March 14, 2014

Mr. David Matheson
Chief Financial Officer, CFO
Dejour Energy (USA) Corp.
1100-808 West Hastings Street
Vancouver, BC
V6C 2X4
Canada

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

Dear David:

As you requested, Gustavson Associates has completed reserves and economics as to Dejour Energy’s interests in future oil and gas production associated with the Kokopelli Field Area located in Garfield County. Reserves have been estimated based on analysis of analogous well production data. Estimates and projections have been made as of January 1, 2014. Reserves have been estimated in accordance with the US Securities and Exchange Commission’s (SEC) definitions and guidelines, and the report was prepared for the purpose of inclusion as an exhibit in a filing made with the SEC. This report was completed on March 5, 2014.

In general, Proved Developed Producing (PDP) reserves have been assigned to the four Kokopelli Federal wells, and Proved Undeveloped (PUD) reserves have been assigned to 139 well locations. Gustavson is of the opinion that no current regulations, and no anticipated changes to regulations, would inhibit the ability of Dejour to recover the estimated reserves in the manner projected herein. It is our understanding that the reserves estimated herein represent all of Dejour’s US reserves.

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

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

Mr. David Matheson
March 14, 2014
Page 2

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

Reserves Category	Net Gas Reserves (MMCF)	Net Light Crude Oil Reserves (MBO)	Net NGL Reserves (MBO)	Net Present Value, thousands of US$ Discounted at
				0%	10%	15%
Proved Developed Producing	367.1	2.5	15.2	$1,450.5	$1,069.6	$956.3
Proved Developed Non-Producing	-	-	-	$0.0	$0.0	$0.0
Proved Undeveloped	86,243.3	587.3	3,580.3	$247,444.2	$83,588.3	$53,379.4
Total Proved	86,610.4	589.8	3,595.6	$248,894.7	$84,657.9	$54,335.7

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

Location of Reserves						Proportion of
		Gas	Light Crude Oil	NGL	Oil Equivalent	Oil Equiv.
Country	Area	(MMCF)	(MBBL)	(MBBL)	(MBOE)	Reserves
United States	Colorado	86,610	590	3,596	18,620	99%
Total Company					18,815	100%

Kokopelli Field Area Assumptions, Garfield County, Colorado

Gustavson Associates has performed an evaluation of the reserves associated with both developed and undeveloped locations located in the Kokopelli Field Project Area, Garfield County, Colorado. Proved Developed Producing (PDP) Reserves have been assigned to the Federal 6/7-16-21, Federal 6/7-14-21, Federal 6/7-15-21, and Federal 6/7-13-21 wells, which began producing in July and August of 2013. Logs for these well were reviewed and found to indicate similar response in the target formations to the response in analogous producing wells. Proved Undeveloped reserves have been assigned to locations within the area delineated by successful wells and logged net pay, comprising of 139 locations. The 139 PUD locations and the PDP locations are displayed in Figure 1.

Dejour entered into a farmout agreement on December 31, 2012 with a private Denver-based drilling fund for a four-well drilling and completion program which included all the aforementioned PDP locations. The drilling of these four locations was completed in mid-2013. Dejour will have a 22.23% working interest (WI) and 17.78% net revenue interest (NRI) before payout of 150% of the capital investments (BPO), and 41.67% WI and 33.34% NRI APO, in the joint venture for three of the wells. For the Federal 6/7 16-21 well, Dejour maintains a 15.88% working interest (WI) and 12.70% net revenue interest (NRI) before payout of 150% of the capital investments (BPO), and 29.77% WI and 23.81% NRI APO, in the joint venture. Payout of 150% of investment is expected to occur in 2023. Dejour’s interests in these four wells can be found in Table 2 below:

Mr. David Matheson
March 14, 2014
Page 3

Table 2 Farmout and Non Farmout Working Interests and Net Revenue Interests

Company	No Farmout		Farmout
			Federal 6/7 13, 14, & 15-21				Federal 6/716-21 well
			BPO		APO		BPO		APO
	WI	NRI	WI	NRI	WI	NRI	WI	NRI	WI	NRI
Dejour	71.43	57.14	22.23	17.78	41.67	33.34	15.88	12.70	29.77	23.81
Brownstone	28.57	22.86	0.00	0.00	0.00	0.00	28.57	22.86	28.57	22.86
Drilling Fund	0.00	0.00	77.77	62.22	58.33	46.66	55.55	44.44	41.66	33.33

Figure 1 Map of Dejour PDP, PUD, and Offset Well Locations

Dejour expects to start the remainder of their drilling program with 54 wells drilled per year, beginning 2014 through 2017. On this schedule, the last PUD location will be drilled in November 2016. The estimated ultimate recovery (EUR) for each location was based on the average performance of wells in the immediate area. Many of these wells were completed in multiple zones, including Williams Fork, Rollins, Cozette, and Corcoran. Figure 1 also displays the locations of Dejour’s PDP wells, and offsetting producing wells. All of the PUD locations are within 1.5 miles and flanked by producing wells.

