EX-4.21



 Exhibit 4.21 
 DEJOUR ENERGY (USA) CORP. 
 March 6, 2013 

Randall Kenworthy 
 Bakken Drilling Fund III
Manager LLC 
 5251 DTC Parkway, Suite 200 
 Denver, CO 80111 
  

	Re:	Amendment to Operating Agreement dated December 31, 2012 by and between Dejour Energy (USA) Corp. and Bakken Drilling Fund III, L.P., Garfield County, Colorado


 Dear Mr. Kenworthy: 
 Dejour Energy (USA) Corp. (“Dejour”) and Bakken Drilling Fund III, L.P. (“Bakken”) are parties to that certain Operating Agreement dated December 31, 2012 (the “JOA”).
It has come to our attention that certain provisions of the JOA and the exhibits thereto do not reflect the parties’ intentions and for purposes of clarity, the parties hereby agree to amend the JOA as follows: 

ARTICLE XVI 
 1. Article XVI.B(i)
of the JOA is amended by deleting the first sentence in its entirety and replacing it with the following: 
 “Non-Operator
will contribute initial capital in the amount of $6,500,000 (the “Drilling Funds”), to fund Operator’s Working Interest share of the cost to (i) drill and complete up to three new wells of which the Operator holds a 100% working
interest (or such other number of wells the parties may reasonably determine in order to fully expend the Drilling Fund), within the Contract Area at a location to be determined by Operator and (ii) complete the Existing Well of which the
Operator’s Working Interest share is 5/7ths (collectively, the “Tranche 1 Drilling Program”).” 
 2. Article XVI.B(ii) of
the JOA is amended by deleting the second paragraph that begins “75% of Non-Operator’s” in its entirety and replacing it as follows: 
 “75% of Non-Operator’s actual capital investment in the Tranche 1 Wells less 75% of the Net Operating Profits (defined below) received by Non-Operator for sales of production during the first 36
calendar months for such Tranche 1 Wells plus a “top up” amount. The “top up” amount shall be calculated to return 75% of the capital invested by Non-Operator and to create a total BFIT rate of return of 8% per annum
compounded annually but applied on a monthly basis on the then- outstanding capital invested by Non-Operator. As used herein, “Net Operating Profits” means Non-Operator’s working interest share of gross sales less royalties and
Non-Operator’s proportionate share of the Joint Operations (as defined in 







 
Exhibit C to this Agreement). Notwithstanding the foregoing, should Non- Operator choose to go non-consent as permitted under this Agreement on any Well remedial work that is determined to be
required by Operator, then 100% of all associated penalties not already recovered by Operator will be deducted from any amounts owed to Non-Operator under the put option. The return calculation shall be based on monthly cash flows. 

As an example the calculation of the value of the put option is as follows: 

 

																							
	75% of
Capital
Invested	 	  	75% of Net
Operating Profits
Year
1	 	  	75% of Net
Operating Profits
Year
2	 	  	75% of Net
Operating Profits
Year 3	 	  	Interest
(Estimated)	 	  	Put
Purchase
Price
(Top Up)
(Estimated)	 
	$	4.875 MM	  	  	< $	2.0 MM >	  	  	< $	1.2 MM >	  	  	< $	0.8 MM >	  	  	$	0.650MM	  	  	$	1.525MM	  

 Where the “top up” of $1.525 MM consists of $0.875 MM of unrecovered capital investment plus
$0.650 MM which represents 8% per annum compounded annually and applied on a monthly basis to the outstanding balance of unrecovered capital. An example of the month to month calculation is attached hereto as Exhibit “I”. 

3. The first sentence of Article XVI.C(i) is amended by deleting “additional” in the fourth line thereof and replacing it with “amount up
to” before “$5,000,000”. 
 4. The first sentence of Article XVI.C(ii) is amended by deleting “additional” in the
fourth line thereof and replacing it with “amount up to” before “$5,000,000”. 
 5. Article XVI.C. is amended by adding a
new subsection (v) as follows: 
 “(v) Other Operations. Nothing herein shall prevent or restrict the Operator from
developing, farming out. mortgaging or creating other partnering arrangements in the development of its Leases, provided that all obligations under this Agreement are satisfied or may be satisfied with future drilling tranches.” 

6. The first sentence of Article XVI.F. is amended by adding after “increased by’ in the fourth line thereof, “a transfer of rights from
Non-Operator of before “an amount equal to”. 
 7. Article XVI.G. is amended by deleting the third sentence thereof in its entirety
and replacing it as follows: 
 “The initial Facility Throughput Fee shall be $0.20 per MCF (Twenty cents per Thousand Cubic
Feet of Gas).” 
 8. Exhibit “A” to the JOA is deleted in its entirety and replaced with the Exhibit “A” attached
hereto. 

  
 2 








 9. Exhibit “G” to the JOA is amended by deleting Section 5.1 in its entirety and replacing
it as follows: 
 “5.1 Capital Contributions. 
 The respective capital contributions of each Party to the Partnership shall be (a) in the case of the Non-Operator capital contributed per the terms of the JOA and (b) in the case of the
Operator, capital and Existing Wells or other field installations as per the terms of the JOA.” 
 10. The JOA is amended by adding Exhibit
“I” attached hereto. 
 11. This letter may be executed in any number of counterparts, each of which when so executed shall constitute
in the aggregate but one and the same document. Copies or facsimiles of signatures to this letter have the same effect as if the signatures were placed on the originals and shall be deemed to be fully executed by each signatory. 

12. All other provisions of the JOA remain unchanged and in full force and effect. 

If you are in agreement with the above corrections to the JOA, please so indicate by signing in the space provided on the next page and
returning an executed, notarized copy to Dejour. 
  

	
	Very Truly Yours,
	
	DEJOUR ENERGY (USA) CORP.
	
	




	Harrison F. Blacker, President


  

			
	STATE OF COLORADO	 	§
		 	§
	CITY AND COUNTY OF DENVER	 	§

 This instrument was acknowledged before me this 6th day of March, 2013 by Harrison F. Blacker, as President of Dejour
Energy (USA) Corp. 
 WITNESS my hand and official seal. 

 

	
	




	Notary Public, State of Colorado


  

			
	My Commission Expires: June 8, 2015	  	
		  	






  
 3 








 AGREED TO AND ACCEPTED this
11th day of March, 2013. 

 

	
	BAKKEN DRILLING FUND III, L.P.
	
	By: Bakken Drilling Fund III Manager LLC,
	Its Managing General Partner
	
	




	By: Randall Kenworthy, Manager

  

			
	STATE OF Colorado	 	§
		 	§
	CITY AND COUNTY OF Arapahoe	 	§

 This instrument was acknowledged before me this 11th day of March, 2013 by Randall Kenworthy, as Manager of Bakken
Drilling Fund III Manager LLC, the Managing General Partner of Bakken Drilling Fund III, L.P. 
 WITNESS my hand and official
seal. 
  

					
	



	 		 	




	 		 	Notary Public State of Colorado
	 		 	  
 My Commission Expires: 10/11/15



  
 4 








 EXHIBIT “A” 

Attached to and made a part of that certain Operating Agreement dated December 31, 2012, by and between Dejour Energy (USA) Corp.,
as Operator, and Bakken Drilling Fund III LP, as Non-Operator, collectively referred to herein as “Parties” or individually as “Party’’. 
  

	(1)	Lands Subject to this Agreement (Contract Area): 

 Township 6 South. Range 91 West of the 6th P.M. 
 Section 13: W 1/2SW 
1/4; 

Section 14:
S 1/2; 
 Section 15: NW 1/4NE 1/4,
SW 1/4NE 1/4,
NE 1/4NW 1/4,
W 1/2NW 1/4,
SE 1/4NW 1/4,
N 1/2SW 1/4,
SE 1/4; 
 Section 21: E 1/2NE 
1/4, SE 1/4SW 1/4,
SW 1/4SE 1/4; 

Section 22:
SW 1/4NW 1/4,
W 1/2SW 1/4,
SE 1/4SW 1/4; 

Section 23:
NE 1/4, N 1/2NW 
1/4; 

Section 24:
NE 1/4NE 1/4,
W 1/2NE 1/4,
NW 1/4, N 1/2SE 
1/4; 

Section 25:
SE 1/4SE 1/4,
SW 1/4SW 1/4; 

Section 26:
S 1/2 
 Garfield County, CO 

 

	(2)	Restrictions as to Depths, Formations or Substances: 

 None 
  

	(3)	Percentages of Working Interest of the Parties: 

 The Percentage Interest in the jointly drilled wells will be calculated as follows: (i) for Operator, the actual capital invested in the Existing Well, which is $1,147,779.43, plus any additional
capital contributed by Operator to complete the Tranche 1 Drilling Program, and (ii) for Non-Operator, the actual capital contribution by Non-Operator for the Tranche 1 Drilling Program. The Parties. anticipate updating Exhibit “A” to
reflect the Percentage Interest of the Parties based on actual investments made by each Party in the Drilling Program. 
 Parties to
Agreement: 
 Dejour Energy (USA) Corp. 
 Attn: Land Department 
 1401 17th Street, Suite 850 

Denver, CO 80202 

Ph (303) 296-3535; FAX (303) 296-3888 
 Bakken Drilling Fund III LP 
 Attn: Don Scott [Address] 

[Address] 
 Ph
(        )         -        ; FAX (        )
        -         
 Oil and Gas Lease(s) Subject to this
Agreement: 
  

	1.	Serial Number: COC-066370 


Effective Date: 12/01/2002 
 Lessor: USA Federal DOI-BLM 
 Land Description: 

Township 6 South, Range 91 West of the 6th P.M. 
 Section 21: E 1/2NE 
1/4, SE 1/4SW 1/4,
SW 1/4SE 1/4; 

Section 22:
SW 1/4NW 1/4,
W 1/2SW 1/4,
SE 1/4SW 1/4; 

Section 25:
SW 1/4SW 1/4; 
 Section 26: S 1/2 
 Containing 680.00 acres, more or less, in 
 Garfield County, CO 


  

	2.	Serial Number: COC-065531 


Effective Date: 12/01/2001 
 Lessor: USA Federal DOI-BLM 
 Land Description: 

Township 6 South, Range 91 West of the 6th P.M. 
 Section 13: W 1/2SW 
1/4; 

Section 14:
S 1/2; 
 Section 15: NW 1/4NE 1/4,
SW 1/4NE 1/4,
NE 1/4NW 1/4,
W 1/2NW 1/4,
SE 1/4NW 1/4,
N 1/2SW 1/4,
SE 1/4; 
 Section 23: NE 1/4,
N 1/2NW 1/4; 
 Section 24: NE 1/4NE 
1/4, W 1/2NE 1/4,
NW 1/4, N 1/2SE 
1/4; 

Section 25:
SE 1/4SE 1/4 
 Containing 1,520.00 acres, more or less, in 
 Garfield County, CO 

  
 5 








 EXHIBIT “I” 

Attached to and made a part of that certain Operating Agreement dated 

December 31, 2012, by and between Dejour Energy (USA) Corp., as Operator, and Bakken Drilling Fund III LP, as Non-Operator,

 collectively referred to herein as “Parties” or individually as “Party”. 

 

							
	 75% of Capital (in MM)
 Interest ratio
	  	 
  
	4.00
 5%
	  
   
	  	

  

																																																																									
	 March
	  	1	 	  	2	 	  	3	 	  	4	 	  	5	 	  	6	 	  	7	 	  	8	 	  	9	 	  	10	 	  	11	 	  	12	 	  	13	 	  	14	 	  	15	 	  	16	 	  	17	 	  	18	 
																			
	 Monthly Operating Income-BDFM
	  	 	0.17	  	  	 	0.17	  	  	 	0.17	  	  	 	0.17	  	  	 	0.17	  	  	 	0.17	  	  	 	0.17	  	  	 	0.17	  	  	 	0.17	  	  	 	0.17	  	  	 	0.17	  	  	 	0.17	  	  	 	0.10	  	  	 	0.10	  	  	 	0.10	  	  	 	0.10	  	  	 	0.10	  	  	 	0.10	  
		  				  				  				  				  				  				  				  				  				  				  				  	  
	  
	 	  				  				  				  				  				  			
	 Subtotal
	  				  				  				  				  				  				  				  				  				  				  				  	 	2.00	  	  				  				  				  				  				  			
		  				  				  				  				  				  				  				  				  				  				  				  	  
	  
	 	  				  				  				  				  				  			
																			
	 Unpaid Capital-BDFM
	  	 	4.71	  	  	 	4.54	  	  	 	4.36	  	  	 	4.21	  	  	 	4.04	  	  	 	3.68	  	  	 	3.71	  	  	 	3.54	  	  	 	3.38	  	  	 	3.21	  	  	 	3.04	  	  	 	2.20	  	  	 	2.70	  	  	 	2.50	  	  	 	2.50	  	  	 	2.48	  	  	 	2.38	  	  	 	2.20	  
	 Interest
	  				  				  				  				  				  				  				  				  				  				  				  				  				  				  	 	0.30	  	  	 	0.30	  	  	 	0.30	  	  	 	0.30	  
	 Monthly Interest
	  	 	0.03	  	  	 	0.03	  	  	 	0.03	  	  	 	0.03	  	  	 	0.03	  	  	 	0.03	  	  	 	0.02	  	  	 	0.02	  	  	 	0.02	  	  	 	0.02	  	  	 	0.02	  	  	 	0.02	  	  	 	0.02	  	  	 	0.02	  	  	 	0.02	  	  	 	0.02	  	  	 	0.02	  	  	 	0.02	  
		  				  				  				  				  				  				  				  				  				  				  				  	  
	  
	 	  				  				  				  				  				  			
		  				  				  				  				  				  				  				  				  				  				  				  	 	0.30	  	  				  				  				  				  				  			
		  				  				  				  				  				  				  				  				  				  				  				  	  
	  
	 	  				  				  				  				  				  			
	 Total Interest
	  	 	0.55	  	  				  				  				  				  				  				  				  				  				  				  				  				  				  				  				  				  			
	 Put Purchase price
	  	 	1.52	  	  				  				  				  				  				  				  				  				  				  				  				  				  				  				  				  				  			

  

																																																																									
	 March
	  	19	 	  	20	 	  	21	 	  	22	 	  	23	 	  	24	 	  	25	 	  	26	 	  	27	 	  	28	 	  	29	 	  	30	 	  	31	 	  	32	 	  	33	 	  	34	 	  	35	 	  	36	 
																			
