---



March 31, 2017

Mr. David Matheson Chief Financial Officer, CFO Dejour
Energy (USA) Corp. 598, 999 Canada Place Vancouver, BC V6C 3E1
Canada

|Subject: | Reserve Estimate and Financial Forecast as to Dejours
      Interests in the Kokopelli Field Area, Garfield County, Colorado.
|-------- | ------------------------------------------------------------------------------------------------------------------------------

Dear David:

As you requested, Gustavson Associates has completed reserves
and economics as to Dejour Energys interests in future oil and gas production
associated with the Kokopelli Field Area located in Garfield County. Reserves
have been estimated based on analysis of analogous well production data.
Estimates and projections have been made as of January 1, 2017. Reserves have
been estimated in accordance with the US Securities and Exchange Commissions
(SEC) definitions and guidelines, and the report was prepared for the purpose of
inclusion as an exhibit in a filing made with the SEC.

In general, Proved Developed Producing (PDP) reserves were
assigned to 11 producing wells (shown in Table 2). Proved Developed
Non-Producing (PDNP) reserves have been assigned to the Federal 14/15-7-21 well.
There are plans to recomplete this well, which is currently producing out of the
Mancos shale, in the Williams Fork member of the Mesaverde formation in July
2017. No Proved Undeveloped (PUD) reserves have been assigned. Gustavson is of
the opinion that no current regulations, and no anticipated changes to
regulations, would inhibit the ability of Dejour to recover the estimated
reserves in the manner projected herein. It is our understanding that the
reserves estimated herein represent all of Dejours US reserves.

The estimated net reserves volumes and associated net cash flow
estimates are summarized in Table 1 below.

5757 Central Ave.     Suite
D     Boulder, Co. 80301 USA    
1-303-443-2209     FAX
1-303-443-3156     http://www.gustavson.com

---

Mr. David Matheson March 31, 2017 Page 2

Table 1 Summary of Net Reserves and Projected Before Tax Cash
Flow

Reserves Category
    Net Gas
      Reserves, MMcf
    Net
      Condensate Reserves (MBO)
    Net NGL
      Reserves (MBO)
    Before Tax
      Net Present Value,thousands of US$ Discounted at0%
    10%
    15%Proved Developed Producing
    730.8
    5.3
    30.7
    $969
    $704
    $623Proved Developed Non-Producing
    186.9
    1.2
    9.5
    $210
    $118
    $92Proved Undeveloped
    -
    -
    -
    $0
    $0
    $0Total Proved
    917.6
    6.5
    40.2
    $1,179
    $822
    $715


The portion of the Companys total reserves represented by the
reserves included in this report is shown below.

Location of Reserves
    
    
    
    
    
    Proportion ofGas
    Condensate
    NGL
    Oil Equivalent
    Oil Equiv.Country
    Area
    (MMCF)
    (MBBL)
    (MBBL)
    (MBOE)
    ReservesUnited States
    Colorado
    917.6
    6.5
    40.2
    199.7
    60%Total Company
    
    
    
    
    330.7
    100%


Gustavson Associates has performed an evaluation of the
reserves associated with both developed and undeveloped locations located in the
Kokopelli Field Project Area, Garfield County, Colorado. Proved Developed
Producing (PDP) Reserves have been assigned to 11 wells (shown in Table 2). The
first four wells began producing in July and August of 2013 and next eight wells
began producing in September 2015. All these wells are completed in the Williams
Fork member of the Mesaverde formation except for one of the new wells, the
Federal 14/15-7-21, which is completed in the Mancos shale.

Proved Developed Non-Producing (PDNP) reserves were assigned to
the Federal 14-15-7-21 well. There are plans to recomplete this well, which is
currently producing out of the Mancos shale, in the Williams Fork member of the
Mesaverde formation in July 2017.

The PDP locations are displayed in Figure 1 and Figure 2. The
property has additional upside which has not been included in this report. Under
current economic conditions, drilling of offset locations in the Williams Fork
or Mancos formation does not generate positive economics; therefore, no PUD
reserves have been assigned.

---

Mr. David Matheson March 31, 2017 Page 3

Table 2 Summary of PDP Wells

Well Name
    Working Interest
    Revenue Interest
    Producing Formation1. Federal 6/7-16-21
    5.5573%
    4.4458%
    Williams Fork2. Federal 6/7-15-21
    7.778%
    6.6624%
    Williams Fork3. Federal 6/7-14-21
    7.778%
    6.6624%
    Williams Fork4. Federal 6/7-13-21
    7.778%
    6.6624%
    Williams Fork5. Federal
      14/15-1-21
    25.00%
    20.00%
    Williams Fork6. Federal
      14/15-2-21
    25.00%
    20.00%
    Williams Fork7. Federal
      14/15-3-21
    25.00%
    20.00%
    Williams Fork8. Federal
      14/15-4-21
    25.00%
    20.00%
    Williams Fork9. Federal
      14/15-5-21
    25.00%
    20.00%
    Williams Fork10. Federal
      14/15-6-21
    25.00%
    20.00%
    Williams Fork11. Federal 14/15-7-21
    25.00%
    20.00%
    Mancos




