on its credit facility.

81

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The following are the contractual maturities of financial
liabilities as at December 31, 2014:

|(CA$ thousands)                          |  | Carrying amount |  |  | 2015  | 
|---------------------------------------- |  | --------------- |  |  | ----- | 
|                                         |  | $               |  |  | $     | 
|Accounts payable and accrued liabilities |  | 3,516           |  |  | 3,516 | 
|Bank credit
      facilities             |  | 1,955           |  |  | 1,955 | 
|                                         |  | 5,471           |  |  | 5,471 | 

For the contractual maturities of financial contract liability
as at December 31, 2014, see note 12 to the 2014 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, 2014 and 2013.

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

|(CA$
      thousands)                    |  | 2014  |   |  | 2013   |  
|---------------------------------------- |  | ----- | - |  | ------ | -
|Expressed in
      foreign currencies    |  | CND$  |   |  | CND$   |  
|Cash and cash equivalents                |  | 1,128 |   |  | 376    |  
|Accounts receivable                      |  | 25    |   |  | 421    |  
|Accounts payable and accrued liabilities |  | (109  | ) |  | (1,613 | )
|Balance sheet
      exposure             |  | 1,044 |   |  | (816   | )

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

|                                 |  | 2014   |  |  | 2013   | 
|-------------------------------- |  | ------ |  |  | ------ | 
|December 31, reporting date rate |  | 1.1601 |  |  | 1.0636 | 
|YTD average USD to
      CAD     |  | 1.1048 |  |  | 1.0301 | 

The Company has performed a sensitivity analysis on its foreign
currency denominated financial instruments. Based on the Companys foreign
currency exposure noted above and assuming that all other variables remain
constant, a 10% appreciation of the US dollar against the Canadian dollar would
result in the decrease of net loss of $104,000 at December 31, 2014 (2013 -
$82,000 increase 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.

82

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(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, 2014,
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, 2014 would have increased or decreased net loss by $25,000. The
Company had no interest rate swaps or financial contracts in place at or during
the year ended December 31, 2014 and 2013.

(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, 2014 would have decreased or increased net loss by $72,000. The Company had
no commodity contracts in place at December 31, 2014.

(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, 2014, the Company was in default of the
covenant for its bank credit 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, 2014.

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.

83

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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, 2014, 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, 2014. 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, 2014, the
Companys internal control over financial reporting was effective and
managements assessment did not identify material weaknesses.

84

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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, 2014 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, 2014, 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.

85

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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, 2014 and December 31, 2013. During these years, BDO Canada LLP was
our external auditors.

Year endedDecember 31, 2014
    Year endedDecember 31, 2013$
    $Audit Services (1)
    160,730
    201,762Audit Related Services (2)
    19,500
    29,700Tax Services (3)
    9,200
    8,500All Other Fees (4)
    12,959
  16,235


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 2014 and 2013, 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 2014 and 2013, the services
      provided in this category included assistance and advice in relation to
      the preparation of corporate income tax returns.                                                                                                                                                 
|    |                                                                                                                                                                                                                                                                                                                                                                                                                         
|(4) | During fiscal 2014 and 2013, 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 2014.

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

None.

86

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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, 2014.

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.

87

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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 4, 2015

Consolidated Balance Sheets at December 31, 2014 and 2013

Consolidated Statements of Comprehensive Loss for the years
ending December 31, 2014, 2013 and 2012.

Consolidated Statements of Changes in Shareholders Equity for
the years ended December 31, 2014, 2013 and 2012.

Consolidated Statements of Cash Flows for the years ended
December 31, 2014, 2013 and 2012.

Notes to the Consolidated Financial Statements

Supplementary Oil and Gas Reserve Estimation and Disclosures
(Unaudited) for the years ending December 31, 2014 and 2013

88

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ITEM 19. EXHIBITS

Financial Statements

|Description                                                                                   | Page      
|--------------------------------------------------------------------------------------------- | ----------
|                                                                                              |           
|Consolidated Financial Statements for the
      Years Ended December 31, 2014, 2013 and 2012. | F-1 - F-38

Supplementary Oil and Gas Reserve Estimation and Disclosures
(Unaudited) for the years ending December 31, 2014 and 2013

|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)                                           
|        |                                                                                                                                                   
|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)                                       

89

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|EXHIBIT |                                                                                                                                                                                            
|------- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|NUMBER  | DESCRIPTION                                                                                                                                                                                
|        |                                                                                                                                                                                            
|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 (7)                                                                                         
|        |                                                                                                                                                                                            
|4.24    | Commitment Letter between the Registrant and Invico
  Performance Yield Fund Limited Partnership dated June 11, 2013 (7)                                                                   
|        |                                                                                                                                                                                            
|4.25    | Amendment to Financial Contract with Bakken Drilling Fund
      III, LP dated September 10, 2013 (7)                                                                                       
|        |                                                                                                                                                                                            
|4.26    | Credit Facility Renewal Letter between DEAL and Canadian
      Western Bank dated December 16, 2013 (7)                                                                                    
|        |                                                                                                                                                                                            
|4.27    | Credit Facility Renewal Letter between DEAL and Canadian
      Western Bank dated February 18, 2014 (7)                                                                                    
|        |                                                                                                                                                                                            
|4.28    | Amendment to Financial Contract with Bakken Drilling Fund
      III, LP dated June 16, 2014 (7)                                                                                            
|        |                                                                                                                                                                                            
|4.29    | Credit Facility Renewal Letter between DEAL and Canadian
      Western Bank dated June 5, 2014 (7)                                                                                         
|        |                                                                                                                                                                                            
|4.30    | Credit Facility Renewal Letter between DEAL and Canadian
      Western Bank dated June 27, 2014 (7)                                                                                        
|        |                                                                                                                                                                                            
|4.31    | Purchase and Sale Agreement  Drake/Woodrush area,
      British Columbia dated July 3, 2014 (7)                                                                                           
|        |                                                                                                                                                                                            
|4.32    | Credit Facility Renewal Letter between DEAL and Canadian
      Western Bank dated July 29, 2014 (7)                                                                                        
|        |                                                                                                                                                                                            
|4.33    | Credit Facility Renewal Letter between DEAL and Canadian
      Western Bank dated November 24, 2014 (7)                                                                                    
|        |                                                                                                                                                                                            
|4.34    | Loan Agreement between the Company and HEC dated March
      12, 2015 (7)                                                                                                                  
|        |                                                                                                                                                                                            
|4.35    | Credit Facility Renewal Letter between DEAL and Canadian
      Western Bank dated March 16, 2015 (7)                                                                                       
|        |                                                                                                                                                                                            
|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 Gustavson Associates*                                                                                                                                                  
|        |                                                                                                                                                                                            
|99.1    | Third Party Report on Reserves Prepared by GLJ Petroleum
      Consultants, Effective December 31, 2014*                                                                                   
|        |                                                                                                                                                                                            
|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, 2015*

|(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                                                                                                                               

90

---

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
      21, 2015 |  | /s/
      Robert L. Hodgkinson
|       |                      |  | Robert L. Hodgkinson          
|       |                      |  | Chairman & CEO                

91

---



CONSOLIDATED FINANCIAL STATEMENTS (AUDITED)

December 31, 2014

F-1

---



F-2

---



F-3

---

DEJOUR ENERGY INC.CONSOLIDATED BALANCE SHEETS(Expressed in Canadian Dollars)

|                                                      |  |       |  |  | December 31, |   |  | December 31, |  
|----------------------------------------------------- |  | ----- |  |  | ------------ | - |  | ------------ | -
|(CA$ thousands)                                       |  | Notes |  |  | 2014         |   |  | 2013         |  
|                                                      |  |       |  |  | $            |   |  | $            |  
|ASSETS                                                |  |       |  |  |              |   |  |              |  
|Current                                               |  |       |  |  |              |   |  |              |  
|Cash and cash equivalents                             |  |       |  |  | 1,215        |   |  | 505          |  
|Accounts
      receivable                             |  |       |  |  | 605          |   |  | 831          |  
|Prepaids and deposits                                 |  |       |  |  | 141          |   |  | 49           |  
|Current Assets                                        |  |       |  |  | 1,961        |   |  | 1,385        |  
|Non-current                                           |  |       |  |  |              |   |  |              |  
|Deposits                                              |  |       |  |  | 297          |   |  | 447          |  
|Exploration and evaluation assets                     |  | 5     |  |  | 3,107        |   |  | 3,281        |  
|Property and equipment                                |  | 6     |  |  | 17,909       |   |  | 20,386       |  
|Total Assets                                          |  |       |  |  | 23,274       |   |  | 25,499       |  
|                                                      |  |       |  |  |              |   |  |              |  
|LIABILITIES                                           |  |       |  |  |              |   |  |              |  
|Current                                               |  |       |  |  |              |   |  |              |  
|Bank credit facility                                  |  | 8     |  |  | 1,955        |   |  | 2,900        |  
|Loan
      facility                                   |  | 10    |  |  | -            |   |  | 2,911        |  
|Accounts payable and accrued liabilities              |  |       |  |  | 3,515        |   |  | 2,623        |  
|Warrant
      liability                               |  | 9     |  |  | 755          |   |  | 324          |  
|Derivative liability                                  |  | 10    |  |  | 216          |   |  | 287          |  
|Current portion of financial
      contract liability |  |       |  |  | -            |   |  | 1,248        |  
|Current
      Liabilities                             |  |       |  |  | 6,441        |   |  | 10,293       |  
|Non-current                                           |  |       |  |  |              |   |  |              |  
|Decommissioning liability                             |  | 11    |  |  | 3,709        |   |  | 1,212        |  
|Other liabilities                                     |  |       |  |  | -            |   |  | 22           |  
|Financial contract liability                          |  | 12    |  |  | 2,739        |   |  | 4,873        |  
|Total Liabilities                                     |  |       |  |  | 12,889       |   |  | 16,400       |  
|SHAREHOLDERS'
      EQUITY                            |  |       |  |  |              |   |  |              |  
|Share
      capital                                   |  | 13    |  |  | 97,132       |   |  | 90,274       |  
|Contributed surplus                                   |  |       |  |  | 9,674        |   |  | 9,150        |  
|Deficit                                               |  |       |  |  | (98,042      | ) |  | (90,839      | )
|Accumulated other comprehensive
      income (loss)   |  |       |  |  | 1,621        |   |  | 514          |  
|Total Shareholders' Equity                            |  |       |  |  | 10,385       |   |  | 9,099        |  
|Total Liabilities and Shareholders' Equity            |  |       |  |  | 23,274       |   |  | 25,499       |  

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 LOSSExpressed in
Canadian Dollars)

Year ended December 31(CA$ thousands, except per share amounts)
    
    Notes
    
    
    2014
    
    
    2013
    
    
    2012$
    
    
    $
    
    
    $REVENUESGross revenues
    
    
    
    
    9,049
    
    
    9,317
    
    
    6,882Royalties
    
    
    
    
    (1,488
    )
    
    (1,811
    )
    
    (1,116
    )Total Revenues, net of royalties
    
    20
    
    
    7,561
    
    
    7,506
    
    
    5,766EXPENSESOperating and
      transportation
    
    
    