	 Monthly Operating Income-BDFM
	  	 	0.10	  	  	 	0.10	  	  	 	0.10	  	  	 	0.10	  	  	 	0.10	  	  	 	0.10	  	  	 	0.70	  	  	 	0.70	  	  	 	0.70	  	  	 	0.70	  	  	 	0.70	  	  	 	0.70	  	  	 	0.70	  	  	 	0.70	  	  	 	0.70	  	  	 	0.70	  	  	 	0.70	  	  	 	0.70	  
		  				  				  				  				  				  	  
	  
	 	  				  				  				  				  				  				  				  				  				  				  				  	  
	  
	 
	 Subtotal
	  				  				  				  				  				  	 	1.20	  	  				  				  				  				  				  				  				  				  				  				  				  	 	0.80	  
		  				  				  				  				  				  	  
	  
	 	  				  				  				  				  				  				  				  				  				  				  				  	  
	  
	 
																			
	 Unpaid Capital-BDFM
	  	 	2.18	  	  	 	2.04	  	  	 	1.04	  	  	 	1.00	  	  	 	1.78	  	  	 	1.80	  	  	 	1.61	  	  	 	1.51	  	  	 	1.48	  	  	 	1.41	  	  	 	1.34	  	  	 	1.28	  	  	 	1.21	  	  	 	1.14	  	  	 	1.08	  	  	 	1.01	  	  	 	0.94	  	  	 	0.07	  
	 Interest
	  	 	0.30	  	  	 	0.30	  	  	 	0.30	  	  	 	0.30	  	  	 	0.30	  	  	 	0.30	  	  	 	0.51	  	  	 	0.51	  	  	 	0.51	  	  	 	0.51	  	  	 	0.51	  	  	 	0.51	  	  	 	0.51	  	  	 	0.51	  	  	 	0.51	  	  	 	0.51	  	  	 	0.51	  	  	 	0.61	  
	 Monthly Interest
	  	 	0.02	  	  	 	0.02	  	  	 	0.02	  	  	 	0.01	  	  	 	0.01	  	  	 	0.01	  	  	 	0.01	  	  	 	0.01	  	  	 	0.01	  	  	 	0.01	  	  	 	0.01	  	  	 	0.01	  	  	 	0.01	  	  	 	0.01	  	  	 	0.01	  	  	 	0.01	  	  	 	0.01	  	  	 	0.01	  
		  				  				  				  				  				  	  
	  
	 	  				  				  				  				  				  				  				  				  				  				  				  	  
	  
	 
		  				  				  				  				  				  	 	0.20	  	  				  				  				  				  				  				  				  				  				  				  				  	 	0.14	  
		  				  				  				  				  				  	  
	  
	 	  				  				  				  				  				  				  				  				  				  				  				  	  
	  
	 
	 Total Interest
	  				  				  				  				  				  				  				  				  				  				  				  				  				  				  				  				  				  			
	 Put Purchase price
	  				  				  				  				  				  				  				  				  				  				  				  				  				  				  				  				  				  			








 A.A.P.L. FORM 610 - 1989 

MODEL FORM OPERATING AGREEMENT 
 OPERATING AGREEMENT 
 DATED 

 

											
		 	
    December 31    
	 	,	 	     2012    
	 	,	  	
		 		 		 	year	 		  	

  

			
	OPERATOR	  	 Dejour Energy (USA),
Corp.


  

			
	CONTRACT AREA	  	 See Exhibit A

	
	  

	
	  

	
	  

	
	  


 COUNTY OR PARISH OF Garfield, STATE OF Colorado 

 

			
		  	 COPYRIGHT 1989 – ALL RIGHTS RESERVED
 AMERICAN ASSOCIATION OF PETROLEUM
 LANDMEN, 4100 FOSSIL CREEK BLVD.

FORT WORTH, TEXAS, 76137, APPROVED FORM.
  

A.A.P.L. NO. 610 – 1989









 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

TABLE OF CONTENTS 
  

							
	 Article
	 	 Title
	  	Page	 
	I.	 	DEFINITIONS	  	 	1	  
	II.	 	EXHIBITS	  	 	1	  
	III.	 	INTERESTS OF PARTIES	  	 	2	  
		 	 A.     OIL AND GAS INTERESTS:
	  	 	2	  
		 	 B.     INTERESTS OF PARTIES IN COSTS AND PRODUCTION:
	  	 	2	  
		 	 C.     SUBSEQUENTLY CREATED INTERESTS:
	  	 	2	  
	IV.	 	TITLES	  	 	2	  
		 	 A.     TITLE EXAMINATION:
	  	 	2	  
		 	 B.     LOSS OR FAILURE OF TITLE:
	  	 	3	  
		 	 1.      Failure of Title
	  	 	3	  
		 	 2.      Loss by Non-Payment or Erroneous Payment of Amount Due
	  	 	3	  
		 	 3.      Other Losses
	  	 	3	  
		 	 4.      Curing Title
	  	 	3	  
	V.	 	OPERATOR	  	 	4	  
		 	 A.     DESIGNATION AND RESPONSIBILITIES OF OPERATOR:
	  	 	4	  
		 	 B.     RESIGNATION OR REMOVAL OF OPERATOR AND SELECTION OF SUCCESSOR:
	  	 	4	  
		 	 1.      Resignation or Removal of Operator
	  	 	4	  
		 	 2.      Selection of Successor Operator
	  	 	4	  
		 	 3.      Effect of Bankruptcy
	  	 	4	  
		 	 C.     EMPLOYEES AND CONTRACTORS:
	  	 	4	  
		 	 D.     RIGHTS AND DUTIES OF OPERATOR:
	  	 	4	  
		 	 1.      Competitive Rates and Use of Affiliates
	  	 	4	  
		 	 2.      Discharge of Joint Account Obligations
	  	 	4	  
		 	 3.      Protection from Liens
	  	 	4	  
		 	 4.      Custody of Funds
	  	 	5	  
		 	 5.      Access to Contract Area and Records
	  	 	5	  
		 	 6.      Filing and Furnishing Governmental Reports
	  	 	5	  
		 	 7.      Drilling and Testing Operations
	  	 	5	  
		 	 8.      Cost Estimates
	  	 	5	  
		 	 9.      Insurance
	  	 	5	  
	VI.	 	DRILLING AND DEVELOPMENT	  	 	5	  
		 	 A.     INITIAL WELL:
	  	 	5	  
		 	 B.     SUBSEQUENT OPERATIONS:
	  	 	5	  
		 	 1.      Proposed Operations
	  	 	5	  
		 	 2.      Operations by Less Than All Parties
	  	 	6	  
		 	 3.      Stand-By Costs
	  	 	7	  
		 	 4.      Deepening
	  	 	8	  
		 	 5.      Sidetracking
	  	 	8	  
		 	 6.      Order of Preference of Operations
	  	 	8	  
		 	 7.      Conformity to Spacing Pattern
	  	 	9	  
		 	 8.      Paying Wells
	  	 	9	  
		 	 C.     COMPLETION OF WELLS; REWORKING AND PLUGGING BACK:
	  	 	9	  
		 	 1.      Completion
	  	 	9	  
		 	 2.      Rework, Recomplete or Plug Back
	  	 	9	  
		 	 D.     OTHER OPERATIONS:
	  	 	9	  
		 	 E.     ABANDONMENT OF WELLS:
	  	 	9	  
		 	 1.      Abandonment of Dry Holes
	  	 	9	  
		 	 2.      Abandonment of Wells That Have Produced
	  	 	10	  
		 	 3.      Abandonment of Non-Consent Operations
	  	 	10	  
		 	 F.      TERMINATION OF OPERATIONS:
	  	 	10	  
		 	 G.     TAKING PRODUCTION IN KIND:
	  	 	10	  
		 	 (Option 1) Gas Balancing Agreement
	  	 	10	  
		 	 (Option 2) No Gas Balancing Agreement
	  	 	11	  
	VII.	 	EXPENDITURES AND LIABILITY OF PARTIES	  	 	11	  
		 	 A.     LIABILITY OF PARTIES:
	  	 	11	  
		 	 B.     LIENS AND SECURITY INTERESTS:
	  	 	12	  
		 	 C.     ADVANCES:
	  	 	12	  
		 	 D.     DEFAULTS AND REMEDIES:
	  	 	12	  
		 	 1.      Suspension of Rights
	  	 	13	  
		 	 2.      Suit for Damages
	  	 	13	  
		 	 3.      Deemed Non-Consent
	  	 	13	  
		 	 4.      Advance Payment
	  	 	13	  
		 	 5.      Costs and Attorney’s Fees
	  	 	13	  
		 	 E.     RENTALS, SHUT-IN WELL PAYMENTS AND MINIMUM ROYALTIES:
	  	 	13	  
		 	 F.      TAXES:
	  	 	13	  
	VIII.	 	ACQUISITION. MAINTENANCE OR TRANSFER OF INTEREST	  	 	14	  
		 	 A.     SURRENDER OF LEASES:
	  	 	14	  
		 	 B.     RENEWAL OR EXTENSION OF LEASES:
	  	 	14	  
		 	 C.     ACREAGE OR CASH CONTRIBUTIONS:
	  	 	14	  


  
 i 









 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

 


 TABLE OF CONTENTS 

 


							
		 	 D.     ASSIGNMENT; MAINTENANCE OF UNIFORM INTEREST:
	  	 	15	  
		 	 E.     WAIVER OF RIGHTS TO PARTITION:
	  	 	15	  
		 	 F.      PREFERENTIAL RIGHT TO PURCHASE:
	  	 	15	  
	IX.	 	INTERNAL REVENUE CODE ELECTION	  	 	15	  
	X.	 	CLAIMS AND LAWSUITS	  	 	15	  
	XI.	 	FORCE MAJEURE	  	 	16	  
	XII.	 	NOTICES	  	 	16	  
	XIII.	 	TERM OF AGREEMENT	  	 	16	  
	XIV.	 	COMPLIANCE WITH LAWS AND REGULATIONS	  	 	16	  
		 	 A.     LAWS, REGULATIONS AND ORDERS:
	  	 	16	  
		 	 B.     GOVERNING LAW:
	  	 	16	  
		 	 C.     REGULATORY AGENCIES:
	  	 	16	  
	XV.	 	MISCELLANEOUS	  	 	17	  
		 	 A.     EXECUTION:
	  	 	17	  
		 	 B.     SUCCESSORS AND ASSIGNS:
	  	 	17	  
		 	 C.     COUNTERPARTS:
	  	 	17	  
		 	 D.     SEVERABILITY
	  	 	17	  
	XVI.	 	OTHER PROVISIONS	  	 	17	  


  
 ii 










 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

 

 OPERATING AGREEMENT 

THIS AGREEMENT, entered into by and between Dejour Energy (USA), Corp. hereinafter designated and referred to as
“Operator,” and the signatory party or parties other than Operator, sometimes hereinafter referred to individually as “Non-Operator,” and collectively as “Non-Operators.” 

WITNESSETH: 
 WHEREAS, the parties to this agreement are owners of Oil and Gas Leases and/or Oil and Gas Interests in the land identified in Exhibit “A,” and the parties hereto have reached an agreement to
explore and develop these Leases and/or Oil and Gas Interests for the production of Oil and Gas to the extent and as hereinafter provided, 
 NOW, THEREFORE, it is agreed as follows: 
 ARTICLE I. 

DEFINITIONS 
 As used in this agreement, the following words and terms shall have the meanings here ascribed to them: 
 A. The term “AFE” shall mean an Authority for Expenditure prepared by a party to this agreement for the purpose of estimating the costs to be incurred in conducting an operation hereunder.

 B. The term “Completion” or “Complete” shall mean a single operation intended to complete a well as a
producer of Oil and Gas in one or more Zones, including, but not limited to, the setting of production casing, perforating, well stimulation and production testing conducted in such operation. 

C. The term “Contract Area” shall mean all of the lands, Oil and Gas Leases and/or Oil and Gas Interests intended to be
developed and operated for Oil and Gas purposes under this agreement. Such lands, Oil and Gas Leases and Oil and Gas Interests are described in Exhibit “A.” 
 D. The term “Deepen” shall mean a single operation whereby a well is drilled to an objective Zone below the deepest Zone in which the well was previously drilled, or below the Deepest Zone
proposed in the associated AFE, whichever is the lesser. 
 E. The terms “Drilling Party” and “Consenting
Party” shall mean a party who agrees to join in and pay its share of the cost of any operation conducted under the provisions of this agreement. 
 F. The term “Drilling Unit” shall mean the area fixed for the drilling of one well by order or rule of any state or federal body having authority. If a Drilling Unit is not fixed by any
such rule or order, a Drilling Unit shall be the drilling unit as established by the pattern of drilling in the Contract Area unless fixed by express agreement of the Drilling Parties. See Page 17 Article XVI “Other Provisions”
for continued Article I Definitions F. language 
 G. The term “Drillsite” shall mean the Oil and Gas Lease or Oil
and Gas Interest on which a proposed well is to be located. See Page 17 Article XVI “Other Provisions” for continued Article I Definitions G. language. 
 H. The term “Initial Well” shall mean the well required to be drilled by the parties hereto as provided in Article VI.A. 
 I. The term “Non-Consent Well” shall mean a well in which less than all parties have conducted an operation as provided in Article VI.B.2. 

J. The terms “Non-Drilling Party” and “Non-Consenting Party” shall mean a party who elects not to participate in a
proposed operation. 
 K. The term “Oil and Gas” shall mean oil, gas, casinghead gas, gas condensate, and/or all other
liquid or gaseous hydrocarbons and other marketable substances produced therewith, unless an intent to limit the inclusiveness of this term is specifically stated. 
 L. The term “Oil and Gas Interests” or “Interests” shall mean unleased fee and mineral interests in Oil and Gas in tracts of land lying within the Contract Area which are owned by
parties to this agreement. 
 M. The terms “Oil and Gas Lease,” “Lease” and “Leasehold” shall mean
the oil and gas leases or interests therein covering tracts of land lying within the Contract Area which are owned by the parties to this agreement. 
 N. The term “Plug Back” shall mean a single operation whereby a deeper Zone is abandoned in order to attempt a Completion in a shallower Zone. 

O. The term “Recompletion” or “Recomplete” shall mean an operation whereby a Completion in one Zone is abandoned in
order to attempt a Completion in a different Zone within the existing wellbore. 
 P. The term “Rework” shall mean an
operation conducted in the wellbore of a well after it is Completed to secure, restore, or improve production in a Zone which is currently open to production in the wellbore. Such operations include, but are not limited to, well stimulation
operations but exclude any routine repair or maintenance work or drilling, Sidetracking, Deepening, Completing, Recompleting, or Plugging Back of a well. 
 Q. The term “Sidetrack” shall mean the directional control and intentional deviation of a well from vertical so as to change the bottom hole location unless done to straighten the hole or drill
around junk in the hole to overcome other mechanical difficulties. 
 R. The term “Zone” shall mean a stratum of earth
containing or thought to contain a common accumulation of Oil and Gas separately producible from any other common accumulation of Oil and Gas. 