Mr. David Matheson
March 14, 2014
Page 4

The type curve utilized for the undeveloped locations was the same as that determined in the Dejour 2012 year-end reserve report. While there have been some new wells drilled and completed in the area, their performance on average appears to have been negatively impacted by operator completion practices in 2013, namely, the smaller size of fracture treatments. Dejour has stated their intentions to maintain the larger fracture treatments; therefore, we have stayed with the type curve based on the wells drilled prior to 2013. The average EUR was based on the average composite performance of the total well production from each well. When the economic parameters were considered, this EUR was found to be approximately 1.15 BCF. This average reserve per well is dry gas after a shrinkage of 5% is deducted. The Proved Undeveloped location type curve can be found in Figure 2 below. The estimated net reserves volumes and associated net cash flow estimates are summarized in Table 1 above.

Figure 2 Composite Type Curve, Kokopelli Area

Oil and Gas Pricing

In order to determine the flat pricing in accordance with SEC guidelines, the Dejour’s revenue statements were analyzed. A differential was calculated based on the price that Dejour was paid versus the West Texas Intermediate (WTI) and Henry Hub (HH) spot prices averaged for that given month. These differentials were then applied to the WTI and HH spot prices for the first day of each month in 2013 in order to estimate prices for Dejour’s products on the first day of the month, per SEC guidelines. These values were averaged and applied in the cash flows presented herein.

Mr. David Matheson
March 14, 2014
Page 5

The oil prices were determined to be 11% lower than WTI prices. Gas prices were determined to be 9% higher than Henry Hub prices. NGL’s were found to be sold at 79.5% the price of Dejour’s paid price for oil. The utilized flat hydrocarbon pricing can be found in the table below.

Flat Price Forecast For Effective Date of January 1, 2014
Oil, Gas & NGL Pricing Includes Differentials
	Piceance Oil, $/B	Piceance Gas, $/MCF	Piceance NGL, $/B
Flat Pricing	$86.58	$4.09	$68.84

Expenses

The drilling and completion costs utilized for the first 50 undeveloped locations is $1.65 million per well; the next 50 locations is $1.50 million per well; and the remaining locations have a drilling and completion cost of $1.40 million per well. Operating costs for the PDPs and first 50 undeveloped locations is estimated at $3,759 per well per month; the next 50 locations utilize a monthly operational expense of $3,000 per well; the remaining undeveloped locations have an anticipated monthly operational expense of $2,500 per well. This is based on information provided by Dejour and is consistent with our experience with similar wells in the area. The reduction in costs reflects economies of scale and contractual advantages expected to be gained when a large drilling program is executed. Severance tax and conservation taxes are deducted at the rate of 1.07% of revenue. County ad valorem tax was estimated at approximately 3.35% of revenue after discussion with Garfield County personnel. NGL yield of 39 Bbl/MMCF and condensate/gas ratio of 6.5 Bbl/MMCF were based on actual 2013 sales. Contractual gas transportation, gathering, and processing fees of $0.71/MCF were deducted as operating costs.

Capital and operating costs were held flat. Abandonment costs of $15,000 per well was assumed. Dejour’s interests in the property are reported to be 71.43% working interest with a 20% royalty burden for net revenue interest of 57.14%, with the exception of the four PDP wells included in the farmout as described previously.

Detailed cash flow projections by category are shown in Table 3 and Table 4 below. Note that the NGL volumes shown in these tables represent total NGL sales as expected based on the revenue statements provided by the Client.¹

^{____________________________________________
1} In some previous reports, ethane and heavier NGLs were reported separately. Here they are reported together.