    
    4,099
    
    
    3,398
    
    
    3,793General and administrative
    
    
    
    
    3,493
    
    
    3,384
    
    
    3,525Financing expenses
    
    
    
    
    1,168
    
    
    1,182
    
    
    587Stock based compensation
    
    
    
    
    1,270
    
    
    348
    
    
    866Foreign exchange
      loss
    
    
    
    
    286
    
    
    505
    
    
    190Loss on settlement of loan facility
    
    10
    
    
    388
    
    
    -
    
    
    -(Gain) loss on
      disposal of E&E assets
    
    5
    
    
    318
    
    
    185
    
    
    (299
    )(Gain) loss on disposal of property and equipment
    
    6
    
    
    (1,909
    )
    
    107
    
    
    -Amortization,
      depletion and impairment losses
    
    7
    
    
    6,515
    
    
    3,630
    
    
    10,676Change in fair value of warrant liability
    
    9
    
    
    78
    
    
    (1,101
    )
    
    (1,842
    )Change in fair
      value of derivative liability
    
    10
    
    
    -
    
    
    (264
    )
    
    -Gain on financial contract liability
    
    12
    
    
    (918
    )
    
    (1,268
    )
    
    -Total
      Expenses
    
    
    
    
    14,788
    
    
    10,106
    
    
    17,496Loss before other items
    
    
    
    
    (7,227
    )
    
    (2,600
    )
    
    (11,730
    )Financial
      instrument loss
    
    
    
    
    -
    
    
    -
    
    
    (55
    )Other income
    
    
    
    
    24
    
    
    23
    
    
    33Loss for the year
    
    
    
    
    (7,203
    )
    
    (2,577
    )
    
    (11,752
    )Other Comprehensive IncomeItems that may be subsequently reclassified to profit
      or loss:    Foreign currency translation
      adjustment
    
    
    
    
    1,107
    
    
    1,082
    
    
    (175
    )Comprehensive loss
    
    
    
    
    (6,096
    )
    
    (1,495
    )
    
    (11,927
    )Loss per common share - basic and diluted
    
    15
    
    
    (0.04
    )
    
    (0.02
    )
    
    (0.08
)


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, 2014
    
    
    
    
    148,916,374
    
    
    90,274
    
    
    9,150
    
    
    (90,839
    )
    
    514
    
    
    9,099Shares issued via private
      placements, net of issuance costs
    
    13
    
    
    13,000,000
    
    
    1,920
    
    
    
    
    
    
    
    
    
    
    
    1,920Shares
      issued via acquisition of property, net of issuance costs
    
    13
    
    
    9,600,000
    
    
    1,890
    
    
    
    
    
    
    
    
    
    
    
    1,890Issue of shares on
      exercise of options and warrants
    
    13
    
    
    10,885,765
    
    
    2,232
    
    
    
    
    
    
    
    
    
    
    
    2,232Derivative liability reallocated on exercise of warrants
    
    13
    
    
    
    
    
    70
    
    
    
    
    
    
    
    
    
    
    
    70Contributed surplus
      reallocated on exercise of options
    
    13
    
    
    
    
    
    746
    
    
    (746
    )
    
    
    
    
    
    
    
    -Stock-based compensation
    
    
    
    
    
    
    
    
    
    
    1,270
    
    
    
    
    
    
    
    
    1,270Loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    (7,203
    )
    
    
    
    
    (7,203
    )Foreign currency translation adjustment
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,107
    
    
    1,107Balance as at December 31, 2014
    
    
    
    
    182,402,139
    
    
    97,132
    
    
    9,674
    
    
    (98,042
    )
    
    1,621
    
    
    10,385Balance as at January 1, 2013
    
    
    
    
    148,916,374
    
    
    90,274
    
    
    8,802
    
    
    (88,262
    )
    
    (568
    )
    
    10,246Stock-based compensation
    
    
    
    
    
    
    
    
    
    
    348
    
    
    
    
    
    
    
    
    348Net loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,577
    )
    
    
    
    
    (2,577
    )Foreign currency translation adjustment
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,082
    
    
    1,082Balance as at December 31, 2013
    
    
    
    
    148,916,374
    
    
    90,274
    
    
    9,150
    
    
    (90,839
    )
    
    514
    
    
    9,099Balance as at January 1, 2012
    
    
    
    
    126,892,386
    
    
    85,076
    
    
    8,134
    
    
    (76,510
    )
    
    (393
    )
    
    16,307Shares
      issued via private placements, net of issuance costs
    
    13
    
    
    18,130,305
    
    
    3,248
    
    
    
    
    
    
    
    
    
    
    
    3,248Issue of shares on
      exercise of warrants and options
    
    13
    
    
    3,893,683
    
    
    1,466
    
    
    
    
    
    
    
    
    
    
    
    1,466Warrant
      liability reallocated on exercise of warrants
    
    13
    
    
    
    
    
    286
    
    
    
    
    
    
    
    
    
    
    
    286Contributed surplus
      reallocated on exercise of options
    
    13
    
    
    
    
    
    198
    
    
    (198
    )
    
    
    
    
    
    
    
    -Stock-based compensation
    
    
    
    
    
    
    
    
    
    
    866
    
    
    
    
    
    
    
    
    866Net 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


* 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
    
    
    2014
    
    
    2013
    
    
    2012$
    
    
    $
    
    
    $CASH FLOWS FROM (USED IN) OPERATING
      ACTIVITIESNet loss for the year
    
    
    
    
    (7,203
    )
    
    (2,577
    )
    
    (11,752
    )Adjustment for
      items not affecting cash:Amortization, depletion and impairment losses
    
    
    
    
    6,515
    
    
    3,630
    
    
    10,676Stock based compensation
    
    
    
    
    1,270
    
    
    348
    
    
    866Non-cash financing expenses
    
    
    
    
    1,010
    
    
    1,012
    
    
    53Non-cash foreign exchange on financial contract liability
    
    
    
    
    371
    
    
    462
    
    
    -Loss on settlement of decommissioning liability
    
    
    
    
    -
    
    
    -
    
    
    92Loss
      on settlement of loan facility
    
    
    
    
    388(Gain) loss on disposal of E&E assets
    
    
    
    
    318
    
    
    185
    
    
    (299
    )(Gain) loss on disposal of property and equipment
    
    
    
    
    (1,909
    )
    
    107
    
    
    -Change in fair value of derivative liability
    
    
    
    
    -
    
    
    (264
    )
    
    -Change in fair value of warrant liability
    
    
    
    
    78
    
    
    (1,101
    )
    
    (1,842
    )Amortization of deferred leasehold inducement
    
    
    
    
    (20
    )
    
    (12
    )
    
    (12
    )Gain
      on financial contract liability
    
    
    
    
    (918
    )
    
    (1,268
    )
    
    -Changes in operating working capital
    
    15
    
    
    (481
    )
    
    440
    
    
    (1,009
    )Total Cash Flows from
      (used in) Operating Activities
    
    
    
    
    (581
    )
    
    962
    
    
    (3,227
    )CASH FLOWS FROM
      (USED IN) INVESTING ACTIVITIESDeposits
    
    
    
    
    150
    
    
    (55
    )
    
    12E&E expenditures
    
    
    
    
    (120
    )
    
    (249
    )
    
    (448
    )Additions to
      property and equipment
    
    
    
    
    (3,714
    )
    
    (1,792
    )
    
    (4,037
    )Proceeds from sale of E&E assets
    
    5
    
    
    412
    
    
    284
    
    
    353Proceeds from sale
      of property and equipment
    
    6
    
    
    4,136
    
    
    477
    
    
    2Changes in investing working capital
    
    15
    
    
    1,507
    
    
    (76
    )
    
    (583
    )Total Cash Flows from
      (used in) Investing Activities
    
    
    
    
    2,371
    
    
    (1,411
    )
    
    (4,701
    )CASH FLOWS FROM
      (USED IN) FINANCING ACTIVITIESAdvance
      (repayment) of bank credit facility
    
    
    
    
    (945
    )
    
    (3,057
    )
    
    410Advance (repayment) of loan facility
    
    10
    
    
    (3,820
    )
    
    2,971
    
    
    -Advance
      (repayment) of financial contract liability
    
    
    
    
    (772
    )
    
    (468
    )
    
    -Shares issued on exercise of warrants and options
    
    13
    
    
    2,232
    
    
    -
    
    
    1,466Shares issued for
      cash, net of share issue costs
    
    13
    
    
    2,225
    
    
    -
    
    
    4,556Changes in financing working capital
    
    15
    
    
    -
    
    
    -
    
    
    516Total Cash Flows from
      (used in) Financing Activities
    
    
    
    
    (1,080
    )
    
    (554
    )
    
    6,948CHANGE IN CASH AND CASH
      EQUIVALENTS
    
    
    
    
    710
    
    
    (1,003
    )
    
    (980
    )CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR
    
    
    
    
    505
    
    
    1,508
    
    
    2,488CASH AND CASH EQUIVALENTS, END OF YEAR
    
    
    
    
    1,215
    
    
    505
    
    
    1,508


Supplemental cash flow information - Note 15

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, 2014, 2013 and 2012                                              
|(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 4, 2015.

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 (IASB) and
the International Financial Reporting Interpretations Committee (IFRIC). 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 $4.5 million, which includes a
Credit Facility in DEAL of $1.9 million, and accumulated deficit of $98.0
million. Excluding the non-cash warrant liability of $0.8 million and the
non-cash derivative liability of $0.2 million, the adjusted working capital
deficiency was $3.5 million.

On November 24, 2014, DEAL renewed the Credit Facility. Under
the terms of the Credit Facility, 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 Facility) less unrealized hedging gains to (ii)
current liabilities (excluding current portion of outstanding balances under the
Facility) less unrealized hedging losses. As at December 31, 2014, DEAL was in
default of its working capital ratio covenant with a 0.56 to 1 ratio. The Bank
is currently conducting its annual review of the Company's Canadian oil and gas
reserves for loan purposes.

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.

(c)Basis of measurement

The consolidated annual financial statements have been prepared
on the historical cost basis except for certain financial liabilities are
measured at fair value, as explained in the accounting policies in note 3.

F-8

---

|DEJOUR ENERGY INC.                                                                                     
|-------------------------------------------------------------------------------------------------------
|NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS                                                         
|For the Year Ended December 31, 2014, 2013 and 2012                                                    
|(All
      tabular amounts are expressed in thousands of Canadian dollars unless
      otherwise noted)

NOTE 2  BASIS OF PRESENTATION (continued)

|(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
|--- | ----------------

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 loss as cumulative translation differences.

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 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.

F-9

---

|DEJOUR ENERGY INC.                                                                                     
|-------------------------------------------------------------------------------------------------------
|NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS                                                         
|For the Year Ended December 31, 2014, 2013 and 2012                                                    
|(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)
|--- | ----------------------------

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.

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.

F-10

---

|DEJOUR ENERGY INC.                                                                                     
|-------------------------------------------------------------------------------------------------------
|NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS                                                         
|For the Year Ended December 31, 2014, 2013 and 2012                                                    
|(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)
|--- | -------------------------------

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.