See Page 17 Article XVI “Other Provisions” for additional Article I. Definitions S through Z. 

Unless the context otherwise clearly indicates, words used in the singular include the plural, the. word “person” includes
natural and artificial persons, the plural includes the singular, and any gender includes the masculine, feminine, and neuter. 

ARTICLE II. 

EXHIBITS 

The following exhibits, as indicated below and attached hereto, are incorporated in and made a part hereof: 

 

					
			
	      X      	 	A.	  	Exhibit “A,” shall include the following information:
			
		 		  	(1) Description of lands subject to this agreement,
			
		 		  	(2) Restrictions, if any, as to depths, formations, or substances,
			
		 		  	(3) Parties to agreement with addresses and telephone numbers for notice purposes,
			
		 		  	(4) Percentages or fractional interests of parties to this agreement,
			
		 		  	(5) Oil and Gas Leases and/or Oil and Gas Interests subject to this agreement,
			
		 		  	(6) Burdens on production.
			
		 	B.	  	Exhibit “B,” Form of Lease.
			
	      X      	 	C.	  	Exhibit “C,” Accounting Procedure.
			
	      X      	 	D.	  	Exhibit “D,” Insurance.
			
		 	E.	  	Exhibit “E,” Gas Balancing Agreement.
			
	      X      	 	F.	  	Exhibit “F,” Non-Discrimination and Certification of Non-Segregated Facilities.
			
	      X       	 	G.	  	Exhibit “G,” Tax Partnership.
			
	      X      	 	H.	  	Other: Weil Notice and Data Requirements


  
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 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

 

 If any provision of any exhibit, except Exhibits “E,” “F” and
“G,” is inconsistent with any provision contained in the body of this agreement, the provisions in the body of this agreement shall prevail. 
 ARTICLE III. 
 INTERESTS OF PARTIES 

A. Oil and Gas Interests: 
 If any party owns an Oil and Gas Interest in the Contract Area, that Interest shall be treated for all purposes of this agreement and during the term hereof as if it were covered by the form of
Oil and Gas Lease attached hereto as Exhibit “B,” and the owner thereof shall be deemed to own both royalty interest in such lease and the interest of the lessee thereunder. 

B. Interests of Parties in Costs and Production: 
 Unless changed by other provisions, all costs and liabilities incurred in operations under this agreement shall be borne and paid, and all equipment and materials acquired in operations on the Contract
Area shall be owned, by the parties as their interests are set forth in Exhibit “A.” In the same manner, the parties shall also own all production of Oil and Gas from the Contract Area subject, however, to the payment of royalties and
other burdens on production as described hereafter. 
 Regardless of which party has contributed any Oil and Gas Lease or Oil
and Gas Interest on which royalty or other burdens may be payable and except as otherwise expressly provided in this agreement, each party shall pay or deliver, or cause to be paid or delivered, all burdens on its share of the production from the
Contract Area up to, but not in excess of, 20% and shall indemnify, defend and hold the other parties free from any liability therefor. Except as otherwise expressly provided in this agreement, if any party has contributed hereto any Lease or
Interest which is burdened with any royalty, overriding royalty, production payment or other burden on production in excess of the amounts stipulated above, such party so burdened shall assume and alone bear all such excess obligations and shall
indemnify, defend and hold the other parties hereto harmless from any and all claims attributable to such excess burden. However, so long as the Drilling Unit for the productive Zone(s) is identical with the Contract Area, each party shall pay or
deliver, or cause to be paid or delivered, all burdens on production from the Contract Area due under the terms of the Oil and Gas Lease(s) which such party has contributed to this agreement, and shall indemnify, defend and hold the other parties
free from any liability therefor. 
 No party shall ever be responsible, on a price basis higher than the price received by such
party, to any other party’s lessor or royalty owner, and if such other party’s lessor or royalty owner should demand and receive settlement on a higher price basis, the party contributing the affected Lease shall bear the additional
royalty burden attributable to such higher price. 
 Nothing, contained in this Article III.B. shall be deemed an assignment or
cross-assignment of interests covered hereby, and in the event two or more parties contribute to this agreement jointly owned Leases, the parties’ undivided interests in said Leaseholds shall be deemed separate leasehold interests for the
purposes of this agreement. 
 C. Subsequently Created Interests: 

If any party has contributed hereto a Lease or Interest that is burdened with an assignment of production given as security for the
payment of money, or if, after the date of this agreement, any party creates an overriding royalty, production payment, net profits interest, assignment of production or other burden payable out of production attributable to its working interest
hereunder, such burden shall be deemed a “Subsequently Created Interest.” Further, if any party has contributed hereto a Lease or Interest burdened with an overriding royalty, production payment, net profits interests, or other burden
payable out of production created prior to the date of this agreement, and such burden is not shown on Exhibit “A,” such burden also shall be deemed a Subsequently Created Interest to the extent such burden causes the burdens on such
party’s Lease or Interest to exceed the amount stipulated in Article III.B. above. 
 The party whose interest is burdened
with the Subsequently Created Interest (the “Burdened Party”) shall assume and alone bear, pay and discharge the Subsequently Created Interest and shall indemnify, defend and hold harmless the other parties from and against any liability
therefor. Further, if the Burdened Party fails to pay, when due, its share of expenses chargeable hereunder, all provisions of Article VII.B. shall be enforceable against the Subsequently Created Interest in the same manner as they are enforceable
against the working interest of the Burdened Party. If the Burdened Party is required under this agreement to assign or relinquish to any other party, or parties, all or a portion of its working interest and/or the production attributable thereto,
said other party, or parties, shall receive said assignment and/or production free and clear of said Subsequently Created Interest, and the Burdened Party shall indemnify, defend and hold harmless said other party, or parties, from any and all
claims and demands for payment asserted by owners of the Subsequently Created Interest. 
 ARTICLE IV. 

TITLES 
 A. Title
Examination: 
 Title examination shall be made on the Drillsite of any proposed well prior to commencement of drilling
operations and, if a majority in interest of the Drilling Parties so request or Operator so elects, title examination shall be made on the entire Drilling Unit, or maximum anticipated Drilling-Producing
Unit, of the well. The opinion will include the ownership of the working interest, minerals, royalty, overriding royalty and production payments under the applicable Leases. Each party contributing Leases and/or Oil and Gas
Interests to be included in the Drillsite, or Drilling Unit, or Producing Unit, if appropriate, shall furnish to Operator all abstracts (including federal lease status reports), title opinions, title papers and curative
material in its possession free of charge. All such information not in the possession of or made available to Operator by the parties, but necessary for the examination of the title, shall be obtained by Operator. Operator shall cause title to he
examined by attorneys on its staff or by outside attorneys. Copies of all title opinions shall be furnished to each Drilling Party. Costs incurred by Operator in procuring abstracts, fees paid outside attorneys for title examination (including
preliminary, supplemental, shut-in royalty opinions and division order title opinions) and other direct charges as provided in Exhibit “C” shall be borne by the Drilling Parties in the proportion that the interest of each Drilling. Party
bears to the total interest of all Drilling Parties as such interests appear in Exhibit “A.” Operator shall make no charge for services rendered by its staff attorneys or other personnel in the performance of the above functions.

 Each party shall be responsible for securing curative matter and pooling amendments or agreements required in connection with
Leases or Oil and Gas Interests contributed by such party. Operator shall be responsible for the preparation and recording of pooling designations or declarations and communitization agreements as well as the conduct of hearings before governmental
agencies for the securing of spacing or pooling orders or any other orders necessary or appropriate to the conduct of operations hereunder. This shall not prevent any party from appearing on its own behalf at such hearings. Costs incurred by
Operator, including fees paid to outside attorneys, which are associated with hearings before governmental agencies, and which costs are necessary and proper for the activities contemplated under this agreement, shall be direct charges to the joint
account and shall not be covered by the administrative overhead charges as provided in Exhibit “C.” 

  
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 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

 

 Operator shall make no charge for services rendered by its staff attorneys or other personnel in the
performance of the above functions. 
 No well shall be drilled on the Contract Area until after (1) the title to the
Drillsite, or Drilling Unit, or Producing Unit, if appropriate, has been examined as above provided, and (2) the title has been approved by the examining attorney or title has been accepted by all of the Drilling Parties in such well.

 B. Loss or Failure of Title: 
 1. Failure of Title: Should any Oil and Gas Interest or Oil and Gas Lease be lost through failure of title, which results in a reduction of interest from that shown on Exhibit “A,” the
party credited with contributing the affected Lease or Interest (including, if applicable, a successor in interest to such party) shall have ninety (90) days from final determination of title failure to acquire a new lease or other instrument
curing the entirety of the title failure, which acquisition will not be subject to Article VIII.B., and failing to do so, this agreement, nevertheless, shall continue in force as to all remaining Oil and Gas Leases and Interests; and, 

(a) The party credited with contributing the Oil and Gas Lease or Interest affected by the title failure (including, if applicable, a
successor in interest to such party) shall bear alone the entire loss and it shall not be entitled to recover from Operator or the other parties any development or operating costs which it may have previously paid or incurred, but there shall be no
additional liability on its part to the other parties hereto by reason of such title failure; 
 (b) There shall be no
retroactive adjustment of expenses incurred or revenues received from the operation of the Lease or Interest which has failed, but the interests of the parties contained on Exhibit “A” shall be revised on an acreage basis, as of the time
it is determined finally that title failure has occurred, so that the interest of the party whose Lease or Interest is affected by the title failure will thereafter be reduced in the Contract Area by the amount of the Lease or Interest failed;

 (c) If the proportionate interest of the other parties hereto in any producing well previously drilled on the Contract Area
is increased by reason of the title failure, the party who bore the costs incurred in connection with such well attributable to the Lease or Interest which has failed shall receive the proceeds attributable to the increase in such interest (less
costs and burdens attributable thereto) until it has been reimbursed for unrecovered costs paid by it in connection with such well attributable to such failed Lease or Interest; 

(d) Should any person not a party to this agreement, who is determined to be the owner of any Lease or Interest which has failed, pay in
any manner any part of the cost of operation, development, or equipment, such amount shall be paid to the party or parties who bore the costs which are so refunded; 
 (e) Any liability to account to a person not a party to this agreement for prior production of Oil and Gas which arises by reason of title failure shall be borne severally by each party (including a
predecessor to a current party) who received production for which such accounting is required based on the amount of such production received, and each such party shall severally indemnify, defend and hold harmless all other parties hereto for any
such liability to account; 
 (f) No charge shall be made to the joint account for legal expenses, fees or salaries in
connection with the defense of the Lease or Interest claimed to have failed, but if the party contributing such Lease or Interest hereto elects to defend its title it shall bear all expenses in connection therewith; and 

(g) If any party is given credit on Exhibit “A” to a Lease or Interest which is limited solely to ownership of an interest in
the wellbore of any well or wells and the production therefrom, such party’s absence of interest in the remainder of the Contract Area shall be considered a Failure of Title as to such remaining Contract Area unless that absence of interest is
reflected on Exhibit “A.” 
 2. Loss by Non-Payment or Erroneous Payment of Amount Due: If, through mistake or
oversight, any rental, shut-in well payment, minimum royalty or royalty payment, or other payment necessary to maintain all or a portion of an Oil and Gas Lease or interest is not paid or is erroneously paid, and as a result a Lease or Interest
terminates, there shall be no monetary liability against the party who failed to make such payment. Unless the party who failed to make the required payment secures a new Lease or Interest covering the same interest within ninety (90) days from
the discovery of the failure to make proper payment, which acquisition will not be subject to Article VIII.B., the interests of the parties reflected on Exhibit “A” shall be revised on an acreage basis, effective as of the date of
termination of the Lease or Interest involved, and the party who failed to make proper payment will no longer be credited with an interest in the Contract Area on account of ownership of the Lease or Interest which has terminated. If the party who
failed to make the required payment shall not have been fully reimbursed, at the time of the loss, from the proceeds of the sale of Oil and Gas attributable to the lost Lease or Interest, calculated on an acreage basis, for the development and
operating costs previously paid on account of such Lease or Interest, it shall be reimbursed for unrecovered actual costs previously paid by it (but not for its share of the cost of any dry hole previously drilled or wells previously abandoned) from
so much of the following as is necessary to effect reimbursement: 
 (a) Proceeds of Oil and Gas produced prior to termination
of the Lease or Interest, less operating expenses and lease burdens chargeable hereunder to the person who failed to make payment, previously accrued to the credit of the lost Lease or Interest, on an acreage basis, up to the amount of unrecovered
costs; 
 (b) Proceeds of Oil and Gas, less operating expenses and lease burdens chargeable hereunder to the person who failed
to make payment, up to the amount of unrecovered costs attributable to that portion of Oil and Gas thereafter produced and marketed (excluding production from any wells thereafter drilled) which, in the absence of such Lease or Interest termination,
would be attributable to the lost Lease or Interest on an acreage basis and which as a result of such Lease or Interest termination is credited to other parties, the proceeds of said portion of the Oil and Gas to be contributed by the other parties
in proportion to their respective interests reflected on Exhibit “A”; and, 
 (c) Any monies, up to the amount of
unrecovered costs, that may be paid by any party who is, or becomes, the owner of the Lease or Interest lost, for the privilege of participating in the Contract Area or becoming a party to this agreement. 

3. Other Losses: All losses of Leases or Interests committed to this agreement, other than those set forth in Articles IV.B.1. and
IV.B.2. above, shall be joint losses and shall be borne by all parties in proportion to their interests shown on Exhibit “A.” This shall include but not be limited to the loss of any Lease or Interest through failure to develop or because
express or implied covenants have not been performed (other than performance which requires only the payment of money), and the loss of any Lease by expiration at the end of its primary term if it is not renewed or extended. There shall be no
readjustment of interests in the remaining portion of the Contract Area on account of any joint loss. 
 4. Curing Title:
In the event of a Failure of Title under Article IV.B.1. or a loss of title under Article IV.B.2, above, any Lease or Merest acquired by any party hereto (other than the party whose interest has failed or was lost) during the ninety (90) day
period provided by Article IV.B.1, and Article IV.B.2. above covering all or a portion of the interest that has failed or was lost shall be offered at cost to the party whose interest has failed or was lost, and the provisions of Article VIII.B.
shall not apply to such acquisition. 