Mr. David Matheson
March 14, 2014
Page 6

Limiting Conditions and Disclaimers

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

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

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

Sincerely,

 

Table 3 Summary Cash Flow Forecast, Proved Developed Producing Reserves

TOTAL PROVED DEVELOPED	DATE	: 03/05/2014
KOKOPELLI FIELD	TIME	: 16:03:42
GARFIELD COUNTY, COLORADO	DBS	: Dejour1-12
TO THE INTERESTS OF DEJOUR ENERGY	SETTINGS	: SETDATA
	SCENARIO	: Dejour

R E S E R V E S   A N D   E C O N O M I C S

EFF DATE: 01/2014
PW DATE: 01/2014

--END--	GROSS OIL	GROSS GAS	GROSS NGL	NET OIL	NET GAS	NET NGL	NET OIL	NET GAS	NET NGL	TOTAL
MO-YEAR	PRODUCTION	PRODUCTION	PRODUCTION	PRODUCTION	PRODUCTION	PRODUCTION	REVENUE	REVENUE	REVENUE	REVENUE
-------	---MBBLS---	----MMCF---	---MBBLS---	---MBBLS--	----MMCF--	---MBBLS--	---M$---	---M$---	---M$---	----M$---
12-2014	3.091	478.730	18.845	0.508	74.568	3.096	43.966	304.982	213.103	562.050
12-2015	1.757	272.050	10.709	0.288	42.320	1.757	24.952	173.090	120.945	318.987
12-2016	1.297	200.848	7.906	0.213	31.235	1.297	18.416	127.749	89.263	235.429
12-2017	1.050	162.634	6.402	0.172	25.288	1.050	14.910	103.429	72.270	190.609
12-2018	0.893	138.266	5.443	0.146	21.498	0.892	12.675	87.925	61.436	162.036
12-2019	0.782	121.165	4.770	0.128	18.838	0.782	11.107	77.046	53.835	141.988
12-2020	0.700	108.402	4.267	0.115	16.853	0.700	9.936	68.928	48.162	127.026
12-2021	0.636	98.456	3.876	0.104	15.306	0.635	9.024	62.602	43.742	115.368
12-2022	0.584	90.453	3.561	0.096	14.062	0.584	8.291	57.512	40.186	105.989
12-2023	0.541	83.854	3.301	0.089	13.035	0.541	7.686	53.315	37.253	98.254
12-2024	0.506	78.304	3.082	0.083	12.173	0.505	7.177	49.786	34.787	91.750
12-2025	0.475	73.561	2.896	0.078	11.435	0.475	6.742	46.770	32.680	86.192
12-2026	0.448	69.455	2.734	0.074	10.797	0.448	6.366	44.159	30.855	81.379
12-2027	0.425	65.853	2.592	0.070	10.237	0.425	6.036	41.868	29.255	77.159
12-2028	0.404	62.556	2.462	0.066	9.724	0.404	5.733	39.772	27.790	73.296
S TOT	13.590	2104.586	82.845	2.229	327.367	13.590	193.017	1338.932	935.562	2467.512
AFTER	1.694	262.365	10.328	0.271	39.753	1.650	23.439	162.591	113.609	299.639
TOTAL	15.284	2366.952	93.172	2.500	367.121	15.241	216.456	1501.524	1049.171	2767.151

--END--	NET OIL	NET GAS	NET NGL	SEVERANCE	AD VALOREM	NET OPER	OPERATING	EQUITY	UNDISC NET	DISC NET
MO-YEAR	PRICE	PRICE	PRICE	TAXES	TAXES	EXPENSES	CASH FLOW	INVESTMENT	CASH FLOW	CASH FLOW
-------	---M$---	---M$---	---M$---	-----M$----	-----M$----	----M$----	----M$----	----M$----	-----M$----	-----M$----
12-2014	86.58	4.09	68.84	3.734	18.704	104.167	435.446	0.000	435.446	415.181
12-2015	86.58	4.09	68.84	2.119	10.615	76.307	229.946	0.000	229.946	199.313
12-2016	86.58	4.09	68.84	1.564	7.834	67.244	158.787	0.000	158.787	125.122
12-2017	86.58	4.09	68.84	1.266	6.343	62.757	120.243	0.000	120.243	86.136
12-2018	86.58	4.09	68.84	1.076	5.392	60.199	95.369	0.000	95.369	62.107
12-2019	86.58	4.09	68.84	0.943	4.725	58.661	77.659	0.000	77.659	45.976
12-2020	86.58	4.09	68.84	0.844	4.227	57.738	64.218	0.000	64.218	34.562
12-2021	86.58	4.09	68.84	0.766	3.839	57.221	53.542	0.000	53.542	26.197
12-2022	86.58	4.09	68.84	0.704	3.527	56.989	44.769	0.000	44.769	19.913
12-2023	86.58	4.09	68.84	0.653	3.270	56.968	37.363	0.000	37.363	15.108
12-2024	86.58	4.09	68.84	0.610	3.053	57.111	30.977	0.000	30.977	11.387
12-2025	86.58	4.09	68.84	0.573	2.868	57.382	25.369	0.000	25.369	8.478
12-2026	86.58	4.09	68.84	0.541	2.708	56.816	21.315	0.000	21.315	6.476
12-2027	86.58	4.09	68.84	0.513	2.568	56.319	17.760	0.000	17.760	4.905
12-2028	86.58	4.09	68.84	0.487	2.439	55.864	14.506	4.229	10.277	2.622
S TOT	86.58	4.09	68.84	16.392	82.113	941.741	1427.267	4.229	1423.038	1063.483
AFTER	86.58	4.09	68.84	1.991	9.971	248.741	38.936	11.478	27.458	6.137
TOTAL	86.58	4.09	68.84	18.382	92.084	1190.481	1466.203	15.707	1450.496	1069.620