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.

F-11

---

|DEJOUR ENERGY INC.                                                                                     
|-------------------------------------------------------------------------------------------------------
|NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS                                                         
|For the Year Ended December 31, 2014, 2013 and 2012                                                    
|(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)
|--- | -------------------------------

Jointly controlled assets and operations

The Company conducts its oil and gas development and production
activities through jointly controlled operations and the accounts reflect only
its interest in such activities. A joint arrangement exists where the parties
take their share of the output of the joint arrangement would be classified as a
joint operation and accounted for by recognizing the Companys share of assets
and liabilities jointly owned and incurred, and the recognition of its share of
revenue and expenses of the joint operation. At December 31, 2014, the Companys
material joint operation in Canada is Drake/Woodrush. The principal activity is
oil and gas production and the ownership percentage is 54% to 99% (December 31,
2013  75%).

|(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.

|(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.

F-12

---

|DEJOUR ENERGY INC.                                                                                     
|-------------------------------------------------------------------------------------------------------
|NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS                                                         
|For the Year Ended December 31, 2014, 2013 and 2012                                                    
|(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 (continued)
|--- | --------------------------------

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:

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.

F-13

---

|DEJOUR ENERGY INC.                                                                                     
|-------------------------------------------------------------------------------------------------------
|NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS                                                         
|For the Year Ended December 31, 2014, 2013 and 2012                                                    
|(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)
|--- | ---------------------------------

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.

The Company has derivative financial instruments in the form of
warrants issued in US dollars, or with certain adjustment provisions, 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.

F-14

---

|DEJOUR ENERGY INC.                                                                                     
|-------------------------------------------------------------------------------------------------------
|NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS                                                         
|For the Year Ended December 31, 2014, 2013 and 2012                                                    
|(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)
|--- | ---------------------------------

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.

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.

F-15

---

|DEJOUR ENERGY INC.                                                                                     
|-------------------------------------------------------------------------------------------------------
|NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS                                                         
|For the Year Ended December 31, 2014, 2013 and 2012                                                    
|(All
      tabular amounts are expressed in thousands of Canadian dollars unless
      otherwise noted)

NOTE 3  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(continued)

|(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, 2014, 2013 and 2012                                                    
|(All
      tabular amounts are expressed in thousands of Canadian dollars unless
      otherwise noted)

NOTE 3  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(continued)

|(m) | Changes in accounting policies
|--- | ------------------------------

The Company has adopted the following new and revised
standards, along with all consequential amendments, effective January 1, 2014.
These changes are made in accordance with the applicable transitional
provisions.

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 clarifies the disclosures required when an
impairment loss has been recognized or reversed in the period. The adoption of
the standard only resulted in certain disclosures being updated on the Companys
consolidated financial statements.

In May 2013, the IASB issued IFRIC 21 "Levies," which was
developed by the IFRS Interpretations Committee ("IFRIC"). IFRIC 21 clarifies
that an entity recognizes a liability for a levy when the activity that triggers
payment, as identified by the relevant legislation, occurs. The interpretation
also clarifies that no liability should be recognized before the specified
minimum threshold to trigger that levy is reached. IFRIC 21 is required to be
adopted retrospectively for fiscal years beginning January 1, 2014, with earlier
adoption permitted. IFRIC 21 was applied by the Company on January 1, 2014 and
the adoption does not have any impact on the Companys accounting for production
and similar taxes, which do not meet the definition of an income tax in IAS 12
"Income Taxes." The adoption of the standard does not have any impact on the
Companys consolidated financial statements.

The amendments to IAS 32 "Financial Instruments: Presentation"
clarify the meaning of currently has a legally enforceable right to set-off
and the criteria for non-simultaneous settlement mechanisms of clearing houses
to qualify for offsetting. These amendments have no impact on the group.

|(n) | Future accounting pronouncements
|--- | --------------------------------

Certain pronouncements were issued by IASB or IFRIC that
are mandatory for accounting periods beginning after January 1, 2015 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:

IAS 1, Presentation of Financial Statements: In December
2014, the IASB issued amendments to IAS 1, clarifying guidance on the concepts
of materiality and aggregation of items in the financial statements, the use and
presentation of subtotals in the statement of operations and comprehensive
income or loss, and providing additional flexibility in the structure and
disclosures of the financial statements to enhance understandability. The
amendments to IAS 1 may be applied immediately, and become mandatory for annual
periods beginning on or after January 1, 2016.

IFRS 9, Financial Instruments: In July 2014, the IASB
completed the final phase of its project to replace IAS 39, the current standard
on the recognition and measurement of financial instruments. IFRS 9 is now the
new standard which sets out the recognition and measurement requirements for
financial instruments and some contracts to buy or sell non-financial items.
IFRS 9 proposes a single model of classifying and measuring financial assets and
liabilities and provides for only two classification categories: amortized cost
and fair value. Hedge accounting requirements have also been updated in the new
standard and are now more aligned with the risk management activities of an
entity. IFRS 9 is effective for annual periods beginning on or after January 1,
2018. Early adoption is permitted; however, if an entity elects to apply this
standard early, it must disclose that fact and apply all of the requirements in
this standard at the same time.

IFRS 11, Joint Arrangements: In May 2014, the IASB issued
amendments to IFRS 11 to address the accounting for acquisitions of interests in
joint operations. The amendments address how a joint operator should account for
the acquisition of an interest in a joint operation in which the activity of the
joint operation constitutes a business. IFRS 11, as amended, now requires that
such transactions be accounted for using the principles related to business
combinations accounting as outlined in IFRS 3, Business Combinations. The
amendments are to be applied prospectively and are effective for annual periods
beginning on or after January 1, 2016, with earlier application permitted.

F-17

---

|DEJOUR ENERGY INC.                                                                                     
|-------------------------------------------------------------------------------------------------------
|NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS                                                         
|For the Year Ended December 31, 2014, 2013 and 2012                                                    
|(All
      tabular amounts are expressed in thousands of Canadian dollars unless
      otherwise noted)

NOTE 3  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(continued)

|(n) | Future accounting pronouncements (continued)
|--- | --------------------------------------------

IFRS 15, Revenue from Contract with Customers. The IASB
issued the standard to replace IAS 18 which establishes principles for reporting
useful information to users of financial statements about the nature, amount,
timing and uncertainty of revenue and cash flows arising from an entitys
contracts with customers. The standard is effective for the Company for annual
periods beginning on January 1, 2017, with required retrospective application
and early adoption permitted.

IAS 16, Property, Plant and Equipment and IAS 38, Intangible
Assets:In May 2014, the IASB issued amendments to IAS 16 and IAS 38 to
clarify acceptable methods of depreciation and amortization. The amended IAS 16
eliminates the use of a revenue-based depreciation method for items of property,
plant and equipment. Similarly, amendments to IAS 38 eliminate the use of a
revenue-based amortization model for intangible assets except in certain
specific circumstances. The amendments are to be applied prospectively and are
effective for annual periods beginning on or after January 1, 2016, with earlier
application permitted.

NOTE 4 - CRITICAL ACCOUNTING ESTIMATES AND ASSUMPTIONS

The Company makes estimates and assumptions about the future
that affect the reported amounts of assets and liabilities. Estimates and
assumptions 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 results 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 assumptions 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 expenditures 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 in which the new information becomes available.

F-18

---

|DEJOUR ENERGY INC.                                                                                     
|-------------------------------------------------------------------------------------------------------
|NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS                                                         
|For the Year Ended December 31, 2014, 2013 and 2012                                                    
|(All
      tabular amounts are expressed in thousands of Canadian dollars unless
      otherwise noted)

NOTE 4 - CRITICAL ACCOUNTING ESTIMATES AND ASSUMPTIONS
(continued)

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. Effective June 30, 2014, the Companys financial contract
liability was reduced by the residual reserve value of its working interest in
the wellbores at September 30, 2016.

At December 31, 2014, the financial contract liability was
adjusted to reflect the present value of the amount outstanding at September 30,
2016, net of the present value of the residual reserves of its working interest
in the wellbores.

Impairment

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.
In determining the recoverable amount, the key assumptions the Company uses in
estimating future cash flows for recoverable amounts are anticipated future
commodity prices, expected production volumes, future operating and development
costs, and discount rate. 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, 2014, 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.

F-19

---

|DEJOUR ENERGY INC.                                                                                     
|-------------------------------------------------------------------------------------------------------
|NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS                                                         
|For the Year Ended December 31, 2014, 2013 and 2012                                                    
|(All
      tabular amounts are expressed in thousands of Canadian dollars unless
      otherwise noted)

NOTE 5  EXPLORATION AND EVALUATION (E&E) ASSETS

Canadian
    
    
    Canadian Oil
    
    
    United StatesUranium
    
    
    and Gas
    
    
    Oil and GasProperties
    
    
    Interests
    
    
    Interests
    
    
    Total$
    
    
    $
    
    
    $
    
    
    $Cost:Balance at January 1,
      2013
    
    533
    
    
    23
    
    
    25,463
    
    
    26,019Additions
    
    -
    
    
    10
    
    
    134
    
    
    144Change in
      decommissioning provision
    
    -
    
    
    37
    
    
    -
    
    
    37Disposals
    
    (533
    )
    
    -
    
    
    (8,930
    )
    
    (9,463
    )Foreign currency translation and other
    
    -
    
    
    -
    
    
    1,631
    
    
    1,631Balance at December 31, 2013
    
    -
    
    
    70
    
    
    18,298
    
    
    18,368Additions
    
    -
    
    
    4
    
    
    116
    
    
    120Change in decommissioning provision
    
    -
    
    
    192
    
    
    -
    
    
    192Disposals
    
    -
    
    
    -
    
    
    (3,758
    )
    
    (3,758
    )Foreign currency translation and other
    
    -
    
    
    -
    
    
    1,192
    
    
    1,192Balance at December 31, 2014
    
    -
    
    
    266
    
    
    15,848
    
    
    16,114


|                                       |  | Canadian   |   |  | Canadian Oil |  |  | United States |   |  |         |  
|-------------------------------------- |  | ---------- | - |  | ------------ |  |  | ------------- | - |  | ------- | -
|                                       |  | Uranium    |   |  | and Gas      |  |  | Oil and Gas   |   |  |         |  
|                                       |  | Properties |   |  | Interests    |  |  | Interests     |   |  | Total   |  
|                                       |  | $          |   |  | $            |  |  | $             |   |  | $       |  
|Accumulated impairment losses:         |  |            |   |  |              |  |  |               |   |  |         |  
|Balance at January 1,
      2013       |  | (271       | ) |  | -            |  |  | (21,858       | ) |  | (22,129 | )
|Impairment losses                      |  | (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 | )
|Impairment losses (Note 7)             |  | -          |   |  | -            |  |  | (88           | ) |  | (88     | )
|Disposals                              |  | -          |   |  | -            |  |  | 3,028         |   |  | 3,028   |  
|Foreign currency translation and other |  | -          |   |  | -            |  |  | (860          | ) |  | (860    | )
|Balance at December 31, 2014           |  | -          |   |  | -            |  |  | (13,007       | ) |  | (13,007 | )

**Canadian**
    
    
    **Canadian Oil**
    
    
    United States**Uranium**
    
    
    **and
    Gas**
    
    
    Oil and Gas**Properties**
    
    
    **Interests**
    
    
    Interests
    
    
    Total$
    
    
    $
    
    
    $
    
    
    $Carrying amounts:At December 31, 2013
    
    -
    
    
    70
    
    
    3,211
    
    
    3,281At December 31, 2014
    
    -
    
    
    266
    
    
    2,841
    
    
    3,107


Exploration and evaluation (E&E) assets consist of the
Companys exploration projects which are pending the determination of proven
reserves.