  
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 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

 

 ARTICLE V. 
 OPERATOR 
 A. Designation and Responsibilities of Operator; 

Dejour Energy (USA) Corp. shall be the Operator of the Contact Area, and shall conduct and direct and have full control of all
operations on the Contract Area as permitted and required by, and within the limits of this agreement. In its performance of services hereunder for the Non-Operators, Operator shall be an independent contractor not subject to the control or
direction of the Non-Operators except as to the type of operation to be undertaken in accordance with the election procedures contained in this agreement. Operator shall not be deemed, or hold itself out as, the agent of the Non-Operators with
authority to bind them to any obligation or liability assumed or incurred by Operator as to any third party. Operator shall conduct its activities under this agreement as a reasonable prudent operator, in a good and workmanlike manner, with due
diligence and dispatch, in accordance with good oilfield practice, and in compliance with applicable law and regulation, but in no event shall it have any liability as Operator to the other parties for losses, sustained or liabilities incurred
except such as may result from gross negligence or willful misconduct. 
 B. Resignation or Removal of Operator and Selection of Successor:

 1. Resignation or Removal of Operator: Operator may resign at any time by giving written notice thereof to
Non-Operators. If Operator terminates its legal existence, no longer owns an interest hereunder in the Contract Area, or is no longer capable of serving as Operator, Operator shall be deemed to have resigned without any action by Non-Operators,
except the selection of a successor. Operator may be removed only for good cause by the affirmative vote of Non-Operators owning a majority interest based on ownership as shown on Exhibit “A” remaining after excluding the voting interest
of Operator; such vote shall not be deemed effective until a written notice has been delivered to the Operator by a Non-Operator detailing the alleged default and Operator has failed to cure the default within thirty (30) days from its receipt
of the notice or, if the default concerns an operation then being conducted, within forty-eight (48) hours of its receipt of the notice. For purposes hereof, “good cause” shall mean not only gross negligence or willful misconduct but
also the material breach of or inability to meet the standards of operation contained in Article V.A. or material failure or inability to perform its obligations under this agreement. 

Subject to Article VII.D.1., such resignation or removal shall not become effective until 7:00 o’clock A.M. on the first day of the
calendar month following the expiration of ninety (90) days after the giving of notice of resignation by Operator or action by the Non-Operators to remove Operator, unless a successor Operator has been selected and assumes the duties of
Operator at an earlier date. Operator, after effective date of resignation or removal, shall be bound by the terms hereof as a Non-Operator. A change of a corporate name or structure of Operator or transfer of Operator’s interest to any single
subsidiary, parent or successor corporation shall not be the basis for removal of Operator. 
 2. Selection of Successor
Operator: Upon the resignation or removal of Operator under any provision of this agreement, a successor Operator shall be selected by the parties. The successor Operator shall be selected from the parties owning an interest in the Contract Area
at the time such successor Operator is selected. The successor Operator shall be selected by the affirmative vote of two (2) or more parties owning a majority interest based on ownership as shown on Exhibit “A”; provided, however, if
an Operator which has been removed or is deemed to have resigned fails to vote or votes only to succeed itself, the successor Operator shall be selected by the affirmative vote of the party or parties owning a majority interest based on ownership as
shown on Exhibit “A” remaining after excluding the voting interest of the Operator that was removed or resigned. The former Operator shall promptly deliver to (no later than thirty (30) days after the successor Operator’s
selection) the successor Operator all records and data relating to the operations conducted by the former Operator to the extent such records and data are not already in the possession of the successor operator, along with an executed Change
of Operator form then in effect. Any cost of obtaining or copying the former Operator’s records and data shall be charged to the joint account. 
 3. Effect of Bankruptcy: If Operator becomes insolvent, bankrupt or is placed in receivership, it shall be deemed to have resigned without any action by Non-Operators, except the selection of a
successor. If a petition for relief under the federal bankruptcy laws is filed by or against Operator, and the removal of Operator is prevented by the federal bankruptcy court, all Non-Operators and Operator shall comprise an interim operating
committee to serve until Operator has elected to reject or assume this agreement pursuant to the Bankruptcy Code, and an election to reject this agreement by Operator as a debtor in possession, or by a trustee in bankruptcy, shall be deemed a
resignation as Operator without any action by Non-Operators, except the selection of a successor. During the period of time the operating committee controls operations, all actions shall require the approval of two (2) or more parties owning, a
majority interest based on ownership as shown on Exhibit “A.” In the event there are only two (2) parties to this agreement, during the period of time the operating committee controls operations, a third party acceptable to Operator,
Non-Operator and the federal bankruptcy court shall be selected as a member of the operating committee, and all actions shall require the approval of two (2) members of the operating committee without regard for their interest in the Contract
Area based on Exhibit “A.” 
 C. Employees and Contractors: 

The number of employees or contractors used by Operator in conducting operations hereunder, their selection, and the hours of labor and
the compensation for services performed shall be determined Operator, and all such employees or contractors shall be the employees or contractors of Operator. See Page 17 Article XVI “Other Provisions” for continued Article V Operation
C. Employees and Contractors language. 
 D. Rights and Duties of Operator: 

1. Competitive Rates and Use of Affiliates: All wells drilled on the Contract Area shall be drilled on a competitive contract basis
at the usual rates prevailing in the area. If it so desires, Operator may employ its own tools and equipment in the drilling of wells, but its charges therefor shall not exceed the prevailing rates in the area and the rate of such charges shall be
agreed upon by the parties in writing before drilling operations are commenced, and such work shall be performed by Operator under the same terms and conditions as are customary and usual in the area in contracts of independent contractors who are
doing work of a similar nature. All work performed or materials supplied by affiliates or related parties of Operator shall be performed or supplied at competitive rates, pursuant to written agreement, and in accordance with customs and standards
prevailing in the industry. 
 2. Discharge of Joint Account Obligations: Except as herein otherwise specifically
provided, Operator shall promptly pay and discharge expenses incurred in the development and operation of the Contract Area pursuant to this agreement and shall charge each of the parties hereto with their respective proportionate shares upon the
expense basis provided in Exhibit “C.” Operator shall keep an accurate record of the joint account hereunder, showing expenses incurred and charges and credits made and received. 

3. Protection from Liens: Operator shall pay, or cause to be paid, as and when they become due and payable, all accounts of
contractors and suppliers and wages and salaries for services rendered or performed, and for materials supplied on, to or in respect of the Contract Area or any operations for the joint account thereof, and shall keep the Contract Area free from
liens and encumbrances resulting therefrom except for those resulting from a bona fide dispute as to services rendered or materials supplied. 

  
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 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

 

 4. Custody of Funds: Operator shall hold for the account of the Non-Operators any
funds of the Non-Operators advanced or paid to the Operator, either for the conduct of operations hereunder or as a result of the sale of production from the Contract Area, and such funds shall remain the funds of the Non-Operators on whose account
they are advanced or paid until used for their intended purpose or otherwise delivered to the Non-Operators or applied toward the payment of debts as provided in Article VII.B. Nothing in this paragraph shall be construed to establish a fiduciary
relationship between Operator and Non-Operators for any purpose other than to account for Non-Operator funds as herein specifically provided. Nothing in this paragraph shall require the maintenance by Operator of separate accounts for the funds of
Non-Operators unless the parties otherwise specifically agree. 
 5. Access to Contract Area and Records: Operator shall,
except as otherwise provided herein, permit each Non-Operator or its duly authorized representative, at the Non-Operator’s sole risk and cost, Ml and free access at all reasonable times to all operations of every kind and character being
conducted for the joint account on the Contract Area and to the records of operations conducted thereon or production therefrom, including Operator’s books and records relating thereto. Such access rights shall not be exercised in a manner
interfering with Operator’s conduct of an operation hereunder and shall not obligate Operator to furnish any geologic or geophysical data of an interpretive nature unless the cost of preparation of such interpretive data was charged to the
joint account. Operator will furnish to each Non-Operator upon request copies of any and all reports and information obtained by Operator in connection with production and related items, including, without limitation, meter and chart reports,
production purchaser statements, run tickets and monthly gauge reports, but excluding purchase contracts and pricing information to the extent not applicable to the production of the Non-Operator seeking the information. Any audit of Operator’s
records relating to amounts expended and the appropriateness of such expenditures shall be conducted in accordance with the audit protocol specified in Exhibit “C.” 
 6. Filing and Furnishing Governmental Reports: Operator will file, and upon written request promptly furnish copies to each requesting Non-Operator not in default of its payment obligations, all
operational notices, reports or applications required to be filed by local, State, Federal or Indian agencies or authorities having jurisdiction over operations hereunder. Each Non-Operator shall provide to Operator on a timely basis all information
necessary to Operator to make such filings. 
 7. Drilling and Testing Operations: The following provisions shall apply
to each well drilled hereunder, including but not limited to the Initial Well: 
 (a) Operator will promptly advise
Non-Operators of the date on which the well is spudded, or the date on which drilling operations are commenced. 
 (b) Operator
will send to Non-Operators such reports, test results and notices regarding the progress of operations on the well as the Non-Operators shall reasonably request, including, but not limited to, daily drilling reports, completion reports, and well
logs. 
 (c) Operator shall adequately test all Zones encountered which may reasonably be expected to be capable of producing
Oil and Gas in paying quantities as a result of examination of the electric log or any other logs or cores or tests conducted hereunder. 
 8. Cost Estimates: Upon request of any Consenting Party, Operator shall furnish estimates of current and cumulative costs incurred for the joint account at reasonable intervals during the conduct
of any operation pursuant to this agreement. Operator shall not be held liable for errors in such estimates so long as the estimates are made in good faith. 
 9. Insurance: At all times while operations are conducted hereunder, Operator shall comply with the workers compensation law of the state where the operations are being conducted; provided,
however, that Operator may be a self-insurer for liability under said compensation laws in which event the only charge that shall be made to the joint account shall be as provided in Exhibit “C.” Operator shall also carry or provide
insurance for the benefit of the joint account of the parties as outlined in Exhibit “D” attached hereto and made a part hereof. Operator shall require all contractors engaged in work on or for the Contract Area to comply with the workers
compensation law of the state where the operations are being conducted and to maintain such other insurance as Operator may require. 
 In the event automobile liability insurance is specified in said Exhibit “D,” or subsequently receives the approval of the parties, no direct charge shall be made by Operator for premiums paid
for such insurance for Operator’s automotive equipment. 
 ARTICLE VI. 

DRILLING AND DEVELOPMENT 

A. Initial Well: 

On or before the      day of             ,
        , Operator shall commence the drilling of the Initial Well at the following location: 

and shall thereafter continue the drilling of the wells with due diligence toSee Article XVI Other Provisions, para A regarding
Drilling Program and Participation. 
 The drilling of the Initial Wells and the participation therein by all parties is obligatory, subject
to Article VI.C.1. as to participation in Completion operations and Article VI.F. as to termination of operations and Article XI as to occurrence of force majeure. 
 B. Subsequent Operations: 
 1. Proposed Operations: If any party
hereto should desire to drill any well on the Contract. Area other than the Initial Well, or if any party should desire to Rework, Sidetrack, Deepen, complete, Recomplete or Plug Back a dry hole or a well no longer capable of producing in
paying quantities in which such party has not otherwise relinquished its interest in the proposed objective Zone under this agreement, the party desiring to drill, Rework, Sidetrack, Deepen, complete, Recomplete or Plug Back such a well shall
give written notice of the proposed operation to the parties who have not otherwise relinquished their interest in such objective Zone 

  
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 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

 

 
under this agreement and to all other parties in the case of a proposal for Sidetracking or Deepening, specifying the work to be performed, the location, proposed depth, objective Zone and the
estimated cost of the operation. Each AFE to drill a new well on the Contract Area shall cover separate operation costs. The parties to whom such a notice is delivered shall have thirty (30) days after receipt of the notice within which
to notify the party proposing to do the work whether they elect to participate in the cost of the proposed operation. If a drilling rig is on location, notice of a proposal to Rework, Sidetrack, complete, Recomplete, Plug Back or Deepen may be,
given by telephone, telecopier or any other form of facsimile or electronic mail and the response period shall be limited to forty-eight (48) hours, exclusive of Saturday, Sunday and legal holidays. Failure of a party to whom such notice
is delivered to reply within the period above fixed shall constitute an election by that party not to participate in the cost of the proposed operation. Any proposal by a party to conduct an operation conflicting with the operation initially
proposed shall be delivered to all parties within the time and in the manner provided in Article VI.B.6. 
 If all parties to
whom such notice is delivered elect to participate in such a proposed operation, the parties shall be contractually committed to participate therein provided such operations are commenced within the time period hereafter set forth, and Operator
shall, no later than ninety (90) days after expiration of the notice period of thirty (30) days (or as promptly as practicable after the expiration of the forty-eight (48) hour period when a drilling rig is on location, as the case
may be), actually commence the proposed operation and thereafter complete it with due diligence at the risk and expense of the parties participating therein; provided, however, said commencement date may be extended upon written notice of same by
Operator to the other parties, for a period of up to an aggregate of no more than thirty (30) additional days if, in the sole opinion of Operator, such additional time is reasonably necessary to obtain permits from
governmental authorities, surface rights (including rights-of-way) or appropriate drilling equipment, or to complete title examination or curative matter required for title approval or acceptance. If the actual operation has not been commenced
within the time provided (including any extension thereof as specifically permitted herein or in the force majeure provisions of Article XI) and if any party hereto still desires to conduct said operation, written notice proposing same must be
resubmitted to the other parties in accordance herewith as if no prior proposal had been made. Those parties that did not participate in the drilling of a well for which a proposal to Deepen or Sidetrack is made hereunder shall, if such parties
desire to participate in the proposed Deepening or Sidetracking operation, reimburse the Drilling Parties in accordance with Article VI.B.4. in the event of a Deepening operation and in accordance with Article VI.B.5. in the event of a Sidetracking
operation. 
 2. Operations by Less Than All Parties: 

(a) Determination of Participation. If any party to whom such notice is delivered as provided in Article VI.B.1. or VI.C.1.
(Option No. 2) elects not to participate in the proposed operation, then, in order to be entitled to the benefits of this Article, the party or parties giving the notice and such other parties as shall elect to participate in the operation
shall, no later than ninety (90) days after the expiration of the notice period of thirty (30) days (or as promptly as practicable after the expiration of the forty-eight (48) hour period when a drilling rig is on location, as the
case may be) actually commence the proposed operation and complete it with due diligence. Operator shall perform all work for the account of the Consenting Parties; provided, however, if no drilling rig or other equipment is on location, and if
Operator is a Non-Consenting Party, the Consenting Parties shall either: (i) request Operator to perform the work required by such proposed operation for the account of the Consenting Parties, or (ii) designate one of the Consenting
Parties as Operator to perform such work. The rights and duties granted to and imposed upon the Operator under this agreement are granted to and imposed upon the party designated as Operator for an operation in which the original Operator is a
Non-Consenting Party. Consenting Parties, when conducting operations on the Contract Area pursuant to this Article VI.B.2., shall comply with all terms and conditions of this agreement. 