Figure 1 Map of Dejour Williams Fork Wells

---

Mr. David Matheson March 31, 2017 Page 4



Figure 2 Map of Dejour Mancos PDP Location

Oil and Gas Pricing

In order to determine the flat pricing in accordance with SEC
guidelines, the Dejours revenue statements were analyzed. For all wells, a
differential was calculated based on the price that Dejour was paid versus the
West Texas Intermediate (WTI) and Henry Hub (HH) spot prices averaged for that
given month. These differentials were then applied to the WTI and HH spot prices
for the first day of each month in 2016 in order to estimate prices for Dejours
products on the first day of the month, per SEC guidelines. These values were
averaged and applied in the cash flows presented herein.

For Williams Fork wells, the wellhead gas price was estimated
at 101% of NYMEX Henry Hub gas and the NGL price was found to be a factor of
11.29 times the Henry Hub gas price. The Williams Fork wellhead condensate
prices were determined to be 24% lower than WTI prices. The utilized flat
hydrocarbon pricings for Williams Fork can be found in Table 3.

---

Mr. David Matheson March 31, 2017 Page 5

Table 3 Flat Pricing for Williams Fork Wells

Flat pricing for Effective Date of January 1, 2017Local Price Differentials Included2016 Avg
      WTI
    2016 Avg HH
    Adjusted WTI
    Adjusted HH
    NGL$/B
    $/mcf
    $/B
    $/mcf
    $/B42.600
    2.470
    32.497
    2.486
    27.89


Expenses

Operating costs are expected to be $2,800 per well per month.
This is based on information provided by the Dejour and is consistent with our
experience with similar wells in the area. The drilling and completion costs
reflects economies of scale and contractual advantages expected to be gained
when a large drilling program is executed. Severance tax is deducted at the rate
of 1.04% of revenue. County ad valorem tax was estimated at approximately 3.91%
of revenue after discussion with Garfield County personnel. Conservation tax was
estimated at 0.072% and the annual property tax was estimated as 0.557% of net
revenue. Note that Conservation tax rate and property tax are lumped together
with Severance tax and Ad Valorem tax in the economics evaluation, respectively
For Williams Fork Wells only, an NGL yield of approximately 25 Bbl/mmcf was
applied until July 2017 and then increased to 48 Bbl/MMCF thereafter. Per a new
gas transportation and processing contract between Coachman and a major
midstream company, the gas will be processed at a plant with enhanced cryogenic
refining capabilities, starting July 2017, thus returning the NGL yield to
previous levels. A condensate/gas ratio of 8.5 Bbl/MMCF was applied based on
actual 2016 sales. Contractual gas transportation, gathering, and processing
fees of $0.71/MCF were deducted as operating costs for both Williams Fork and
Mancos wells. Condensate trucking fee of $1.50/Bbl was also applied to the
Williams Fork wells. Abandonment costs of $15,000 per well were estimated. All
costs were held flat.

Dejour expects the Federal 14-15-7-21 well, currently producing
out of the Mancos shale, to be recompleted in the Williams Fork in July 2017.
This operation will cost $500,000 US, which Gustavson finds to be reasonable
based on estimates from the client and experience in the area.

Detailed cash flow projections are shown in Tables 4 and 5
below. Note that the NGL volumes shown in these tables represent total NGL sales
as expected based on the revenue statements provided by the
Client.1

Limiting Conditions and Disclaimers

The accuracy of any reserve report or resource evaluation is a
function of available data and of engineering and geologic interpretation and
judgment. While the evaluation presented herein is believed to be reasonable, it
should be viewed with the understanding that subsequent reservoir performance or
changes in pricing structure, market demand, or other economic parameters may
justify its revision. The assumptions, data, methods, and procedures used are
appropriate for the purpose served by the report. Gustavson has used all methods
and procedures as we considered necessary under the circumstances to prepare the
report.

______________________________
1 In some previous reports, ethane and heavier NGLs
were reported separately. Here they are reported together.

---

Mr. David Matheson March 31, 2017 Page 6

Gustavson Associates, LLC, holds neither direct nor indirect
financial interest in the subject property, the company operating the subject
acreage, or in any other affiliated companies.

All data and work files utilized in the preparation of this
  report are available for examination in our offices. Please contact us if we can
  be of assistance. We appreciate the opportunity to be of service and look
forward to further serving Dejour Energy (USA) Corp.

Sincerely,



---



---



---