F-20

---

NOTE 5  EXPLORATION AND EVALUATION (E&E) ASSETS
(continued)

United States Exploration and Evaluation
Properties

As at December 31, 2014, 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, 2014, the Company sold its
working interests in certain oil and gas leases in the areas of Colorado to
unrelated third parties for gross proceeds of $412,000 (US$386,000). The loss on
the disposal was $318,000.

During the year ended December 31, 2014, the Company
capitalized $66,000 (December 31, 2013  $79,000) of general and administrative
costs related to its US oil and gas interests.

The E&E asset impairment is $88,000 and $415,000 for the
year ended December 31, 2014 and December 31, 2013, 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.

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, 2013                |  | 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 |  
|Additions                                 |  | 6,898        |   |  | 250           |   |  | 13            |   |  | 7,161  |  
|Change in decommissioning
      provision |  | 733          |   |  | 81            |   |  | -             |   |  | 814    |  
|Disposals                                 |  | -            |   |  | (5,493        | ) |  | (121          | ) |  | (5,614 | )
|Foreign currency translation and other    |  | -            |   |  | 853           |   |  | 2             |   |  | 855    |  
|Balance at December 31, 2014              |  | 32,181       |   |  | 9,970         |   |  | 219           |   |  | 42,370 |  

F-21

---

NOTE 6  PROPERTY AND EQUIPMENT (continued)

|                                                                 |  | 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, 2013                                       |  | (14,768      | ) |  | (1,927        | ) |  | (251          | ) |  | (16,946 | )
|Amortization and depletion                                       |  | (2,036       | ) |  | (493          | ) |  | (25           | ) |  | (2,554  | )
|Impairment losses                                                |  | (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 | )
|Amortization and depletion (Note 7)                              |  | (2,447       | ) |  | (402          | ) |  | (18           | ) |  | (2,867  | )
|Impairment losses (Note 7)                                       |  | (3,560       | ) |  | -             |   |  | -             |   |  | (3,560  | )
|Disposals                                                        |  | -            |   |  | 705           |   |  | 108           |   |  | 813     |  
|Foreign currency translation and other                           |  | -            |   |  | (78           | ) |  | (1            | ) |  | (79     | )
|Balance at December 31, 2014                                     |  | (23,340      | ) |  | (932          | ) |  | (189          | ) |  | (24,461 | )

|                     |   | Canadian Oil |  |   | United States |  |   |               |  |   |        | 
|-------------------- | - | ------------ |  | - | ------------- |  | - | ------------- |  | - | ------ | 
|                     |   | and Gas      |  |   | Oil and Gas   |  |   | Corporate and |  |   |        | 
|                     |   | Interests    |  |   | Interests     |  |   | Other Assets  |  |   | Total  | 
|                     | $ |              |  | $ |               |  | $ |               |  | $ |        | 
|Carrying amounts:    |   |              |  |   |               |  |   |               |  |   |        | 
|At December 31, 2013 |   | 7,217        |  |   | 13,122        |  |   | 47            |  |   | 20,386 | 
|At December 31, 2014 |   | 8,841        |  |   | 9,038         |  |   | 30            |  |   | 17,909 | 

Canadian Oil and Gas Interests

In July 2014, the Company closed the acquisition of an
additional 24% working interest in the Drake/Woodrush oilfield in Northeastern
B.C. to increase its working interest to 99%. As consideration for the purchase,
the Company issued 9,600,000 common shares at a price of $0.202 per share for
$1,939,000. A company controlled by the CEO of the Company (HEC) sold its 5%
working interest in the Drake/Woodrush property for 2,000,000 common shares
included in the above.

In March 2014, the Company paid $626,000 cash to purchase
certain natural gas producing assets and related processing facilities adjacent
to its existing Woodrush oilfield at Ft. St. John, British Columbia. The assets
acquired included a 54% working interest in a Halfway formation well, a 74%
working interest in 2 shut-in natural gas wells, a 96.8% working interest in a
Sour Processing Facility, and an additional 9,600 net acres (44% developed). The
properties so acquired have a fair value of $2,146,000, applying a 10% discount
factor to expected future net cash flows. The Company also assumed related
decommissioning liabilities of $1,520,000, applying a weighted average discount
rate of 2.04% and an inflation rate of 2%.

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, 2014 included estimated future development costs of
$683,000 (December 31, 2013 - $899,000; December 31, 2012 - $Nil) associated
with the development of proved undeveloped reserves.

During the year ended December 31, 2014, the Company
capitalized $138,000 (December 31, 2013  $nil) of general and administrative
costs related to its Canadian oil and gas interests.

F-22

---

NOTE 6  PROPERTY AND EQUIPMENT (continued)

In light of the significant decline in oil benchmark prices
during late 2014 and continued softening in natural gas prices, impairment tests
were conducted at December 31, 2014 on each of the Companys CGUs. The estimated
recoverable amounts were determined using fair value less cost to sell.

In determining the recoverability of oil and gas interests and
making these evaluations, the Company used the net present value of the cash
flows from proved plus probable oil and gas reserves of each CGU as estimated by
the Companys independent reserve evaluator.

Key input estimates used in the determination of cash flows
from oil and gas reserves include the following:

|a) | Reserves  Assumptions that are valid at the time of
      reserve estimation may change significantly when new information becomes
      available. Changes in forward price estimates, production costs or
      recovery rates may change the economic status of reserves and may
      ultimately result in reserves being restated.                                            
|-- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   |                                                                                                                                                                                                                                                                                                                                                                                     
|b) | Crude oil and natural gas prices  Forward price
      estimates of the crude oil and natural gas prices are used in the cash
      flow model. Commodity prices have fluctuated widely in recent years due to
      global and regional factors including supply and demand fundamentals,
      inventory levels, exchange rates, weather, economic and geopolitical
      factors.
|   |                                                                                                                                                                                                                                                                                                                                                                                     
|c) | Discount rate  The discount rate used to calculate the
      net present value of cash flows is 10.7% post tax.                                                                                                                                                                                                                                                                    

Below are the following forward commodity price estimates used
in the December 31, 2014 impairment test:

|                                                                                          | Natural gas   | Condensate               | Crude oil     
|----------------------------------------------------------------------------------------- | ------------- | ------------------------ | --------------
|                                                                                          | (AECO)        | (Edmonton Pentanes Plus) | (Edmonton Par)
|                                                                                          | Cdn $ / mmbtu | Cdn $ / bbl              | Cdn $ / bbl   
|2015                                                                                      | 3.31          | 69.24                    | 64.71         
|2016                                                                                      | 3.77          | 85.60                    | 80.00         
|2017                                                                                      | 4.02          | 91.71                    | 85.71         
|2018                                                                                      | 4.27          | 97.83                    | 91.43         
|2019                                                                                      | 4.53          | 103.94                   | 97.14         
|2020                                                                                      | 4.78          | 110.06                   | 102.86        
|2021                                                                                      | 5.03          | 113.62                   | 106.18        
|2022                                                                                      | 5.28          | 115.89                   | 108.31        
|2023                                                                                      | 5.53          | 118.20                   | 110.47        
|2024                                                                                      | 5.71          | 120.56                   | 112.67        
|Each benchmark price increased on average
      approximately 2% from 2014 and thereafter |              

For the year ended December 31, 2014, the Company recorded an
impairment of $3,560,000 (December 31, 2013 - $529,000) on its Drake/Woodrush
CGU. The impairment was recognized because the carrying value exceeded the
recoverable amount. The fair value less cost to sell values used to determine
the recoverable amounts of the impaired PP&E assets are classified as Level
3 fair value measurements.

United States Oil and Gas Interests

On June 30, 2014, the Company closed the sale of 65% of its
working interest in the initial four wells drilled in 2013 at its Kokopelli
project in Colorado, together with certain related production facilities, for
$4,136,000 (US$3,876,000) cash and a 25% carried working interest in a US$16.0
million drilling and completion program planned for 2014 to be funded 100% by
the Purchaser of the assets. The Company assigned a value of $4,377,000
(US$4,099,000) to the value of the carried interest based on the price paid by
the Purchaser for the undrilled petroleum and natural gas rights at Kokopelli.
The sales transaction resulted in gross proceeds on disposition of $8,513,000
and a gain on sale of assets of $6,822,000 (US$6,394,000) for the period. The
sales transaction resulted in the de-recognition of certain oil and gas assets,
along with an adjustment to the financial contract liability. The net gain on
this transaction was $1.9 million.

F-23

---

NOTE 6  PROPERTY AND EQUIPMENT (continued)

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, 2014 included estimated future development costs of
$95.0 million (December 31, 2013 - $258.8 million; December 31, 2012 - $326.9
million) associated with the development of proved undeveloped reserves.

During the year ended December 31, 2014, the Company
capitalized $198,000 (December 31, 2013  $520,000) of general and
administrative costs related to its US oil and gas interests.

At December 31, 2014 and December 31, 2013, the Company
evaluated its oil and gas interests for indicators of any impairment or related
recovery. As a result, there were no indicators of any impairment or related
recovery. No impairment was recognized on any of the CGUs at December 31, 2014
and December 31, 2013.

NOTE 7  AMORTIZATION, DEPLETION AND IMPAIRMENT
LOSSES

|                                                       |  | Year ended December 31 | 
|------------------------------------------------------ |  | ---------------------- | 
|                                                       |  | 2014                   | 
|                                                       |  | **$**                  | 
|Exploration and Evaluation
      Assets (E & E assets) |  |                        | 
|Impairment losses
      (Note 5)                       |  | 88                     | 
|                                                       |  |                        | 
|Property and Equipment (D & P
      assets)            |  |                        | 
|Amortization and depletion (Note 6)                    |  | 2,867                  | 
|Impairment losses (Note 6)                             |  | 3,560                  | 
|                                                       |  | 6,515                  | 

NOTE 8  BANK CREDIT FACILITY

On June 5, 2014 and amended on June 27, 2014, DEAL renewed its
Credit Facility with the Bank for a maximum amount of $2.9 million. Effective
July 1, 2014, the Credit Facility reduces by $100,000 per month. Interest on the
loan is Prime + 3% payable monthly and the amount outstanding is payable on
demand any time. Collateral for the Credit Facility is provided by a $10.0
million first floating charge over all the assets of DEAL, a general assignment
of DEALs book debts and a $10.0 million debenture with a first floating charge
over all the assets of the Company. Additionally, an amount of US$385,000 was
deposited in the Companys US$ account with the Bank at June 30, 2014 upon the
Banks request to be applied to DEALs general operations.