If less than all parties approve any proposed operation, the proposing party, immediately after the expiration of the applicable notice
period, shall advise all Parties of the total interest of the parties approving such operation and its recommendation as to whether the Consenting Parties should proceed with the operation as proposed. Each Consenting Party, within forty-eight
(48) hours (exclusive of Saturday, Sunday, and legal holidays) after delivery of such notice, shall advise the proposing party of its desire to (i) limit participation to such party’s interest as shown on Exhibit “A” or
(ii) carry only its proportionate part (determined by dividing such party’s interest in the Contract Area by the interests of all Consenting Parties in the Contract Area) of Non-Consenting Parties’ interests, or (iii) carry its
proportionate part (determined as provided in (ii)) of Non-Consenting Parties’ interests together with all or a portion of its proportionate part of any Non-Consenting Parties’ interests that any Consenting Party did not elect to take. Any
interest of Non-Consenting Parties that is not carried by a Consenting Party shall be deemed to be carried by the party proposing the operation if such party does not withdraw its proposal. Failure to advise the proposing party within the time
required shall be deemed an election under (i). In the event a drilling rig is on location, notice may be given by telephone, telecopier or any other form of facsimile or electronic mail and the time permitted for such a response shall not
exceed a total of forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays). The proposing party, at its election, may withdraw such proposal if there is less than 100% participation and shall notify all parties of such decision
within ten (10) days, or within twenty-four (24) hours if a drilling rig is on location, following expiration of the applicable response period. If 100% subscription to the proposed operation is obtained, the proposing party shall promptly
notify the Consenting Parties of their proportionate interests in the operation and the party serving as Operator shall commence such operation within the period provided in Article VI.B.1., subject to the same extension right as provided therein.

 (b) Relinquishment of Interest for Non-Participation. The entire cost and risk of conducting such operations shall be
borne by the Consenting. Parties in the proportions they have elected to bear same under the terms of the preceding paragraph. Consenting Parties shall keep the leasehold estates involved in such operations free and clear of all liens and
encumbrances of every kind created by or arising from the operations of the Consenting Parties. If such an operation results in a dry hole, then subject to Articles VI.B.6. and VI.E.3., the Consenting Parties shall plug and abandon the well and
restore the surface location at their sole cost, risk and expense; provided, however, that those Non-Consenting Parties that participated in the drilling, Deepening or Sidetracking of the well shall remain liable for, and shall pay, their
proportionate shares of the cost of plugging and abandoning the well and restoring the surface location insofar only as those costs were not increased by the subsequent operations of the Consenting Parties. If any well drilled, Reworked,
Sidetracked, Deepened, Recompleted or Plugged Back under the provisions of this Article results in a well capable of producing Oil and/or Gas in paying quantities, the Consenting Parties shall Complete and equip the well to produce at their sole
cost and risk, and the well shall then be turned over to Operator (if the Operator did not conduct the operation) and shall be operated by it at the expense and for the account of the Consenting Parties. Upon commencement of operations for the
drilling, Reworking, Sidetracking, Recompleting, Deepening or Plugging Back of any such well by Consenting Parties in accordance with the provisions of this Article, each Non-Consenting Party shall be deemed to have relinquished to Consenting
Parties, and the Consenting Parties shall own and be entitled to receive, in proportion to their respective interests, all of such Non- Consenting Party’s interest in the well and share of production therefrom or, in the case of a Reworking,
Sidetracking, 

  
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Deepening, Recompleting or Plugging Back, or a Completion pursuant to Article VI.C.1. Option No. 2, all of such Non-Consenting Party’s interest in the production obtained from the
operation in which the Non-Consenting Party did not elect to participate. Such relinquishment shall be effective until the proceeds of the sale of such share, calculated at the well, or market value thereof if such share is not sold (after deducting
applicable ad valorem, production, severance, and excise taxes, royalty, overriding royalty and other interests not excepted by Article III.C. payable out of or measured by the production from such well accruing with respect to such interest until
it reverts), shall equal the total of the following: 
 (i) 200% of each such Non-Consenting Party’s share of the
cost of any newly acquired surface equipment beyond the wellhead connections (including but not limited to stock tanks, separators, treaters, pumping equipment and piping), plus 100% of each such Non-Consenting Party’s share of the cost of
operation of the well commencing with first production and continuing until each such Non-Consenting Party’s relinquished interest shall revert to it under other provisions of this Article, it being agreed that each Non-Consenting Party’s
share of such costs and equipment will be that interest which would have been chargeable to such Non-Consenting Party had it participated in the well from the beginning of the operations; and 

(ii) 400% of (a) that portion of the costs and expenses of drilling, Reworking, Sidetracking, Deepening, Plugging Back,
testing, Completing, and Recompleting, after deducting any cash contributions received under Article VIII.C., and of (b) that portion of the cost of newly acquired equipment in the well (to and including the wellhead connections), which would
have been chargeable to such Non-Consenting Party if it had participated therein. 
 Notwithstanding anything to the contrary in
this Article VI.B., if the well does not reach the deepest objective Zone described in the notice proposing the well for reasons other than the encountering of granite or practically impenetrable substance or other condition in the hole rendering
further operations impracticable, Operator shall give notice thereof to each Non-Consenting Party who submitted or voted for an alternative proposal under Article VI.B.6. to drill the well to a shallower Zone than the deepest objective Zone proposed
in the notice under which the well was drilled, and each such Non-Consenting Party shall have the option to participate in the initial proposed Completion of the well by paying its share of the cost of drilling the well to its actual depth,
calculated in the manner provided in Article VI.B.4. (a). If any such Non-Consenting Party does not elect to participate in the first Completion proposed for such well, the relinquishment provisions of this Article VI.B.2. (b) shall apply to
such party’s interest. 
 (c) Reworking, Recompleting or Plugging Back. An election not to participate in the
drilling, Sidetracking or Deepening of a well shall be deemed an election not to participate in any Reworking or Plugging Back operation proposed in such a well, or portion thereof, to which the initial non-consent election applied that is conducted
at any time prior to full recovery by the Consenting Parties of the Non-Consenting Party’s recoupment amount. Similarly, an election not to participate in the Completing or Recompleting of a well shall be deemed an election not to participate
in any Reworking operation proposed in such a well, or portion thereof, to which the initial non-consent election applied that is conducted at any time prior to full recovery by the Consenting Parties of the Non-Consenting Party’s recoupment
amount. Any such Reworking, Recompleting or Plugging Back operation conducted during the recoupment period shall be deemed part of the cost of operation of said well and there shall be added to the sums to be recouped by the Consenting Parties
300% of that portion of the costs of the Reworking, Recompleting or Plugging Back operation which would have been chargeable to such Non-Consenting Party had it participated therein. If such a Reworking, Recompleting or Plugging Back
operation is proposed during such recoupment period, the provisions of this Article VI.B. shall be applicable as between said Consenting Parties in said well. 
 (d) Recoupment Matters. During the period of time Consenting Parties are entitled to receive Non-Consenting Party’s share of production, or the proceeds therefrom, Consenting Parties shall be
responsible for the payment of all ad valorem, production, severance, excise, gathering and other taxes, and all royalty, overriding royalty and other burdens applicable to Non-Consenting Party’s share of production not excepted by Article
III.C. 
 In the case of any Reworking, Sidetracking, Plugging Back, Recompleting or Deepening operation, the Consenting Parties
shall be permitted to use, free of cost, all casing, tubing and other equipment in the well, but the ownership of all such equipment shall remain unchanged; and upon abandonment of a well after such Reworking, Sidetracking, Plugging Back,
Recompleting or Deepening, the Consenting Parties shall account for all such equipment to the owners thereof, with each party receiving its proportionate part in kind or in value, less cost of salvage. 

Within ninety (90) days after the completion of any operation under this Article, the party conducting the operations for the
Consenting Parties shall furnish each Non-Consenting Party with an inventory of the equipment in and connected to the well, and an itemized statement of the cost of drilling, Sidetracking, Deepening, Plugging Back, testing, Completing, Recompleting,
and equipping the well for production; or, at its option, the operating party, in lieu of an itemized statement of such costs of operation, may submit a detailed statement of monthly billings. Each month thereafter, during the time the Consenting
Parties are being reimbursed as provided above, the party conducting the operations for the Consenting Parties shall furnish the Non-Consenting Parties with an itemized statement of all costs and liabilities incurred in the operation of the well,
together with a statement of the quantity of Oil and Gas produced from it and the amount of proceeds realized from the sale of the well’s working interest production during the preceding month. In determining the quantity of Oil and Gas
produced during any month, Consenting Parties shall use industry accepted methods such as but not limited to metering or periodic well tests. Any amount realized from the sale or other disposition of equipment newly acquired in connection with any
such operation which would have been owned by a Non-Consenting Party had it participated therein shall be credited against the total unreturned costs of the work done and of the equipment purchased in determining when the interest of such
Non-Consenting Party shall revert to it as above provided; and if there is a credit balance, it shall be paid to such Non-Consenting Party. 
 If and when the Consenting Parties recover from a Non-Consenting Party’s relinquished interest the amounts provided for above, the relinquished interests of such Non-Consenting Party shall
automatically revert to it as of 7:00 a.m. on the day following the day on which such recoupment occurs, and, from and after such reversion, such Non-Consenting Party shall own the same interest in such well, the material and equipment in or
pertaining thereto, and the production therefrom as such Non-Consenting Party would have been entitled to had it participated in the drilling, Sidetracking, Reworking, Deepening, Recompleting or Plugging Back of said well. Thereafter, such
Non-Consenting Party shall be charged with and shall pay its proportionate part of the further costs of the operation of said well (including plugging and abandonment, clean-up and damages) in accordance with the terms of this agreement and
Exhibit “C” attached hereto. 
 3. Stand-By Costs: When a well which has been drilled or Deepened has reached
its authorized depth and all tests have been completed and the results thereof furnished to the parties, or when operations on the well have been otherwise terminated pursuant to Article VI.F., stand-by costs incurred pending response to a
party’s notice proposing a Reworking, 

  
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Sidetracking, Deepening, Recompleting, Plugging Back or Completing operation in such a well (including the period required under Article VI.B.6. to resolve competing proposals) shall be charged
and borne as part of the drilling or Deepening operation just completed. Stand-by costs subsequent to all parties responding, or expiration of the response time permitted, whichever first occurs, and prior to agreement as to the participating
interests of all Consenting Parties pursuant to the terms of the second grammatical paragraph: of Article VI.B.2. (a), shall be charged to and borne as part of the proposed operation, but if the proposal is subsequently withdrawn because of
insufficient participation, such stand-by costs shall be allocated between the Consenting Parties in the proportion each Consenting Party’s interest as shown on Exhibit “A” bears to the total interest as shown on Exhibit “A”
of all Consenting Parties. 
 In the event that notice for a Sidetracking operation is given while the drilling rig to be
utilized is on location, any party may request and receive up to five (5) additional days after expiration of the forty-eight hour response period specified in Article VI.B.1. within which to respond by paying, for all stand-by costs and other
costs incurred during such extended response period; Operator may require such party to pay the estimated stand-by time in advance as a condition to extending the response period. If more than one party elects to take such additional time to respond
to the notice, standby costs shall be allocated between the parties taking additional time to respond on a day-to-day basis in the proportion each electing party’s interest as shown on Exhibit “A” bears to the total interest as shown
on Exhibit “A” of all the electing parties. 
 4. Deepening: If less than all parties elect to participate in a
drilling, Sidetracking, or Deepening operation proposed pursuant to Article VI.B.1., the interest relinquished by the Non-Consenting Parties to the Consenting Parties under Article VI.B.2. shall relate only and be limited to the lesser of
(i) the total depth actually drilled or (ii) the objective depth or Zone of which the parties were given notice under Article VI.B.1. (“Initial Objective”). Such well shall not be Deepened beyond the Initial Objective without
first complying with this Article to afford the Non-Consenting Parties the opportunity to participate in the Deepening operation. 
 In the event any Consenting Party desires to drill or Deepen a Non-Consent Well to a depth below the Initial Objective, such party shall give notice thereof, complying with the requirements of Article
VI.B.1., to all parties (including Non-Consenting Parties). Thereupon, Articles VI.B.1. and 2. shall apply and all parties receiving such notice shall have the right to participate or not participate in the Deepening of such well pursuant to said
Articles VI.B.1. and 2. If a Deepening operation is approved pursuant to such provisions, and if any Non-Consenting Party elects to participate in the Deepening operation, such Non-Consenting party shall pay or make reimbursement (as the case may
be) of the following costs and expenses. 
 (a) If the proposal to Deepen is made prior to the Completion of such well as a well
capable of producing in paying quantities, such Non-Consenting Party shall pay (or reimburse Consenting Parties for, as the case may be) that share of costs and expenses incurred in connection with the drilling of said well from the surface to the
Initial Objective which Non-Consenting Party would have paid had such Non-Consenting Party agreed to participate therein, plus the Non-Consenting Party’s share of the cost of Deepening and of participating in any further operations on the well
in accordance with the other provisions of this Agreement; provided, however, all costs for testing and Completion or attempted Completion of the well incurred by Consenting Parties prior to the point of actual operations to Deepen beyond the
Initial Objective shall be for the sole account of Consenting Parties. 
 (b) If the proposal is made for a Non-Consent Well
that has been previously Completed as a well capable of producing in paying quantities, but is no longer capable of producing in paying quantities, such Non-Consenting Party shall pay (or reimburse Consenting Parties for, as the case may be) its
proportionate share of all costs of drilling, Completing, and equipping said well from the surface to the Initial Objective, calculated in the manner provided in paragraph (a) above, less those costs recouped by the Consenting Parties from the
sale of production from the well. The Non-Consenting Party shall also pay its proportionate share of all costs of re-entering said well. The Non-Consenting Parties’ proportionate part (based on the percentage of such well Non-Consenting Party
would have owned had it previously participated in such Non-Consent Well) of the costs of salvable materials and equipment remaining in the hole and salvable surface equipment used in connection with such well shall be determined in accordance with
Exhibit “C.” If the Consenting Parties have recouped the cost of drilling, Completing, and equipping the well at the time such Deepening operation is conducted, then a Non-Consenting Party may participate in the Deepening of the well with
no payment for costs incurred prior to re-entering the well for Deepening 
 The foregoing shall not imply a right of any
Consenting Party to propose any Deepening for a Non-Consent Well prior to the drilling of such well to its Initial Objective without the consent of the other Consenting Parties as provided in Article VI.F. 