	OIL	GAS			P.W. %	P.W., M$
	---------	---------			------	--------
GROSS WELLS	0.0	4.0	LIFE, YRS.	22.25	5.00	1225.246
GROSS ULT., MB & MMF	15.284	2790.128	DISCOUNT %	10.00	10.00	1069.620
GROSS CUM., MB & MMF	0.000	423.177	UNDISCOUNTED PAYOUT, YRS.	0.00	15.00	956.298
GROSS RES., MB & MMF	15.284	2366.951	DISCOUNTED PAYOUT, YRS.	0.00	20.00	870.137
NET RES., MB & MMF	2.500	367.121	UNDISCOUNTED NET/INVEST.	93.35	25.00	802.291
NET REVENUE, M$	216.456	1501.524	DISCOUNTED NET/INVEST.	418.07	30.00	747.328
INITIAL PRICE, $	86.580	4.090	RATE-OF-RETURN, PCT.	100.00	40.00	663.265
INITIAL N.I., PCT.	16.427	16.427	INITIAL W.I., PCT.	20.564	60.00	553.783
					80.00	484.132
					100.00	435.050

Table 4 Summary Cash Flow Forecast, Proved Undeveloped Reserves

TOTAL PROVED UNDEVELOPED	DATE	: 03/05/2014
KOKOPELLI FIELD	TIME	: 16:04:03
GARFIELD COUNTY, COLORADO	DBS	: Dejour1-12
TO THE INTERESTS OF DEJOUR ENERGY	SETTINGS	: SETDATA
	SCENARIO	: Dejour

R E S E R V E S   A N D   E C O N O M I C S

EFF DATE: 01/2014
PW DATE: 01/2014

--END--	GROSS OIL	GROSS GAS	GROSS NGL	NET OIL	NET GAS	NET NGL	NET OIL	NET GAS	NET NGL	TOTAL
MO-YEAR	PRODUCTION	PRODUCTION	PRODUCTION	PRODUCTION	PRODUCTION	PRODUCTION	REVENUE	REVENUE	REVENUE	REVENUE
-------	---MBBLS---	----MMCF---	---MBBLS---	---MBBLS---	----MMCF--	---MBBLS--	---M$---	---M$---	---M$---	----M$---
12-2014	38.329	5935.913	233.660	21.901	3216.090	133.513	1896.223	13153.798	9191.061	24241.100
12-2015	91.965	14242.327	560.633	52.549	7716.526	320.345	4549.700	31560.566	22052.543	58162.863
12-2016	114.939	17800.160	700.682	65.676	9644.151	400.370	5686.247	39444.645	27561.430	72692.297
12-2017	78.662	12182.042	479.531	44.947	6600.252	274.004	3891.543	26995.006	18862.451	49749.000
12-2018	56.993	8826.265	347.436	32.566	4782.093	198.525	2819.544	19558.771	13666.435	36044.746
12-2019	46.206	7155.794	281.679	26.402	3877.023	160.951	2285.913	15857.042	11079.906	29222.842
12-2020	39.406	6102.697	240.226	22.517	3306.453	137.265	1949.505	13523.406	9449.306	24922.217
12-2021	34.636	5363.999	211.147	19.791	2906.224	120.650	1713.525	11886.456	8305.516	21905.492
12-2022	31.068	4811.355	189.393	17.752	2606.805	108.219	1536.984	10661.817	7449.817	19648.643
12-2023	28.279	4379.393	172.390	16.158	2372.763	98.503	1398.996	9704.614	6780.972	17884.580
12-2024	26.028	4030.797	158.667	14.872	2183.895	90.663	1287.635	8932.122	6241.211	16460.971
12-2025	24.166	3742.518	147.320	13.809	2027.702	84.178	1195.544	8293.302	5794.843	15283.692
12-2026	22.597	3499.462	137.752	12.912	1896.014	78.712	1117.901	7754.699	5418.498	14291.104
12-2027	21.253	3291.287	129.558	12.144	1783.228	74.029	1051.401	7293.401	5096.180	13440.983
12-2028	20.120	3115.849	122.652	11.496	1688.173	70.083	995.355	6904.632	4824.523	12724.509
S TOT	674.647	104479.859	4112.725	385.493	56607.391	2350.010	33376.012	231524.281	161774.688	426675.000
AFTER	353.201	54698.793	2153.152	201.819	29635.916	1230.311	17473.492	121210.906	84694.617	223378.984
TOTAL	1027.848	159178.656	6265.877	587.312	86243.312	3580.321	50849.504	352735.188	246469.312	650054.000