On July 29, 2014, the Company renewed the Credit Facility with
its Bank for a maximum of $2.8 million, reducing $100,000 per month, each
through November 1, 2014. As part of the renewal, the Company can utilize the
US$385,000 on deposit with its Bank at June 30, 2014 on the operations and
capital programs of DEAL at the Companys discretion. Further, on November 24,
2014, the Company renewed the Credit Facility with its Bank for a maximum of
$2.2 million. The Bank is currently conducting its annual review of the
Company's Canadian oil and gas reserves for loan purposes.

Under the terms of the Credit Facility, 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 Facility) 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, 2014, DEAL was in default of its working capital ratio covenant
with a 0.56 to 1 ratio.

F-24

---

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 or loss for
the period.

|                                                |  | #          |   |  | $      |  
|----------------------------------------------- |  | ---------- | - |  | ------ | -
|                                                |  |            |   |  |        |  
|Balance at January 1,
      2012                |  | 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    |  
|Granted, investor warrants                      |  | 6,000,000  |   |  | 355    |  
|Warrants expired                                |  | (7,700,000 | ) |  | (2     | )
|Change in fair value                            |  | -          |   |  | 78     |  
|Balance at December 31, 2014                    |  | 19,597,729 |   |  | 755    |  

During the year ended December 31, 2014, 7,700,000 US$0.40
warrants expired unexercised. During the year ended December 31, 2014, none of
the US$ warrants were exercised (December 31, 2013  Nil; December 31, 2012 
2,419,584).

As described in Note 13, in August 2014, the Company issued
6,000,000 investor warrants each of which entitles the holder to purchase one
common share of the Company at an exercise price of US$0.35 until December 31,
2015. The fair value of these warrants was estimated using the Hull-White
Trinomial option pricing model under the following inputs:

December 31,
    
    
    August 15,As at
    
    2014
    
    
    2014Exercise price
    US$
    0.35
    
    US$
    0.35Share price
    US$
    0.18
    
    US$
    0.26Expected volatility
    
    67%
    
    
    79%Expected life
    
    1.00 years
    
    
    1.38 yearsDividends
    
    0.0%
    
    
    0.0%Risk-free interest rate
    
    0.3%
    
    
    0.2%


NOTE 10  LOAN FACILITY

On June 30, 2014, the Company paid $3,563,000 to settle its
outstanding loan facility of $3.5 million plus accrued interest of $63,000 to
the Lender, resulting in a loss on debt settlement of $388,000. With the
payment, all outstanding debt obligations are extinguished and the Lender has
released and discharged the collateral security taken in respect of the loan
facility. For the year ended December 31, 2014, the Company paid $256,000 in
interest to the Lender (December 31, 2013 - $238,000).

An embedded derivative liability in the amount of $216,000
related to 6,591,667 incentive share purchase warrants attached to the original
$3.5 million loan facility remains outstanding at December 31, 2014. During the
year ended December 31, 2014, 700,000 warrants were exercised and a liability in
the amount of $70,000 (note 13) was reallocated as share capital.

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, 2014, the Company
recorded no gain or loss on the derivative liability (year ended December 31,
2013 - $264,000 gain). The following key inputs to obtain the valuation:

F-25

---

NOTE 10  LOAN FACILITY (continued)

|As at                   |   | December 31, 2014 |  |   | December 31, 2013 |  |   | June 18, 2013 | 
|----------------------- | - | ----------------- |  | - | ----------------- |  | - | ------------- | 
|Exercise price          | $ | 0.24              |  | $ | 0.24              |  | $ | 0.24          | 
|Share price             | $ | 0.21              |  | $ | 0.15              |  | $ | 0.20          | 
|Expected volatility     |   | 69%               |  |   | 84%               |  |   | 79%           | 
|Expected life           |   | 0.6 year          |  |   | 1.5 years         |  |   | 2 years       | 
|Dividends               |   | 0.0%              |  |   | 0.0%              |  |   | 0.0%          | 
|Risk-free interest rate |   | 1.0%              |  |   | 1.1%              |  |   | 1.1%          | 

NOTE 11  DECOMMISSIONING LIABILITY

|                                            |  | Canadian       |   |  | United States  |   |  |       |  
|------------------------------------------- |  | -------------- | - |  | -------------- | - |  | ----- | -
|                                            |  | Oil and Gas    |   |  | Oil and Gas    |   |  |       |  
|                                            |  | Properties (1) |   |  | Properties (1) |   |  | Total |  
|                                            |  | $              |   |  | $              |   |  | $     |  
|Balance at January 1,
      2013            |  | 1,308          |   |  | 121            |   |  | 1,429 |  
|Change in estimated future cash flows       |  | (134           | ) |  | 23             |   |  | (111  | )
|Disposals                                   |  | -              |   |  | (35            | ) |  | (35   | )
|Actual costs incurred and other             |  | (112           | ) |  | 8              |   |  | (104  | )
|Unwinding of discount                       |  | 30             |   |  | 3              |   |  | 33    |  
|Balance at December 31, 2013                |  | 1,092          |   |  | 120            |   |  | 1,212 |  
|Change in estimated future
      cash flows |  | 370            |   |  | 6              |   |  | 376   |  
|Additions                                   |  | 2,076          |   |  | 76             |   |  | 2,152 |  
|Disposals                                   |  | -              |   |  | (104           | ) |  | (104  | )
|Actual costs incurred                       |  | -              |   |  | 11             |   |  | 11    |  
|Unwinding of discount                       |  | 59             |   |  | 3              |   |  | 62    |  
|Balance at December 31, 2014                |  | 3,597          |   |  | 112            |   |  | 3,709 |  

|(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, 2014: |              |              
|Discount rate            | 1.71%        | 2.20%        
|Inflation rate           | 2.00%        | 2.00%        
|                         |              |              
|As at December 31, 2013: |              |              
|Discount rate            | 2.55%        | 2.72%        
|Inflation rate           | 2.00%        | 2.00%        

F-26

---

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) to fund the
drilling of up to three wells and the completion of up to four wells in the
State of Colorado. The Drilling Fund contributed US$6.5 million cash to earn
working interests in production from the wellbores ranging from 55.56% to 77.78%
before payout and 44.44% to 58.33% after payout. This amount was subsequently
increased by US$500,000 to US$7,000,000 with the Companys consent.

The December 31, 2012 financial contract states the Drilling
Fund has the right to require Dejour USA to purchase its working interests in
the wellbores for cash in September 2016, 36-months after the final well in the
4-well program is placed in production. The repurchase price is based on a
predetermined formula which ensures the Drilling Fund earns a minimum return,
compounded annually and applied on a monthly basis, on 75% of its original
US$7,000,000 investment over the 36-month period. Accordingly, the Company
considered the transaction to be a financial contract as the risks and rewards
of ownership were not substantially transferred to the Drilling Fund and, on
December 31, 2012, the Company recorded the transaction in its accounts by
increasing property and equipment and financial contract liability by
US$6,500,000 on its balance sheet. This amount was subsequently increased to
US$7,000,000.

On June 30, 2014, the financial contract was amended and the
Drilling Fund agreed to retain its working interest in the wells as at September
30, 2016, should it exercise its right to require Dejour USA to pay the minimum
return calculated in accordance with the provisions of the contract. In
determining the minimum return to be paid, the Drilling Fund agreed to deduct
the residual reserve value of its working interest in the 4 wellbores at
September 30, 2016. The parties also agreed to have a third party engineering
firm calculate the residual value of the reserves in accordance with industry
accepted valuation standards.

Finally, the parties agreed to limit the cash consideration to
be paid by Dejour USA, should it be required to pay the minimum return provided
for in the December 31, 2012 contract to US$3,000,000. Additional consideration,
if any, may be paid by Dejour USA by an assignment of a working interest in
certain proven assets at a jointly owned oil and gas property in Colorado
applying an industry-standard valuation approach.

The June 30, 2014 amendment transferred the risks of ownership
of the 4 wellbores back to the Drilling Fund and the financial contract
liability was adjusted to reflect the present value of the amount owing to the
Drilling Fund under the financial contract at September 30, 2016 ($5,519,000),
net of the present value of the residual reserves ($2,780,000), or $2,739,000,
as follows:

|                                                   | $                                                    
|-------------------------------------------------- | -----------------------------------------------------
|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)     
|(b)                                                | Gain on financial contract liability (US$1,192)      
|Balance at December
      31, 2013 (US$5,755)      | 6,121                                                
|Loan advance during the year
      (US$181)        | 210                                                  
|Accretion expense
      (US$388)                   | 450                                                  
|Foreign exchange loss                              | 351                                                  
|                                                   | 7,132                                                
|Less:                                              |                                                      
|(a)                                                | Net Operating
      income (US$846)                  
|(b)                                                | Adjustment to financial contract liability (US$3,117)
|Balance at December 31, 2014 (US$2,361)            | 2,739                                                

F-27

---

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,
      2012                                       |  | 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     | 
|Issue of shares on exercise
      of warrants and options              |  | 10,885,765  |  |  | 2,232      | 
|Warrant liability reallocated on exercise of
      warrants            |  | -           |  |  | 70         | 
|Contributed surplus
      reallocated on exercise of options           |  | -           |  |  | 746        | 
|Shares issued via acquisition of property,
      net of issuance costs |  | 9,600,000   |  |  | 1,890      | 
|Shares issued via private placements, net of issuance
      costs      |  | 13,000,000  |  |  | 1,920      | 
|Balance at December 31, 2014                                           |  | 182,402,139 |  |  | 97,132     | 

During the year ended December 31, 2014, the Company
completed the following:

On August 14, 2014, the Company completed a private placement
of 6,000,000 units at US$0.25 per unit. Each unit consists of one common share
and 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
until December 31, 2015. Gross proceeds raised were $1,640,000 (US$1,500,000).
In connection with this private placement, the Company paid other related costs
of $64,000. The grant date fair value of the warrants, estimated to be $355,000,
has been recognized as a derivative financial liability (Note 9). Issue costs of
$14,000 related to the warrants were expensed. If at any time prior to April 14,
2015, the Company issues any common shares at a price that is less than US$0.25,
then as long as the subscribers to the August 14, 2014 private placement hold
any shares, the Company will issue to the subscribers, at no additional cost,
that number of shares as is determined by the following formula:

|Number of additional shares     | = | (US$0.25  New Subscription
      Price (in US$)) | x | Number of shares held
      by the subscriber prior to the issuance
|------------------------------- | - | ------------------------------------------------- | - | -------------------------------------------------------------------
|New Subscription Price (in US$)

The Company considers the protection feature to have a nil
value at initial recognition and year-end because of the zero probability of any
equity financing taking place prior to April 14, 2015.

In July 2014, the Company closed the acquisition of an
additional 24% working interest in the Drake/Woodrush oilfield in Northeastern
B.C. to increase its working interest to 99%. As consideration for the purchase,
the Company issued 9,600,000 common shares at a price of $0.202 per share for
$1,939,000. In connection with this acquisition, the Company paid other related
costs of $49,000. A company controlled by the CEO of the Company (HEC) sold
its 5% working interest in the Drake/Woodrush property for 2,000,000 common
shares.