5. Sidetracking: See Page 17 Article XVI for additional Article VI. Section B. paragraph 5. Sidetracking language. Any party
having the right to participate in a proposed Sidetracking operation that does not own an interest in the affected wellbore at the time of the notice shall, upon electing to participate, tender to the wellbore owners its proportionate share (equal
to its interest in the Sidetracking operation) of the value of that portion of the existing wellbore to be utilized as follows: 
 (a) If the proposal is for Sidetracking an existing dry hole, reimbursement shall be on the basis of the actual costs incurred in the initial drilling of the well down to the depth
point at which the Sidetracking operation is initiated. 
 (b) If the proposal is for Sidetracking a well which
has previously produced, reimbursement shall be on the basis of such party’s proportionate share of drilling and equipping costs incurred in the initial drilling of the well down to the depthpoint at which the
Sidetracking operation is conducted, calculated in the manner described in Article VI.B.4(b) above. Such party’s proportionate share of the cost of the well’s salvable materials and equipment down to the depth at which the Sidetracking
operation is initiated shall be determined in accordance with the provisions of Exhibit “C.” 
 6. Order of
Preference of Operations. Except as otherwise specifically provided in this agreement, if any party desires to propose the conduct of an operation that conflicts with a proposal that has been made by a party under this Article VI, such party
shall have fifteen (15) days from delivery of the initial proposal, in the case of a proposal to drill a well or to perform an operation on a well where no drilling rig is on location, or twenty-four (24) hours, exclusive of Saturday,
Sunday and legal holidays, from delivery of the initial proposal, if a drilling rig is on location for the well on which such operation is to be conducted, to deliver to all parties entitled to participate in the proposed operation such party’s
alternative proposal, such alternate proposal to contain the same information required to be included in the initial proposal. Each party receiving such proposals shall elect by delivery of notice to Operator within five (5) days after
expiration of the proposal period, or within twenty-four (24) hours (exclusive inclusive of Saturday, Sunday and legal holidays) if a drilling rig is on location for the well that is the subject of the proposals, to
participate in one of the competing proposals. Any party not electing within the time required shall be deemed not to have voted. The proposal receiving the vote of parties owning the largest aggregate percentage interest of the parties voting shall
have priority over all other competing proposals; in the case of a tie vote, the 

  
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initial proposal shall prevail. Operator shall deliver notice of such result to all parties entitled to participate in the operation within five (5) days after expiration of the election
period (or within twenty-four (24) hours, exclusive inclusive of Saturday, Sunday and legal holidays, if a drilling rig is on location). Each party shall then have two (2) days (Or twenty-four (24) hours if a
rig is on location) from receipt of such notice to elect by delivery of notice to Operator to participate in such operation or to relinquish interest in the affected well pursuant to the provisions of Article VI.B.2.; failure by a party to deliver
notice within such period shall be deemed an election not to participate in the prevailing proposal. 
 7. Conformity to
Spacing Pattern. Notwithstanding the provisions of this Article VI.B.2., it is agreed that no wells shall be proposed to be drilled to or Completed in or produced from a Zone from which a well located elsewhere on the Contract Area is producing,
unless such well conforms to the then-existing well spacing pattern for such Zone or such well has been approved as an exception to the then-existing well spacing pattern for such zone By the appropriate regulatory agency. 

8. Paying Wells. No party shall conduct any Reworking, Deepening, Plugging Back, Completion, Recompletion, or Sidetracking
operation under this agreement with respect to any well then capable of producing in paying quantities except with the consent of all parties that have not relinquished interests in the well at the time of such operation. 

C. Completion of Wells; Reworking and Plugging Back: 
 1. Completion: Without the consent of all parties, no well shall be drilled, Deepened or Sidetracked, except any well drilled, Deepened or Sidetracked pursuant to the provisions of Article VI.B.2.
of this agreement. Consent to the drilling, Deepening or Sidetracking shall include: 
  

	 	 ̈	Option No. 1: All necessary expenditures for the drilling, Deepening or Sidetracking, testing, Completing and equipping of the well, including necessary
tankage and/or surface facilities. 

  

	 	 ̈x	Option No. 2: All necessary expenditures for the drilling, Deepening or Sidetracking and testing of the well. When such well has reached its authorized
depth, and all logs, cores and other tests have been completed, and the results thereof furnished to the parties, Operator shall give immediate notice to the Non-Operators having the right to participate in a Completion attempt whether or not
Operator recommends attempting to Complete the well, together with Operator’s AFE for Completion costs if not previously provided. The parties receiving such notice shall have forty-eight (48) hours (exclusive of Saturday, Sunday and legal
holidays) in which to elect by delivery of notice to Operator to participate in a recommended Completion attempt or to make a Completion proposal with an accompanying AFE. Operator shall deliver any such Completion proposal, or any Completion
proposal conflicting with Operator’s proposal, to the other parties entitled to participate in such Completion in accordance with the procedures specified in Article VI.B.6. Election to participate in a Completion attempt shall include consent
to all necessary expenditures for the Completing and equipping of such well, including necessary tankage and/or surface facilities but excluding any stimulation operation not contained on the Completion AFE. Failure of any party receiving such
notice to. reply within the period above fixed shall constitute an election by that party not to participate in the cost of the Completion attempt; provided, that Article VI.B.6. shall control in the case of conflicting Completion proposals. If one
or more, but less than all of the parties, elect to attempt a Completion, the provision of Article VI.B.2. hereof (the phrase “Reworking, Sidetracking, Deepening, Recompleting or Plugging Back” as contained in Article VI.B.2. shall be
deemed to include “Completing”) shall apply to the operations thereafter conducted by less than all parties; provided, however, that Article VI.B.2. shall apply separately to each separate Completion or Recompletion attempt undertaken
hereunder, and an election to become a Non-Consenting Party as to one Completion or Recompletion attempt shall not prevent a party from becoming a Consenting Party in subsequent Completion or Recompletion attempts regardless whether the Consenting
Parties as to earlier Completions or Recompletion have recouped their costs pursuant to Article VI.B.2.; provided further, that any recoupment of costs by a Consenting Party shall be made solely from the production attributable to the Zone in which
the Completion attempt is made. Election by a previous Non-Consenting party to participate in a subsequent Completion or Recompletion attempt shall require such party to pay its proportionate share of the cost of salvable materials and equipment
installed in the well pursuant to the previous Completion or Recompletion attempt, insofar and only insofar as such materials and equipment benefit the Zone in which such party participates in a Completion attempt. 


2. Rework, Recomplete or Plug Back: No well shall be Reworked, Recompleted or Plugged Back except a well Reworked, Recompleted, or
Plugged Back pursuant to the provisions of Article VI.B.2. of this agreement. Consent to the Reworking, Recompleting or Plugging Back of a well shall include all necessary expenditures in conducting such operations and Completing and equipping of
said well, including necessary tankage and/or surface facilities. 
 D. Other Operations: 

Operator shall not undertake any single project reasonably estimated to require an expenditure in excess of Fifty Thousand Dollars
($50,000.00) except in connection with the drilling, Sidetracking, Reworking, Deepening, Completing, Recompleting or Plugging Back of a well that has been previously authorized by or pursuant to this agreement; provided, however, that, in
case of explosion, fire, flood or other sudden emergency, whether of the same or different nature, Operator may take such steps and incur such expenses as in its opinion are required to deal with the emergency to safeguard life and property but
Operator, as promptly as possible, shall report the emergency to the other parties. If Operator prepares an AFE for its own use, Operator shall furnish any Non-Operator so requesting an information copy thereof for any single project costing in
excess of Fifty Thousand Dollars ($50,000.00). Any party who has not relinquished its interest in a well shall have the right to propose that Operator perform repair work or undertake the installation of artificial lift equipment or
ancillary production facilities such as salt water disposal wells or to conduct additional work with respect to a well drilled hereunder or other similar project (but not including the installation of gathering lines or other transportation or
marketing facilities, the installation of which shall be governed by separate agreement between the parties) reasonably estimated to require an expenditure in excess of the amount first set forth above in this Article VI.D. (except in connection
with an operation required to be proposed under Articles VI.B.1. or VI.C.1. Option No. 2, which shall be governed exclusively be those Articles). Operator shall deliver such proposal to all parties entitled to participate therein. If within
thirty (30) days thereof Operator secures the written consent of any party or parties owning at least 75% of the interests of the parties entitled to participate in such operation, each party having the right to participate in such
project shall be bound by the terms of such proposal and shall be obligated to pay its proportionate share of the costs of the proposed project as if it had consented to such project pursuant to the terms of the proposal. 

E. Abandonment of Wells: 

1. Abandonment of Dry Holes: Except for any well drilled or Deepened pursuant to Article VI.B.2., any well which has been drilled
or Deepened under the terms of this agreement and is proposed to be completed as a dry hole shall not be 

  
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plugged and abandoned without the consent of all parties. Should Operator, after diligent effort, be unable to contact any party, or should any party fail to reply within forty-eight
(48) hours (exclusive of Saturday, Sunday and legal holidays) after delivery of notice of the proposal to plug and abandon such well, such party shall be deemed to have consented to the proposed abandonment. All such wells shall be plugged and
abandoned in accordance with applicable regulations and at the cost, risk and expense of the parties who participated in the cost of drilling or Deepening such well. Any party who objects to plugging and abandoning such well by notice delivered to
Operator within forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays) after delivery of notice of the proposed plugging shall take over the well as of the end of such forty-eight (48) hour notice period and conduct
further operations in search of Oil and/or Gas subject to the provisions of Article VI.B.; failure of such party to provide proof reasonably satisfactory to Operator of its financial capability to conduct such operations or to take over the well
within such period or thereafter to conduct operations on such well or plug and abandon such well shall entitle Operator to retain or take possession of the well and plug and abandon the well. The party taking over the well shall indemnify Operator
(if Operator is an abandoning party) and the other abandoning parties against liability for any further operations conducted on such well except for the costs of plugging and abandoning the well and restoring the surface, for which the abandoning
parties shall remain proportionately liable. 
 2. Abandonment of Wells That Have Produced: Except for any well in which
a Non-Consent operation has been conducted hereunder for which the Consenting Parties have not been fully reimbursed as herein provided, any well which has been completed as a producer shall not be plugged and abandoned without the consent of all
parties. See Page 17 Article XVI for additional Article VI Section E. paragraph 2. Language.If all parties consent to such abandonment, the well shall be plugged and abandoned in accordance with applicable regulations and at the cost, risk
and expense of all the parties hereto. Failure of a party to reply within sixty (60) days of delivery of notice of proposed abandonment shall be deemed an election to consent to the proposal. If, within sixty (60) days after delivery of
notice of the proposed abandonment of any well, all parties do not agree to the abandonment of such well, those wishing to continue its operation from the Zone then open to production shall be obligated to take over the well as of the expiration of
the applicable notice period and shall indemnify Operator (if Operator is an abandoning party) and the other abandoning parties against liability for any further operations on the well conducted by such parties. Failure of such party or parties to
provide proof reasonably satisfactory to Operator of their financial capability to conduct such operations or to take over the well within the required period or thereafter to conduct operations on such well within ninety (90) days shall
entitle operator to retain or take possession of such well and plug and abandon the well. 
 Parties taking over a well as
provided herein shall tender to each of the other parties its proportionate share of the value of the well’s salvable material and equipment, determined in accordance with the provisions of Exhibit “C,” less the estimated cost of
salvaging and the estimated cost of plugging and abandoning and restoring the surface; provided, however, that in the event the estimated plugging and abandoning and surface restoration costs and the estimated cost of salvaging are higher than the
value of the well’s salvable material and equipment, each of the abandoning parties shall tender to the parties continuing operations their proportionate shares of the estimated excess cost. Each abandoning party shall assign to the
non-abandoning parties, without warranty, express or implied, as to title or as to quantity, or fitness for use of the equipment and material, all of its interest in the wellbore of the well and related equipment, together with its interest in the
Leasehold insofar and only insofar as such Leasehold covers the right to obtain production from that wellbore in the Zone then open to production. If the interest of the abandoning party is or includes and Oil and Gas Interest, such party shall
execute and deliver to the non-abandoning party or parties an oil and gas lease, limited to the wellbore and the Zone then open to production, for a term of one (1) year and so long thereafter as Oil and/or Gas is produced from the Zone covered
thereby, such lease to be on the form attached as Exhibit “B.” The assignments or leases so limited shall encompass the Drilling Unit upon which the well is located. The payments by, and the assignments or leases to, the assignees shall be
in a ratio based upon the relationship of their respective percentage of participation in the Contract Area to the aggregate of the percentages of participation in the Contract Area of all assignees. There shall be no readjustment of interests in
the remaining portions of the Contract Area. 
 Thereafter, abandoning parties shall have no further responsibility, liability,
or interest in the operation of or production from the well in the Zone then open other than the royalties retained in any lease made under the terms of this Article. Upon request, Operator shall continue to operate the assigned well for the account
of the non-abandoning parties at the rates and charges contemplated by this agreement, plus any additional cost and charges which may arise as the result of the separate ownership of the assigned well. Upon proposed abandonment of the producing Zone
assigned or leased, the assignor or lessor shall then have the option to repurchase its prior interest in the well (using the same valuation formula) and participate in further operations therein subject to the provisions hereof. 

3. Abandonment of Non-Consent Operations: The provisions of Article VI.E.1. or VI.E.2. above shall be applicable as between
Consenting Parties in the event of the proposed abandonment of any well excepted from said Articles; provided, however, no well shall be permanently plugged and abandoned unless and until all parties having the right to conduct further operations
therein have been notified of the proposed abandonment and afforded the opportunity to elect to take over the well in accordance with the provisions of this Article VI.E.; and provided further, that Non-Consenting Parties who own an interest in a
portion of the well shall pay their proportionate shares of abandonment and surface restoration cost for such well as provided in Article VI.B.2.(b). 
 F. Termination of Operations: 
 Upon the commencement of an operation for
the drilling, Reworking, Sidetracking, Plugging Back, Deepening, testing, Completion or plugging of a well, including but not limited to the Initial Well, such operation shall not be terminated without consent of parties bearing 75% of the
costs of such operation; provided, however, that in the event granite or other practically impenetrable substance or condition in the hole is encountered which renders further operations impractical, Operator may discontinue operations and give
notice of such condition in the manner provided in Article VI.B.1, and the provisions of Article VI.B. or VI.E. shall thereafter apply to such operation, as appropriate. 
 G. Taking Production in Kind: 
  

	 	 ̈	Option No. 1: Gas Balancing Agreement Attached 


Each party shall take in kind or separately dispose of its proportionate share of all Oil and Gas produced from
the Contract Area, exclusive of production which may be used in development and producing operations and in preparing and treating Oil and Gas for marketing purposes and production unavoidably lost. Any extra expenditure incurred in the taking in
kind or separate disposition by any party of its proportionate share of the production shall be borne by such party. Any party taking its share of production in kind shall be required to pay for only its proportionate share of such part of
Operator’s surface facilities which it uses. 
 Each party shall execute such division
orders and contracts as may be necessary for the sale of its interest in production from the Contract Area, and, except as provided in Article VII.B., shall be entitled to receive payment directly from the purchaser thereof for its share of all
production. 