--END--	NET OIL	NET GAS	NET NGL	SEVERANCE	AD VALOREM	NET OPER	OPERATING	EQUITY	UNDISC NET	DISC NET
MO-YEAR	PRICE	PRICE	PRICE	TAXES	TAXES	EXPENSES	CASH FLOW	INVESTMENT	CASH FLOW	CASH FLOW
-------	---M$---	---M$---	---M$---	-----M$----	-----M$----	----M$----	----M$----	----M$----	-----M$----	-----M$----
12-2014	86.58	4.09	68.84	161.035	806.682	3362.669	19910.703	56756.844	-36846.148	-35410.023
12-2015	86.58	4.09	68.84	386.380	1935.510	8608.683	47232.273	56182.695	-8950.458	-7973.347
12-2016	86.58	4.09	68.84	482.900	2419.014	11520.249	58270.145	32898.117	25372.057	19405.477
12-2017	86.58	4.09	68.84	330.486	1655.521	9188.992	38573.988	0.000	38573.988	27632.482
12-2018	86.58	4.09	68.84	239.448	1199.477	7641.883	26963.900	0.000	26963.900	17559.641
12-2019	86.58	4.09	68.84	194.129	972.462	6906.530	21149.725	0.000	21149.725	12521.168
12-2020	86.58	4.09	68.84	165.560	829.348	6469.428	17457.881	0.000	17457.881	9395.918
12-2021	86.58	4.09	68.84	145.520	728.959	6184.893	14846.141	0.000	14846.141	7263.873
12-2022	86.58	4.09	68.84	130.527	653.856	5991.237	12872.992	0.000	12872.992	5725.878
12-2023	86.58	4.09	68.84	118.809	595.154	5857.071	11313.544	0.000	11313.544	4574.756
12-2024	86.58	4.09	68.84	109.351	547.779	5764.457	10039.385	0.000	10039.385	3690.489
12-2025	86.58	4.09	68.84	101.531	508.602	5702.350	8971.216	0.000	8971.216	2998.025
12-2026	86.58	4.09	68.84	94.937	475.571	5585.466	8135.127	0.000	8135.127	2471.471
12-2027	86.58	4.09	68.84	89.289	447.281	5485.363	7419.042	0.000	7419.042	2049.022
12-2028	86.58	4.09	68.84	84.530	423.440	5400.999	6815.539	0.000	6815.539	1711.221
S TOT	86.58	4.09	68.84	2834.433	14198.656	99670.266	309971.656	145837.641	164133.922	73616.055
AFTER	86.58	4.09	68.84	1483.923	7433.485	129262.508	85199.086	1888.811	83310.281	9972.262
TOTAL	86.58	4.09	68.84	4318.356	21632.141	228932.766	395170.750	147726.469	247444.188	83588.320

	OIL	GAS			P.W. %	P.W., M$
	---------	---------			------	--------
GROSS WELLS	0.0	139.0	LIFE, YRS.	42.83	5.00	136375.953
GROSS ULT., MB & MMF	1027.848	159178.656	DISCOUNT %	10.00	10.00	83588.328
GROSS CUM., MB & MMF	0.000	0.000	UNDISCOUNTED PAYOUT, YRS.	3.53	15.00	53379.430
GROSS RES., MB & MMF	1027.848	159178.656	DISCOUNTED PAYOUT, YRS.	3.87	20.00	33964.258
NET RES., MB & MMF	587.313	86243.352	UNDISCOUNTED NET/INVEST.	2.68	25.00	20544.215
NET REVENUE, M$	50849.547	352735.250	DISCOUNTED NET/INVEST.	1.64	30.00	10813.058
INITIAL PRICE, $	86.580	4.090	RATE-OF-RETURN, PCT.	38.14	40.00	-2086.993
INITIAL N.I., PCT.	57.140	57.140	INITIAL W.I., PCT.	71.430	60.00	-15022.593
					80.00	-20700.264
					100.00	-23389.502