In January 2014, the Company completed a private placement of
7,000,000 common shares at $0.11 per share. Gross proceeds raised were $770,000.
In connection with this private placement, the Company paid finders fees of
$27,000 and other related costs of $58,000. Directors and Officers of the
Company purchased 900,000 common shares of this offering.

F-28

---

NOTE 13  SHARE CAPITAL (continued)

During the year ended December 31, 2014, 10,185,765 stock
options were exercised with an average exercise price of $0.20 each. Directors
and Officers of the Company exercised 6,858,008 stock options with an average
exercise price of $0.20 each.

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
9). 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. 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.

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:

F-29

---

NOTE 14  STOCK OPTIONS AND SHARE PURCHASE WARRANTS

|(a) | Stock Options
|--- | -------------

|                                 |  | Number of   |   |  | Weighted average | 
|-------------------------------- |  | ----------- | - |  | ---------------- | 
|                                 |  | options     |   |  | exercise price   | 
|                                 |  |             |   |  | $                | 
|Balance at January 1,
      2012 |  | 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             | 
|Options granted                  |  | 16,989,006  |   |  | 0.25             | 
|Options exercised (Note 13)      |  | (10,185,765 | ) |  | 0.20             | 
|Options forfeited                |  | (2,554,141  | ) |  | 0.20             | 
|Options expired                  |  | (170,000    | ) |  | 0.20             | 
|Balance at December 31, 2014     |  | 14,701,601  |   |  | 0.25             | 

Details of the outstanding and exercisable stock options as
at December 31, 2014 are as follows:

Outstanding
    
    
    ExercisableWeighted
      average
    
    
    
    
    
    Weighted
      averageNumber
    
    
    exercise
    
    
    contractual
    
    
    Number
    
    
    exercise
    
    
    contractualof options
    
    
    price
    
    
    life (years)
    
    
    of options
    
    
    price
    
    
    life (years)$
    
    
    
    
    
    
    
    
    $$0.18
    
    556,250
    
    
    0.18
    
    
    1.26
    
    
    37,500
    
    
    0.18
    
    
    1.26$0.20
    
    2,981,250
    
    
    0.20
    
    
    3.85
    
    
    1,143,750
    
    
    0.20
    
    
    3.48$0.25
    
    300,000
    
    
    0.25
    
    
    2.83
    
    
    43,750
    
    
    0.25
    
    
    2.78$0.26
    
    8,295,400
    
    
    0.26
    
    
    2.27
    
    
    2,370,114
    
    
    0.26
    
    
    2.27$0.29
    
    3,068,701
    
    
    0.29
    
    
    2.63
    
    
    767,176
    
    
    0.29
    
    
    2.6314,701,601
    
    
    0.25
    
    
    2.68
    
    
    4,362,290
    
    
    0.25
    
    
    2.65


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 |   | 2014             |  |   | 2013       |  |   | 2012       | 
|------------------------------ | - | ---------------- |  | - | ---------- |  | - | ---------- | 
|                               |   |                  |  |   |            |  |   |            | 
|Fair value at grant date       | $ | 0.12             |  | $ | 0.07       |  | $ | 0.08       | 
|Exercise price                 | $ | 0.25             |  | $ | 0.18       |  | $ | 0.25       | 
|Share price                    | $ | 0.25             |  | $ | 0.18       |  | $ | 0.25       | 
|Expected volatility            |   | 84.51%           |  |   | 81.18%     |  |   | 82.70%     | 
|Expected option life           |   | 2.23
      years |  |   | 1.42 years |  |   | 1.59 years | 
|Dividends                      |   | 0.0%             |  |   | 0.0%       |  |   | 0.0%       | 
|Risk-free interest rate        |   | 1.09%            |  |   | 1.01%      |  |   | 1.12%      | 

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 6.07% (2013  6.48%
and 2012  5.90%) is used when recording stock based compensation.

F-30

---

NOTE 14  STOCK OPTIONS AND SHARE PURCHASE WARRANTS
(continued)

|(b) | Share Purchase Warrants
|--- | -----------------------

The following table summarizes information about warrant
transactions:

|                                 |  | Number of   |   |  | Weighted average | 
|-------------------------------- |  | ----------- | - |  | ---------------- | 
|                                 |  | warrants    |   |  | exercise price   | 
|                                 |  |             |   |  | $                | 
|Balance at January 1,
      2012 |  | 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             | 
|Warrants granted                 |  | 6,000,000   |   |  | 0.41             | 
|Warrants exercised               |  | (700,000    | ) |  | 0.24             | 
|Warrants expired                 |  | (11,812,051 | ) |  | 0.49             | 
|Balance at December 31, 2014     |  | 29,832,252  |   |  | 0.40             | 

Details of the outstanding and exercisable warrants as at
December 31, 2014 are as follows:

Outstanding
    
    
    ExercisableWeighted
      average
    
    
    
    
    
    Weighted
      averageNumber
    
    
    exercise
    
    
    Contractual
    
    
    Number
    
    
    exercise
    
    
    contractualof warrants
    
    
    price
    
    
    life (years)
    
    
    of warrants
    
    
    price
    
    
    life (years)$
    
    
    
    
    
    
    
    
    $$0.24
    
    6,591,667
    
    
    0.24
    
    
    0.56
    
    
    6,591,667
    
    
    0.24
    
    
    0.56$0.40
    
    3,642,856
    
    
    0.40
    
    
    0.88
    
    
    3,642,856
    
    
    0.40
    
    
    0.88$0.35 US
    
    6,000,000
    
    
    0.41
    
    
    1.00
    
    
    6,000,000
    
    
    0.41
    
    
    1.00$0.40 US
    
    13,597,729
    
    
    0.46
    
    
    2.43
    
    
    13,597,729
    
    
    0.46
    
    
    2.4329,832,252
    
    
    0.40
    
    
    1.54
    
    
    29,832,252
    
    
    0.40
    
    
    1.54


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.

During the year ended December 31, 2014, 96,900 US$0.46
warrants and 7,700,000 US$0.40 warrants expired unexercised.

F-31

---

NOTE 15  SUPPLEMENTAL INFORMATION

|(a) | Changes in working capital consisted of the
      following:
|--- | ------------------------------------------------------------

|                                               |      | Year ended December 31 |  
|---------------------------------------------- | ---- | ---------------------- | -
|                                               |      | **2014**               |  
|                                               | **** | **$**                  |  
|Changes in working
      capital:              |      |                        |  
|Accounts receivable                            |      | 226                    |  
|Share
      subscription receivable            |      | -                      |  
|Prepaids and deposits                          |      | (92                    | )
|Accounts payable and accrued
      liabilities |      | 892                    |  
|                                               |      | 1,026                  |  
|                                               |      |                        |  
|Comprised of:                                  |      |                        |  
|Operating
      activities                     |      | (481                   | )
|Investing activities                           |      | 1,507                  |  
|Financing activities                           |      | -                      |  
|                                               |      | 1,026                  |  
|                                               |      |                        |  
|Other cash flow information:                   |      |                        |  
|Cash paid
      for interest                   |      | 138                    |  
|Income taxes paid                              |      | -                      |  

|(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, | 
|------------------------------------------ |  | ----------------------- | 
|                                           |  | 2014                    | 
|Weighted average common shares outstanding |  |                         | 
|Basic                                      |  | 177,124,094             | 
|Diluted                                    |  | 177,124,094             | 

|(c) | The Company had the following non-cash
      transaction:
|--- | ---------------------------------------------------------

|                                                                                     |  | Year ended December 31, | 
|------------------------------------------------------------------------------------ |  | ----------------------- | 
|                                                                                     |  | 2014                    | 
|                                                                                     |  | **$**                   | 
|Non-cash financing for
      acquisition of property and equipment (note 6)          |  | 3,440                   | 
|Non-cash financing for drilling operations of property and
      equipment (note 12) |  | -                       | 

F-32

---

NOTE 16  RELATED PARTY TRANSACTIONS

During the years ended December 31, 2014, 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 $1,092,000 (2013 - $1,173,000 and 2012
      - $1,194,000) and non-cash stock-based compensation of $823,000 (2013 -
      $302,000 and 2012 - $412,000). Key management includes the Companys
      officers and directors. The salaries and consulting fees are included in
      general and administrative expenses. Included in accounts payable and
      accrued liabilities at December 31, 2014 is $200,000 (December 31, 2013 -
      $Nil and December 31, 2012 - $Nil) owing to the two officers of the
      Company. The repayment is subject to the availability of cash after all
      other key obligations of the Company are met.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|(b) | Included in interest and other income is $15,000 (2013 -
      $21,200 and 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. Effective July 3, 2014, HEC ceased to be the working interest
      partner in the Woodrush property and sold its 5% working interest to the
      Company for 2,000,000 common shares.                                                                                                                                                                                                                                                                                                                                                                                                            

NOTE 17  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:

|                                                                   |  | 2014   |   |  | 2013   |   |  | 2012    |  
|------------------------------------------------------------------ |  | ------ | - |  | ------ | - |  | ------- | -
|                                                                   |  | $      |   |  | $      |   |  | $       |  
|Loss before income taxes                                           |  | (7,203 | ) |  | (2,577 | ) |  | (11,752 | )
|Corporate tax rate                                                 |  | 25.50% |   |  | 25.21% |   |  | 28.48%  |  
|                                                                   |  |        |   |  |        |   |  |         |  
|Expected tax recovery                                              |  | (1,837 | ) |  | (649   | ) |  | (3,347  | )
|Increase (decrease) resulting
      from:                          |  |        |   |  |        |   |  |         |  
|Differences in foreign tax rates and change in statutory tax rates |  | 122    |   |  | (352   | ) |  | 475     |  
|Impact of foreign exchange rate changes                            |  | (792   | ) |  | (452   | ) |  | 259     |  
|Change in unrecognized deferred tax assets                         |  | 4,224  |   |  | 2,251  |   |  | 2,799   |  
|Stock based compensation and share issue costs                     |  | (187   | ) |  | (197   | ) |  | (197    | )
|Non
      taxable/deductible amounts                               |  | (1,530 | ) |  | (601   | ) |  | (121    | )
|Other adjustments                                                  |  | -      |   |  | -      |   |  | 132     |  
|Deferred income tax recovery                                       |  | -      |   |  | -      |   |  | -       |  

No deferred tax asset has been recognized in respect of the
following losses and deductible temporary differences as it is not considered
probable that sufficient future taxable profit will allow the deferred tax
assets to be recovered.

|                                               |  | 2014   |  |  | 2013   |  |  | 2012   | 
|---------------------------------------------- |  | ------ |  |  | ------ |  |  | ------ | 
|                                               |  | $      |  |  | $      |  |  | $      | 
|Deferred income tax assets                     |  |        |  |  |        |  |  |        | 
|Non-capital losses available                   |  | 23,039 |  |  | 20,026 |  |  | 11,290 | 
|Capital losses available                       |  | 1,072  |  |  | 1,072  |  |  | 1,030  | 
|Resource tax pools in excess of net book value |  | 3,062  |  |  | 2,495  |  |  | 8,928  | 
|Share issue costs
      and other              |  | 797    |  |  | 153    |  |  | 247    | 
|Unrecognized deferred tax assets               |  | 27,970 |  |  | 23,746 |  |  | 21,495 | 