  
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 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

 

 If any party fails to make the arrangements necessary to take in
kind or separately dispose of its proportionate share of the Oil produced from the Contract Area, Operator shall have the right, subject to the revocation at will by the party owning it, but not the obligation, to purchase such Oil or sell it to
others at any time and from time to time, for the account of the non-taking party. Any such purchase or sale by Operator may be terminated by Operator upon at least ten (10) days written notice to the owner of said production and shall be
subject always to the right of the owner of the production upon at least ten (10) days written notice to Operator to exercise at any time its right to take in kind, or separately dispose of, its share of all Oil not previously delivered to a
purchaser. Any purchase or sale by Operator of any other party’s share of Oil shall be only for such reasonable periods of time as are consistent with the minimum needs of the industry under the particular circumstances, but in no event for a
period in excess of one (1) year. 
 Any such sale by Operator shall be in a manner
commercially reasonable under the circumstances but Operator shall have no duty to share any existing market or to obtain a price equal to that received under any existing market. The sale or delivery by Operator of a non-taking party’s share
of Oil under the terms of any existing contract of Operator shall not give the non-taking party any interest in or make the non-taking party a party to said contract. No purchase shall be made by Operator without first giving the non-taking party at
least ten (10) days written notice of such intended purchase and the price to be paid or the pricing basis to be used. 
 All parties shall give timely written notice to Operator of their Gas marketing arrangements for the following month, excluding price, and shall notify Operator immediately in the event of a
change in such arrangement. Operator shall maintain records of all marketing arrangements, and of volumes actually sold or transported, which records shall be made available to Non-Operators upon reasonable request. 

In the event one or more parties’ separate disposition of its share of the Gas causes split stream deliveries
to separate pipelines and/or deliveries which on a day to day basis for any reason are not exactly equal to a party’s respective proportionate share of total Gas sales to be allocated to it, the balancing or accounting between the parties shall
be in accordance with any Gas balancing agreement between the parties hereto, whether such an agreement is attached as Exhibit “E” or is a separate agreement. Operator shall give notice to all parties of the first sales of Gas from any
well under this agreement. 
 Option No. 2: No Gas Balancing Agreement: See Article XVI.E. for
additional terms regarding sales of Oil and/or Gas. 
 Each party shall take in kind or
separately Operator shall sell dispose of its and Non-Operator’s proportionate share of all Oil and Gas produced from the Contract Area, exclusive of production which may be used in development and
producing operations and in preparing and treating Oil and Gas for marketing purposes and production unavoidably lost. Any extra expenditures incurred in the taking in kind or separate disposition by any party of its proportionate share of
the production shall be borne by such party. Any party taking its share of production in kind shall be required to pay for only its proportionate share of such part of Operator’s surface facilities which it uses. 

Each party shall execute such division orders and contracts as may be necessary for the sale of its interest in
production from the Contract Area, and, Non-Operator shall direct that payments with respect to its proportionate share be paid directly to Operator per Article XVI.E. except as provided in Article VII.B., shall be entitled to
receive payment directly from the purchaser thereof for its share of all production. 
 If any
party fails to make the arrangements necessary to take in kind or separately dispose of its proportionate share of the Oil and/or Gas produced from the Contract Area, Operator shall have the right, subject to the revocation at will by the party
owning it, but not the obligation, to purchase such Oil and/or Gas or sell it to others at any time and from time to time, for the account of the non-taking party. Any such purchase or sale by Operator may be terminated by Operator upon at least ten
(10) days written notice to the owner of said production and shall be subject always to the right of the owner of the production upon at least ten (10) days written notice to Operator to exercise its right to take in kind, or separately
dispose of, its share of all Oil and/or Gas not previously delivered to a purchaser; provided, however, that the effective date of any such revocation may be deferred at Operator’s election for a period not to exceed ninety (90) days if
Operator has committed such production to a purchase contract having a term extending beyond such ten (10) days period. Any purchase or sale by Operator of any other party’s share of Oil and/or Gas shall be only for such reasonable periods
of time as are consistent with the minimum needs of the industry under the particular circumstances, but in no event for a period in excess of one (1) year. 

Any such Such sale by Operator shall be in a manner commercially reasonable under the
circumstances, but Operator shall have no duty to share any existing market or transportation arrangement or to obtain a price or transportation fee equal to that received under any existing market or transportation arrangement. The
sale or delivery by Operator of Non-Operator’s a non-taking party’s share of production under the terms of any new or existing contract of Operator shall not give the Non-Operator non-taking
party any interest in or make the Non-Operator non-taking party a party to said contract. No purchase of Oil and Gas and no sale of Gas shall be made by Operator without first giving the non-taking party ten
days written notice of such intended purchase or sale and the price to be paid or the pricing basis to be used. Operator shall give notice to all parties of the first sale of Gas from any well under this Agreement. 

All parties shall give timely written notice to Operator of their Gas marketing arrangements for the following
month, excluding price, and shall notify Operator immediately in the event of a change in such arrangements. 
 Operator shall maintain records of all marketing arrangements, and of volumes actually sold or transported, which records shall be made available to Non-Operators upon reasonable request. 

ARTICLE VII. 
 EXPENDITURES AND LIABILITY OF PARTIES 
 A. Liability of Parties: 

The liability of the parties shall be several, not joint or collective. Each party shall be responsible only for its obligations, and
shall be liable only for its proportionate share of the costs of developing and operating the Contract Area. Accordingly, the liens granted among the parties in Article VII.B. are given to secure only the debts of each severally, and no party shall
have any liability to third parties hereunder to satisfy the default of any other party in the payment of any expense or obligation hereunder. It is not the intention of the parties to create, nor shall this agreement be construed as creating, a
mining or other partnership, joint venture, agency relationship or association, or to render the parties liable as partners, co-venturers, or principals. In their relations with each other under this agreement, the parties shall not: be considered
fiduciaries or to have established a confidential relationship but rather shall be free to act on an arm’s-length basis in accordance with their own respective self-interest, subject, however, to the obligation of fee parties to act in good
faith in their dealings with each other with respect to activities hereunder. 

  
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 B. Liens and Security Interests: 

Each party grants to the other parties hereto a lien upon any interest it now owns or hereafter acquires in Oil and Gas Leases and Oil and
Gas Interests in the Contract Area, and a security interest and/or purchase money security interest in any interest it now owns or hereafter acquires in the personal property and fixtures on or used or obtained for use in connection therewith, to
secure performance of all of its obligations under this agreement including but not limited to payment of expense, interest and fees, the proper disbursement of all monies paid hereunder, the assignment or relinquishment of interest in Oil and Gas
Leases as required hereunder, and the proper performance of operations hereunder. Such lien and security interest granted by each party hereto shall include such party’s leasehold interests, working interests, operating rights, and royalty and
overriding royalty interests in the Contract Area now owned or hereafter acquired and in lands pooled or unitized therewith or otherwise becoming subject to this agreement, the Oil and Gas when extracted therefrom and equipment situated thereon or
used or obtained for use in connection therewith (including, without limitation, all wells, tools, and tubular goods), and accounts (including, without limitation, accounts arising from gas imbalances or from the sale of Oil and/or Gas at the
wellhead), contract rights, inventory and general intangibles relating thereto or arising therefrom, and all proceeds and products of the foregoing. 
 To perfect the lien and security agreement provided herein, each party hereto shall execute and acknowledge the recording supplement and/or any financing statement prepared and submitted by any party
hereto in conjunction herewith or at any time following execution hereof, and Operator is authorized to file this agreement or the recording supplement executed herewith as a lien or mortgage in the applicable real estate records and as a financing
statement with the proper officer under the Uniform Commercial Code in the state in which the Contract Area is situated and such other states as Operator shall deem appropriate to perfect the security interest granted hereunder. Any party may file
this agreement, the recording supplement executed herewith, or such other documents as it deems necessary as a lien or mortgage in the applicable real estate records and/or a financing statement with the proper officer under the Uniform Commercial
Code. 
 Each party represents and warrants to the other parties hereto that the lien and security interest granted by such
party to the other parties shall be a first and prior lien, and each party hereby agrees to maintain the priority of said lien and security interest against all persons acquiring an interest in Oil and Gas Leases and Interests covered by this
agreement by, through or under such party. All parties acquiring an interest in Oil and Gas Leases and Oil and Gas Interests covered by this agreement, whether by assignment, merger, mortgage, operation of law, or otherwise, shall be deemed to have
taken subject to the lien and security interest granted by this Article VII.B, as to all obligations attributable to such interest hereunder whether or not such obligations arise before or after such interest is acquired. 

To the extent that parties have a security interest under the Uniform Commercial Code of the state in which the Contract Area is
situated, they shall be entitled to exercise the rights and remedies of a secured party under the Code. The bringing of a suit and the obtaining of judgment by a party for the secured indebtedness shall not be deemed an election of remedies or
otherwise affect the lien rights or security interest as security for the payment thereof. In addition, upon default by any party in the payment of its share of expenses, interests or fees, or upon the improper use of funds by the Operator, the
other parties shall have the right, without prejudice to other rights or remedies, to collect from the purchaser the proceeds from the sale of such defaulting party’s share of Oil and Gas until the amount owed by such party, plus interest as
provided in “Exhibit C,” has been received, and shall have the right to offset the amount owed against the proceeds from the sale of such defaulting party’s share of Oil and Gas, All purchasers of production may rely on a notification
of default from the non-defaulting party or parties stating the amount due as a result of the default, and all parties waive any recourse available against purchasers for releasing production proceeds as provided in this paragraph. 

If any party fails to pay its share of cost within one hundred twenty (120) days after rendition of a statement therefor by
Operator, the non-defaulting parties, including Operator, shall upon request by Operator, pay the unpaid amount in the proportion that the interest of each such party bears to the interest of all such parties. The amount paid by each party so paying
its share of the unpaid amount shall be secured by the liens and security rights described in Article VII.B., and each paying party may independently pursue any remedy available hereunder or otherwise. 

If any party does not perform all of its obligations hereunder, and the failure to perform subjects such party to foreclosure or
execution proceedings pursuant to the provisions of this agreement, to the extent allowed by governing law, the defaulting party waives any available right of redemption from and after the date of judgment, any required valuation or appraisement of
the mortgaged or secured property prior to sale, any available right to stay execution or to require a marshaling of assets and any required bond in the event a receiver is appointed. In addition, to the extent permitted by applicable law, each
party hereby grants to the other parties a power of sale as to any property that is subject to the lien and security rights granted hereunder, such power to be exercised in the manner provided by applicable law or otherwise in a commercially
reasonable manner and upon reasonable notice. 
 Each party agrees that the other parties shall be entitled to utilize the
provisions of Oil and Gas lien law or other lien law of any state in which the Contract Area is situated to enforce the obligations of each party hereunder. Without limiting the generality of the foregoing, to the extent permitted by applicable law,
Non-Operators agree that Operator may invoke or utilize the mechanics’ or materialmen’s lien law of the state in which the Contract Area is situated in order to secure the payment to Operator of any sum due hereunder for services performed
or materials supplied by Operator. 
 C. Advances: 
 Operator, at its election, shall have the right from time to time to demand and receive from one or more of the other parties payment in advance of their respective shares of the estimated amount of the
expense to be incurred in operations hereunder during the next succeeding month, which right may be exercised only by submission to each such party of an itemized statement of such estimated expense, together with an invoice for its share thereof.
Each such statement and invoice for the payment in advance of estimated expense shall be submitted on or before the 20th day of the next preceding month. Each party shall pay to Operator its proportionate share of such estimate within fifteen
(15) days after such estimate and invoice is received. If any party fails to pay its share of said estimate within said time, the amount due shall bear interest as provided in Exhibit “C” until paid. Proper adjustment shall be made
monthly between advances and actual expense to the end that each party shall bear and pay its proportionate share of actual expenses incurred, and no more. 
 D. Defaults and Remedies: 
 If any party fails to discharge any financial
obligation under this agreement, including without limitation the failure to make any advance under the preceding Article VII.C. or any other provision of this agreement, within the period required for such payment hereunder, then in addition to the
remedies provided in Article VII.B. or elsewhere in this agreement, the remedies specified below shall be applicable. For purposes of this Article VII.D., all notices and elections shall be delivered


  
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only by Operator, except that Operator shall deliver any such notice and election requested by a non-defaulting Non-Operator, and when Operator is the party in default, the applicable notices and
elections can be delivered by any Non-Operator. Election of any one or more of the following remedies shall not preclude the subsequent use of any other remedy specified below or otherwise available to anon-defaulting party. 

1. Suspension of Rights: Any party may deliver to the party in default a Notice of Default, which shall specify the default,
specify the action to be taken to cure the default, and specify that failure to take such action will result in the exercise of one or more of the remedies provided in this Article. If the default is not cured within thirty (30) days of the
delivery of such Notice of Default, all of the rights of the defaulting party granted by this agreement may upon notice be suspended until the default is cured, without prejudice to the right of the non-defaulting party or parties to continue to
enforce the. obligations of the defaulting party previously accrued or thereafter accruing under this agreement. If Operator is the party in default, the Non-Operators shall have in addition the right, by vote of Non-Operators owning a majority in
interest in the Contract Area after excluding the voting interest of Operator, to appoint a new Operator effective immediately. The rights of a defaulting party that may be suspended hereunder at the election of the non-defaulting parties shall
include, without limitation, the right to receive information as to any operation conducted hereunder during the period of such default, the right to elect to participate in an operation proposed under Article VI.B. of this agreement, the right to
participate in an operation being conducted under this agreement even if the party has previously elected to participate in such operation, and the right to receive proceeds of production from any well subject to this agreement. 