F-33

---

NOTE 17  INCOME TAXES

The Company has the approximate amounts of tax pools available
as follows:

|As at December 31                              |  | 2014    |  |  | 2013    |  |  | 2012   | 
|---------------------------------------------- |  | ------- |  |  | ------- |  |  | ------ | 
|                                               |  | $       |  |  | $       |  |  | $      | 
|Canada:                                        |  |         |  |  |         |  |  |        | 
|Exploration and development expenditures       |  | 17,927  |  |  | 15,050  |  |  | 17,218 | 
|Unamortized share issue costs                  |  | 648     |  |  | 858     |  |  | 988    | 
|Capital losses                                 |  | 8,242   |  |  | 8,242   |  |  | 8,242  | 
|Non-capital losses                             |  | 28,846  |  |  | 24,918  |  |  | 22,762 | 
|                                               |  | 55,663  |  |  | 49,068  |  |  | 49,210 | 
|                                               |  |         |  |  |         |  |  |        | 
|United States:                                 |  |         |  |  |         |  |  |        | 
|Exploration and development
      expenditures |  | 11,697  |  |  | 17,039  |  |  | 33,287 | 
|Undeducted expenses                            |  | 1,685   |  |  | -       |  |  | -      | 
|Non-capital losses                             |  | 38,949  |  |  | 36,112  |  |  | 15,324 | 
|                                               |  | 52,331  |  |  | 53,151  |  |  | 48,611 | 
|                                               |  |         |  |  |         |  |  |        | 
|Total                                          |  | 107,994 |  |  | 102,219 |  |  | 97,821 | 

The exploration and development expenditures at December 31,
2014 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 |  | -      |  |  | 2,341               |  |  | 2,341  | 
|2027 |  | 4,152  |  |  | 3,120               |  |  | 7,272  | 
|2028 |  | 4,674  |  |  | 234                 |  |  | 4,908  | 
|2029 |  | 3,373  |  |  | 3,021               |  |  | 6,394  | 
|2030 |  | 2,070  |  |  | 2,566               |  |  | 4,636  | 
|2031 |  | 2,407  |  |  | 2,584               |  |  | 4,991  | 
|2032 |  | 4,357  |  |  | 7,034               |  |  | 11,391 | 
|2033 |  | 2,156  |  |  | 14,994              |  |  | 17,150 | 
|2034 |  | 3,928  |  |  | 3,055               |  |  | 6,983  | 
|     |  | 28,846 |  |  | 38,949              |  |  | 67,795 | 

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 18  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:

|     |  | $   | 
|---- |  | --- | 
|2015 |  | 130 | 
|2016 |  | 49  | 
|     |  | 179 | 

F-34

---

NOTE 19  PERSONNEL EXPENSES

The aggregate compensation expense of key management was as
follows:

|                                         |  | Year ended December 31 |  
|---------------------------------------- |  | ---------------------- | -
|                                         |  | 2014                   |  
|                                         |  | **$**                  |  
|Salaries, benefits and fees              |  | 1,092                  |  
|Non-cash stock-based compensation        |  | 823                    |  
|                                         |  | 1,915                  |  
|Capitalized portion of salaries and fees |  | (127                   | )
|                                         |  | 1,788                  |  

NOTE 20  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
    
    
    
    
    
    
    
    
    Total2014
    
    
    2013
    
    
    2012
    
    
    2014
    
    
    2013
    
    
    2012
    
    
    2014
    
    
    2013
    
    
    2012**$**
    
    

    $
    
    
    $
    
    
    **$**
    
    
    $
    
    
    $
    
    
    **$**
    
    
    $
    
    
    $Year ended December 31Revenues
    
    5,952
    
    
    6,039
    
    
    5,766
    
    
    1,609
    
    
    1,467
    
    
    -
    
    
    7,561
    
    
    7,506
    
    
    5,766Segmented income (loss)
    
    (8,259
    )
    
    (1,552
    )
    
    (8,361
    )
    
    1,056
    
    
    (1,025
    )
    
    (3,390
    )
    
    (7,203
    )
    
    (2,577
    )
    
    (11,752
    )Amortization, depletion andimpairment losses
    
    6,020
    
    
    2,714
    
    
    7,927
    
    
    495
    
    
    916
    
    
    2,749
    
    
    6,515
    
    
    3,630
    
    
    10,676Interest expense
    
    659
    
    
    669
    
    
    233
    
    
    429
    
    
    486
    
    
    1
    
    
    1,088
    
    
    1,155
    
    
    234Total capital expenditures
    
    6,915
    
    
    37
    
    
    1,423
    
    
    366
    
    
    2,341
    
    
    9,389
    
    
    7,281
    
    
    2,378
    
    
    10,812


NOTE 21  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.

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).

F-35

---

NOTE 21  DETERMINATION OF FAIR VALUES (continued)

At December 31, 2014 and December 31, 2013, 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).

NOTE 22  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, 2014 and 2013, no accounts receivable has been deemed
uncollectible or written off during the year.

As at December 31, 2014, the Companys receivables consist of
$57,000 (2013 - $4,000) from joint interest partners, $409,000 (2013 - $760,000)
from oil and natural gas marketers and $139,000 (2013 - $67,000) 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, 2014, $Nil (2013 - $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. At December 31,
2014, the Company was in default of its working capital ratio covenant on its
credit facility, refer to Note 2.

F-36

---

NOTE 22  FINANCIAL INSTRUMENTS AND CAPITAL MANAGEMENT
(continued)

|(b) | Liquidity Risk (continued)
|--- | --------------------------

The following are the contractual maturities of financial
liabilities as at December 31, 2014:

|                                               |  | Carrying amount |  |  | 2015  | 
|---------------------------------------------- |  | --------------- |  |  | ----- | 
|                                               |  | **$**           |  |  | $     | 
|Accounts payable and accrued
      liabilities |  | 3,516           |  |  | 3,516 | 
|Bank
      credit facilities                   |  | 1,955           |  |  | 1,955 | 
|                                               |  | 5,471           |  |  | 5,471 | 

For the contractual maturities of financial contract liability
as at December 31, 2014, 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, 2014 and 2013.

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

|                                         |  | 2014  |   |  | 2013   |  
|---------------------------------------- |  | ----- | - |  | ------ | -
|Expressed in foreign currencies          |  | CND$  |   |  | CND$   |  
|Cash and cash equivalents                |  | 1,128 |   |  | 376    |  
|Accounts receivable                      |  | 25    |   |  | 421    |  
|Accounts payable and accrued liabilities |  | (109  | ) |  | (1,613 | )
|Balance sheet exposure                   |  | 1,044 |   |  | (816   | )

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

|                                       |  | 2014   |  |  | 2013   | 
|-------------------------------------- |  | ------ |  |  | ------ | 
|December 31, reporting date
      rate |  | 1.1601 |  |  | 1.0636 | 
|YTD
      average USD to CAD           |  | 1.1048 |  |  | 1.0301 | 

The Company has performed a sensitivity analysis on its foreign
currency denominated financial instruments. Based on the Companys foreign
currency exposure noted above and assuming that all other variables remain
constant, a 10% appreciation of the US dollar against the Canadian dollar would
result in the decrease of net loss of $104,000 at December 31, 2014 (2013 -
$82,000 increase of net loss and 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.

F-37

---

NOTE 22  FINANCIAL INSTRUMENTS AND CAPITAL MANAGEMENT
(continued)

|(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, 2014,
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, 2014 would have increased or decreased net loss by $25,000. The
Company had no interest rate swaps or financial contracts in place at or during
the year ended December 31, 2014 and 2013.

|(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, 2014 would have decreased or increased net loss by $72,000. The Company had
no commodity contracts in place at December 31, 2014.

|(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, 2014, the Company was in default of the
covenant for its bank credit facility (Note 8).

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, 2014.

F-38

---

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 2014, 2013 and 2012 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, 2014. The conversion rate used per
Bank of Canada is 1.1601.

|(a) | Net proved oil and gas
reserves
|--- | -------------------------------

As at December 31, 2014, 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 January 27, 2015 and has an
effective date of December 31, 2014.

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 February 17, 2015 and has an effective
date of January 1, 2015.

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,
      2014
|--- | --------------------------------------------------------------

Net Proved 
      Developed and Proved Undeveloped Reserve sCanada
    
    
    
    United States
    
    
    
    
    TotalLight and
    Natural Gas
    
    Barrels of Oil
    
    
    Natural Gas
    
    Barrels of Oil
    Light and
    
    
    Natural Gas
    
    Barrels of OilMedium 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, 2013
    114
    2
    466
    194
    
    590
    3,596
    86,611
    18,621
    114
    
    590
    3,598
    87,077
    18,815Extensions
    22
    1
    385
    87
    
    -
    -
    -
    -
    22
    
    -
    1
    385
    87Technical Revisions
    32
    -
    60
    42
    
    (1)
    3
    33
    8
    32
    
    (1)
    3
    93
    50Acquisitions
    44
    2
    774
    175
    
    -
    -
    -
    -
    44
    
    -
    2
    774
    175Dispositions
    -
    -
    -
    -
    
    (381)
    (1,839)
    (56,318)
    (11,606)
    -
    
    (381)
    (1,839)
    (56,318)
    (11,606)Economic Factors
    -
    -
    -
    -
    
    -
    -
    23
    4
    -
    
    -
    -
    23
    4Production
    (57)
    (2)
    (250)
    (101)
    
    (1)
    (1)
    (26)
    (6)
    (57)
    
    (1)
    (3)
    (276)
    (107)December 31, 2014
    155
    3
    1,435
    397
    
    207
    1,759
    30,323
    7,021
    155
    
    207
    1,762
    31,758
    7,418Developed Producing
    128
    2
    822
    267
    
    1
    8
    136
    32
    128
    
    1
    10
    958
    299Developed Non-producing
    27
    1
    613
    130
    
    12
    101
    1,738
    403
    27
    
    12
    102
    2,351
    533Undeveloped
    -
    -
    -
    -
    
    194
    1,650
    28,449
    6,586
    -
    
    194
    1,650
    28,449
    6,586Total
    155
    3
    1,435
    397
    
    207
    1,759
    30,323
    7,021
    155
    
    207
    1,762
    31,758
    7,418


(1) Canada  Increase in Total Proved
Oil Reserves of 41 Mbbls and Natural Gas Reserves of 969 MMcf:

During the year ended December 31,
2014, the Company acquired an additional 24% working interest in its
northeastern British Columbia properties and increased total proved oil and
natural gas reserves by 41 Mbbls and 969 MMcf respectively.

(2) United States  Decrease in Total
Proved Natural Gas Liquids Reserves of 1,837 Mbbls and Natural Gas Reserves of
56,288 MMcf:

During the year ended December 31,
2014, the Company sold 65% of its working interest at Kokopelli in Colorado,
resulting in a reduction of its total proved natural gas and natural gas liquids
by 56,288 MMcf and 1,837 Mbbls, respectively.

---

CONSTANTPRICESANDCOSTS- YEARENDEDDECEMBER31,
2013

Ne t P rove d De
      ve lope d and P rove d Unde ve lope d Re s e rve sCanada
    
    
    
    Unite d S tate s
    
    
    
    
    TotalLight and
    Natural Gas
    
    Barrels of Oil
    
    
    Natural Gas
    
    Barrels of Oil
    
    Light and
    
    Natural Gas
    
    Barrels of OilMedium 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
    11,893Extensions
    -
    -
    -
    -
    
    283
    1,726
    41,571
    8,938
    
    -
    283
    1,726
    41,571
    8,938Technical 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
    87Production
    (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
    18,814Developed Producing
    114
    2
    466
    194
    
    3
    15
    367
    79
    
    114
    3
    17
    833
    273Developed Non-producing
    -
    -
    -
    -
    
    -
    -
    -
    -
    
    -
    -
    -
    -
    -Undeveloped
    -
    -
    -
    -
    
    587
    3,581
    86,243
    18,542
    
    -
    587
    3,581
    86,243
    18,542Total
    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.

---

|(b) | Capitalized Costs
|--- | -----------------

| |                                        |  | December 31, |   |  | December 31, |   |  | December 31, |  
| | -------------------------------------- |  | ------------ | - |  | ------------ | - |  | ------------ | -
| | (CA$
      thousands)                  |  | 2014         |   |  | 2013         |   |  | 2012         |  
| |                                        |  | $            |   |  | $            |   |  | $            |  
| | Canada                                 |  |              |   |  |              |   |  |              |  
| | Proved oil and gas properties          |  | 32,181       |   |  | 24,550       |   |  | 24,700       |  
| | Unproved
      oil and gas properties  |  | 266          |   |  | 70           |   |  | 23           |  
| | Total capital costs                    |  | 32,447       |   |  | 24,620       |   |  | 24,723       |  
| | Accumulated depletion and depreciation |  | (13,040      | ) |  | (10,593      | ) |  | (8,557       | )
| | Accumulated Impairment                 |  | (10,300      | ) |  | (6,740       | ) |  | (6,211       | )
| | Net
      capitalized costs            |  | 9,107        |   |  | 7,287        |   |  | 9,955        |  
| |                                        |  |              |   |  |              |   |  |              |  
| | United States                          |  |              |   |  |              |   |  |              |  
| | Proved oil and gas properties          |  | 9,970        |   |  | 14,279       |   |  | 13,076       |  
| | Unproved
      oil and gas properties  |  | 15,848       |   |  | 18,298       |   |  | 25,462       |  
| | Total capital costs                    |  | 25,818       |   |  | 32,577       |   |  | 38,538       |  
| | Accumulated depletion and depreciation |  | (343         | ) |  | (463         | ) |  | -            |  
| | Accumulated Impairment                 |  | (13,596      | ) |  | (15,781      | ) |  | (23,785      | )
| | Net capitalized
      costs            |  | 11,879       |   |  | 16,333       |   |  | 14,753       |  
| |                                        |  |              |   |  |              |   |  |              |  
| | Total                                  |  |              |   |  |              |   |  |              |  
| | Proved oil and gas properties          |  | 42,151       |   |  | 38,829       |   |  | 37,776       |  
| | Unproved oil and
      gas properties  |  | 16,114       |   |  | 18,368       |   |  | 25,485       |  
| | Total capital costs                    |  | 58,265       |   |  | 57,197       |   |  | 63,261       |  
| | Accumulated depletion and depreciation |  | (13,383      | ) |  | (11,056      | ) |  | (8,557       | )
| | Accumulated Impairment                 |  | (23,896      | ) |  | (22,521      | ) |  | (29,996      | )
| | Net capitalized
      costs            |  | 20,986       |   |  | 23,620       |   |  | 24,708       |  

---

|(c) | Costs Incurred
|--- | --------------

| |                                     |  | December 31, |  |  | December 31, |  |  | December 31, | 
| | ----------------------------------- |  | ------------ |  |  | ------------ |  |  | ------------ | 
| | (CA$
      thousands)               |  | 2014         |  |  | 2013         |  |  | 2012         | 
| |                                     |  | **$**        |  |  | **$**        |  |  | **$**        | 
| | Canada                              |  |              |  |  |              |  |  |              | 
| | Property acquisition costs (1)      |  |              |  |  |              |  |  |              | 
| | Proved oil and gas
      properties |  | 56           |  |  | 17           |  |  | 14           | 
| | Unproved oil and gas properties     |  | -            |  |  | -            |  |  | 1            | 
| | Exploration costs (2)               |  | 4            |  |  | 115          |  |  | 132          | 
| | Development
      costs (3)         |  | 3,395        |  |  | 4            |  |  | 1,407        | 
| | Capital Expenditures                |  | 3,455        |  |  | 136          |  |  | 1,553        | 
| |                                     |  |              |  |  |              |  |  |              | 
| | United States                       |  |              |  |  |              |  |  |              | 
| | Property acquisition costs (1)      |  |              |  |  |              |  |  |              | 
| | Proved oil and gas properties       |  | 4            |  |  | 45           |  |  | 40           | 
| | Unproved oil and gas properties     |  | 43           |  |  | 56           |  |  | 211          | 
| | Exploration costs (2)               |  | 73           |  |  | 79           |  |  | 104          | 
| | Development costs
      (3)         |  | 246          |  |  | 1,720        |  |  | 2,568        | 
| | Capital Expenditures                |  | 366          |  |  | 1,900        |  |  | 2,923        | 
| |                                     |  |              |  |  |              |  |  |              | 
| | Total                               |  |              |  |  |              |  |  |              | 
| | Property acquisition costs (1)      |  |              |  |  |              |  |  |              | 
| | Proved oil and gas properties       |  | 60           |  |  | 62           |  |  | 54           | 
| | Unproved oil and gas properties     |  | 43           |  |  | 56           |  |  | 212          | 
| | Exploration costs (2)               |  | 77           |  |  | 194          |  |  | 236          | 
| | Development costs
      (3)         |  | 3,641        |  |  | 1,724        |  |  | 3,975        | 
| | Capital Expenditures                |  | 3,821        |  |  | 2,036        |  |  | 4,476        | 

(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)                 |  | 2014                             |  
| |                                       |  | $                                |  
| | Canada                                |  |                                  |  
| | Oil and gas sales, net of royalties   |  | 5,952                            |  
| | Operating costs and capital taxes     |  | (2,669                           | )
| | Transportation costs                  |  | (443                             | )
| | Depletion, depreciation and accretion |  | (2,448                           | )
| | Income taxes (1)                      |  | -                                |  
| | Results
      of operations           |  | 392                              |  
| |                                       |  |                                  |  
| | United States                         |  |                                  |  
| | Oil and gas sales, net of royalties   |  | 1,609                            |  
| | Operating costs and capital taxes     |  | (987                             | )
| | Transportation costs                  |  | -                                |  
| | Depletion, depreciation and accretion |  | (406                             | )
| | Income taxes (1)                      |  | -                                |  
| | Results of
      operations           |  | 216                              |  
| |                                       |  |                                  |  
| | Total                                 |  |                                  |  
| | Oil and gas sales, net of royalties   |  | 7,561                            |  
| | Operating costs and capital taxes     |  | (3,656                           | )
| | Transportation costs                  |  | (443                             | )
| | Depletion, depreciation and accretion |  | (2,854                           | )
| | Income taxes (1)                      |  | -                                |  
| | Results of
      operations           |  | 608                              |  

(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, 2014 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, 2014 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, 2014 is presented below:

| | As at December 31, 2014                                 |  |         |   |  |          |   |  |          |  
| | ------------------------------------------------------- |  | ------- | - |  | -------- | - |  | -------- | -
| |                                                         |  |         |   |  |          |   |  |          |  
| | (CA$ thousands)                                         |  | Canada  |   |  | USA      |   |  | Total    |  
| |                                                         |  | $       |   |  | $        |   |  | $        |  
| | Future cash from revenues after royalties               |  | 20,367  |   |  | 336,157  |   |  | 356,524  |  
| | Future production,
      abandon and salvage costs      |  | (11,623 | ) |  | (106,667 | ) |  | (118,290 | )
| | Future development costs                                |  | (485    | ) |  | (60,480  | ) |  | (60,965  | )
| | Future income taxes                                     |  | -       |   |  | (20,133  | ) |  | (20,133  | )
| | Future net cash flows                                   |  | 8,259   |   |  | 148,877  |   |  | 157,136  |  
| | Less: 10% annual discount factor                        |  | (956    | ) |  | (108,218 | ) |  | (109,174 | )
| |                                                         |  |         |   |  |          |   |  |          |  
| | Standardized measure of discounted future net cash flow |  | 7,303   |   |  | 40,659   |   |  | 47,962   |  

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   |  

---

|(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, 2014 are presented below:

| | For the Year Ended December 31, 2014                                                  |  |        |   |  |         |   |  |         |  
| | ------------------------------------------------------------------------------------- |  | ------ | - |  | ------- | - |  | ------- | -
| |                                                                                       |  |        |   |  |         |   |  |         |  
| | (CA$ thousands)                                                                       |  | Canada |   |  | USA     |   |  | Total   |  
| |                                                                                       |  | $      |   |  | $       |   |  | $       |  
| | Beginning Balance, January 1, 2014                                                    |  | 3,648  |   |  | 60,919  |   |  | 64,567  |  
| |                                                                                       |  |        |   |  |         |   |  |         |  
| | Sales and transfers of oil and gas produced, net of
      production costs            |  | (2,840 | ) |  | (21     | ) |  | (2,861  | )
| | Net changes in
      sales and transfer prices, net of production costs and royalties |  | 630    |   |  | 55,858  |   |  | 56,488  |  
| | Extensions, discoveries, and improved recovery, less
      estimated costs            |  | -      |   |  | 2,304   |   |  | 2,304   |  
| | Changes in
      estimated future development costs                                   |  | 1,575  |   |  | (38,806 | ) |  | (37,231 | )
| | Sales of reserves in place, less estimated future costs                               |  | -      |   |  | (43,182 | ) |  | (43,182 | )
| | Purchase of
      reserves in place, less estimated future costs                      |  | 3,169  |   |  | -       |   |  | 3,169   |  
| | Revisions of quantity estimates and timing of estimated
      production              |  | 338    |   |  | 3,990   |   |  | 4,328   |  
| | Accretion of
      discount                                                           |  | 365    |   |  | 6,644   |   |  | 7,009   |  
| | Net
      change in income taxes                                                      |  | -      |   |  | (4,076  | ) |  | (4,076  | )
| | Other                                                                                 |  | 418    |   |  | (2,971  | ) |  | (2,553  | )
| |                                                                                       |  |        |   |  |         |   |  |         |  
| | Ending Balance, December 31, 2014                                                     |  | 7,303  |   |  | 40,659  |   |  | 47,962  |  

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   |  

---