2. Suit for Damages: Non-defaulting parties or Operator for the benefit of non-defaulting parties may sue (at joint account
expense) to collect the amounts in default, plus interest accruing on the amounts recovered from the date of default until the date of collection at the rate specified in Exhibit “C” attached hereto. Nothing herein shall prevent any party
from suing any defaulting party to collect consequential damages accruing to such party as a result of the default. 
 3.
Deemed Non-Consent: The non-defaulting party may deliver a written Notice of Non-Consent Election to the defaulting party at any time after the expiration of the thirty-day cure period following delivery of the Notice of Default, in which
event if the billing is for the drilling a new well or the Plugging Back, Sidetracking, Reworking or Deepening of a well which is to be or has been plugged as a dry hole, or for the Completion or Recompletion of any well, the defaulting party will
be conclusively deemed to have elected not to participate in the operation and to be a Non-Consenting Party with respect thereto under Article VI.B. or VI.C., as the case may be, to the extent of the. costs unpaid by such party, notwithstanding any
election to participate theretofore made. If election is made to proceed under this provision, then the non-defaulting parties may not elect to sue for the unpaid amount pursuant to Article VII.D.2. 

Until the delivery of such Notice of Non-Consent Election to the defaulting party, such party shall have the right to cure its default by
paying its unpaid share of costs plus interest at the rate set forth in Exhibit “C,” provided, however, such payment shall not prejudice the rights of the non-defaulting parties to pursue remedies for damages incurred by the non-defaulting
parties as a result of the default. Any interest relinquished pursuant to this Article VII.D.3. shall be offered to the non-defaulting parties in proportion to their interests, and the non-defaulting parties electing to participate in the ownership
of such interest shall be required to contribute their shares of the defaulted amount upon their election to participate therein. 
 4. Advance Payment: If a default is not cured within thirty (30) days of the delivery of a Notice of Default, Operator, or Non-Operators if Operator is the defaulting party, may thereafter
require advance payment from the defaulting party of such defaulting party’s anticipated share of any item of expense for which Operator, or Non-Operators, as the case may be, would be entitled to reimbursement under any provision of this
agreement, whether or not such expense was the subject of the previous default. Such right includes, but is not limited to, the right to require advance payment for the estimated costs of drilling a well or Completion of a well as to which an
election to participate in drilling or Completion has been made. If the defaulting party fails to pay the required advance payment, the non-defaulting parties may pursue any of the remedies provided in the Article VII.D. or any other default remedy
provided elsewhere in this agreement. Any excess of funds advanced remaining when the operation is completed and all costs have been paid shall be promptly returned to the advancing party, 

5. Costs and Attorneys’ Fees: In the event any party is required to bring legal proceedings to enforce any financial
obligation of a party hereunder, the prevailing party in such action shall be entitled to recover all court costs, costs of collection, and a reasonable attorney’s fee, which the lien provided for herein shall also secure. 

E. Rentals, Shut-in Well Payments and Minimum Royalties: 
 Rentals, shut-in well payments and minimum royalties which may be required under the terms of any lease shall be paid by the party or parties who subjected such lease to this agreement at its or their
expense. In the event two or more parties own and have contributed interests in the same lease to this agreement, such parties may designate one of such parties to make said payments for and on behalf of all such parties. Any party may request, and
shall be entitled to receive, proper evidence of all such payments. In the event of failure to make proper payment of any rental, shut-in well payment or minimum royalty through mistake or oversight where such payment is required to continue the
lease in force, any loss which results from such non-payment shall be borne in accordance with the provisions of Article IV.B.2. 
 Operator shall notify Non-Operators of the anticipated completion of a shut-in well, or the shutting in or return to production of a producing well, at least five (5) days (excluding Saturday,
Sunday, and legal holidays) prior to taking such action, or at the earliest opportunity permitted by circumstances, but assumes no liability for failure to do so. In the event of failure by Operator to so notify Non-Operators, the loss of any lease
contributed hereto by Non-Operators for failure to make timely payments of any shut-in well payment shall be borne jointly by the parties hereto under the provisions of Article IV.B.3. 
 F. Taxes: 
 Beginning with the first calendar year after the effective date
hereof, Operator shall render for ad valorem taxation all property subject to this agreement which by law should be rendered for such taxes, and it shall pay all such taxes assessed thereon before they become delinquent. Prior to the rendition date,
each Non-Operator shall furnish Operator information as to burdens (to include, but not be limited to, royalties, overriding royalties and production payments) on Leases and Oil and Gas Interests contributed by such Non-Operator. If the assessed
valuation of any Lease is reduced by reason of its being subject to outstanding excess royalties, overriding royalties or production payments, the reduction in ad valorem taxes resulting therefrom shall inure to the benefit of the owner or owners of
such Lease, and Operator shall adjust the charge to such owner or owners so as to reflect the benefit of such reduction. If the ad valorem taxes are based in whole or in part upon separate valuations Of each party’s working interest, then
notwithstanding anything to the contrary herein, charges to the joint account shall be made and paid by the parties hereto in accordance with the tax value generated by each party’s working interest. Operator shall bill the other parties for
their proportionate shares of all tax payments in the manner provided in Exhibit “C.” However, if at any time any party taking its share of production in kind or is separately disposing of same, such party shall pay or cause to be paid
any and all taxes as to such production. 

  
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 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

 

 If Operator considers any tax assessment improper, Operator may, at its discretion,
protest within the time and manner prescribed by law, and prosecute the protest to a final determination, unless all parties agree to abandon the protest prior to final determination. During the pendency of administrative or judicial proceedings,
Operator may elect to pay, under protest, all such taxes and any interest and penalty. When any such protested assessment shall have been finally determined, Operator shall pay the tax for the joint account, together with any interest and penalty
accrued, and the total cost shall then be assessed against the parties, and be paid by them, as provided in Exhibit “C.” 
 Each party shall pay or cause to be paid all production, severance, excise, gathering and other taxes imposed upon or with respect to the production or handling of such party’s share of Oil and Gas
produced under the terms of this agreement. 
 ARTICLE VIII. 

ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST 
 A. Surrender of Leases: 
 The Leases covered by this agreement insofar as
they embrace acreage in the Contract Area, shall not be surrendered in whole or in part unless all parties consent thereto. 

However, should any party desire to surrender its interest in any Lease or in any portion thereof, such party shall give written notice
of the proposed surrender to all parties, and the parties to whom such notice is delivered shall have thirty (30) days after delivery of the notice within which to notify the party proposing the surrender whether they elect to consent thereto.
Failure of a party to whom such notice is delivered to reply within said 30-day period shall constitute a consent to the surrender of the Leases described in the notice. If all parties do not agree or consent thereto, the party desiring to surrender
shall assign, without express or implied warranty of title, all of its interest in such Lease, or portion thereof, and any well, material and equipment which may be located thereon and any rights in production thereafter secured, to the parties not
consenting to such surrender. If the interest of the assigning party is or includes an Oil and Gas Interest, the assigning party shall execute and deliver to the party or parties not consenting to such surrender an oil and gas lease covering such
Oil and Gas Interest for a term of one (1) year and so long thereafter as Oil and/or Gas is produced from the land covered thereby, such lease to be on the form attached hereto as Exhibit “B.” Upon such assignment or lease, the
assigning party shall be relieved from all obligations thereafter accruing, but not theretofore accrued, with respect to the interest assigned or leased and the operation of any well attributable thereto, and the assigning party shall have no
further interest in the assigned or leased premises and its equipment and production other than the royalties retained in any lease made under the terms of this Article. The party assignee or lessee shall pay to the party assignor or lessor the
reasonable salvage value of the latter’s interest in any well’s salvable materials and equipment attributable to the assigned or leased acreage. The value of all salvable materials and equipment shall be determined in accordance with the
provisions of Exhibit “C,” less the estimated cost of salvaging and the estimated cost of plugging and abandoning and restoring the surface. If such value is less than such costs, then the party assignor or lessor shall pay to the party
assignee or lessee the amount of such deficit. If the assignment or lease is in favor of more than one party, the interest shall be shared by such parties in the proportions that the interest of each bears to the total interest of all such parties.
If the interest of the parties to whom the assignment is to be made varies according to depth, then the interest assigned shall similarly reflect such variances. 
 Any assignment, lease or surrender made under this provision shall not reduce or change the assignor’s, lessor’s or surrendering party’s interest as it was immediately before the
assignment, lease or surrender in the balance of the Contract Area; and the acreage assigned, leased or surrendered, and subsequent operations thereon, shall not thereafter be subject to the terms and provisions of this agreement but shall be deemed
subject to an Operating Agreement in the form of this agreement. 
 B. Renewal or Extension of Leases: 

If any party secures a renewal or replacement of an Oil and Gas Lease or Interest subject to this agreement, then all other parties shall
be notified promptly upon such acquisition or, in the case of a replacement Lease taken before expiration of an existing Lease, promptly upon expiration of the existing Lease. The parties notified shall have the right for a period of thirty
(30) days following delivery of such notice in which to elect to participate in the ownership of the renewal or replacement Lease, insofar as such Lease affects lands within the Contract Area, by paying to the party who acquired it their
proportionate shares of the acquisition cost allocated to that part of such Lease within the Contract Area, which shall be in proportion to the interest held at that time by the parties in the Contract Area. Each party who participates in the
purchase of a renewal or replacement Lease shall be given an assignment of its proportionate interest therein by the acquiring party. 
 If some, but less than all, of the parties elect to participate in the purchase of a renewal or replacement Lease, it shall be owned by the parties who elect to participate therein, in a ratio based upon
the relationship of their respective percentage of participation in the Contract Area to the aggregate of the percentages of participation in the Contract Area of all parties participating in the purchase of such renewal or replacement Lease. The
acquisition of a renewal or replacement Lease by any or all of the parties hereto shall not cause a readjustment of the interests of the parties stated in Exhibit “A,” but any renewal or replacement Lease in which less than all parties
elect to participate shall not be subject to this agreement but shall be deemed subject to a separate Operating Agreement in the form of this agreement. 
 If the interests of the parties in the Contract Area vary according to depth, then their right to participate proportionately in renewal or replacement Leases and their right to receive an assignment of
interest shall also reflect such depth variances. 
 The provisions of this Article shall apply to renewal or replacement Leases
whether they are for the entire interest covered by the expiring Lease or cover only a portion of its area or an interest therein. Any renewal or replacement Lease taken before the expiration of its predecessor Lease, or taken or contracted for or
becoming effective within six (6) months after the expiration of the existing Lease, shall be subject to this provision so long as this agreement is in effect at the time of such acquisition or at the time the renewal or replacement Lease
becomes effective; but any Lease taken or contracted for more than six (6) months after the expiration of an existing Lease shall not be deemed a renewal or replacement Lease and shall not be subject to the provisions of this agreement.

 The provisions in this Article shall also be applicable to extensions of Oil and Gas Leases. 

C. Acreage or Cash Contributions: 
 While this agreement is in force, if any party contracts for a contribution of cash towards the drilling of a well or any other operation on the Contract Area, such contribution shall be paid to the party
who conducted the drilling or other operation and shall be applied by it against the cost of such drilling or other operation. If the contribution be in the form of acreage, the party to whom the contribution is made shall promptly tender an
assignment of the acreage, without warranty of title, to the Drilling Parties in the proportions said Drilling Parties shared the cost of drilling the well. Such acreage shall become a separate Contract Area and, to the extent possible, be governed
by provisions identical to this agreement. Each party shall promptly notify all other parties of any acreage or cash contributions it may obtain in support of any well or any other operation on the Contract Area. The above provisions shall also be
applicable to optional rights to earn acreage outside the Contract Area which are in support of well drilled inside Contract Area. 

  
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 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

 

 If any party contracts for any consideration relating to disposition of such
party’s share of substances produced hereunder, such consideration shall not be deemed a contribution as contemplated in this Article VIII.C. 
 D. Assignment; Maintenance of Uniform Interest Disposition of Interests: 
 For the purpose of maintaining uniformity of ownership in the Contract Area in the Oil and Gas Leases, Oil and Gas Interests, wells, equipment and production covered by this agreement no party
shall sell, encumber, transfer or make other disposition of its interest in the Oil and Gas Leases and Oil and Gas Interests embraced within the Contract Area or in wells, equipment and production unless such disposition covers either:

 1. the entire interest of the party in all Oil and Gas Leases, Oil and Gas Interest, wells, equipment and production;
or 
 2. an equal undivided percent of the party’s present interest in all Oil and Gas Leases, Oil and Gas
Interests, wells, equipment and production in the Contract Area. 
 Every sale, encumbrance, transfer or other
disposition made by any party shall be made expressly subject to this agreement and shall be made without prejudice to the right of the other parties, and any transferee of an ownership interest in any Oil and Gas Lease or Interest shall be deemed a
party to this agreement as to the interest conveyed from and after the effective date of the transfer of ownership; provided, however, that the other parties shall not be required to recognize any such sale, encumbrance, transfer or other
disposition for any purpose hereunder until thirty (30) days after they have received a copy of the instrument of transfer or other satisfactory evidence thereof in writing from the transferor or transferee. No assignment or other disposition
of interest by a party shall relieve such party of obligations previously incurred by such party hereunder with respect to the interest transferred, including without limitation the obligation of a party to pay all costs attributable to an operation
conducted hereunder in which such party has agreed to participate prior to making such assignment, and the lien and security interest granted by Article. VII.B. shall continue to burden the interest transferred to secure payment of any such
obligations. 
 If, at any time the interest of any party is divided among and owned by four or more co-owners, Operator, at its
discretion, may require such co-owners to appoint a single trustee or agent with full authority to receive notices, approve expenditures, receive billings for and approve and pay such party’s share of the joint expenses, and to deal generally
with, and with power to bind, the co-owners of such party’s interest within the scope of the operations embraced in this agreement; however, all such co-owners shall have the right to enter into and execute all contracts or agreements for the
disposition of their respective shares of the Oil and Gas produced from the Contract Area and they shall have the right to receive, separately, payment of the sale proceeds thereof. 
 E. Waiver of Rights to Partition: 
 If permitted by the laws of the state or
states in which the property covered hereby is located, each party hereto owning an undivided interest in the Contract Area waives any and all rights it may have to partition and have set aside to it in severalty its undivided interest therein.

 F. Preferential Right to Purchase: 
  

	 ̈	(Optional; Check if applicable.) 

 Should any party desire to sell all or any part of its interests under this agreement, or its rights and interests in the Contract Area, it shall promptly give written notice to the other parties,
with full information concerning its proposed disposition, which shall include the name and address of the prospective transferee (who must be ready, willing and able to purchase), the purchase price, a legal description sufficient to identify the
property, and all other terms of the offer. The other parties shall then have an optional prior right, for a period of ten (10) days after the notice is delivered, to purchase for the stated consideration on the same terms and conditions the
interest which the other party proposes to sell; and, if this optional right is exercised, the purchasing parties shall share the purchased interest in the proportions that the interest of each bears to the total interest of all purchasing parties.
However, there shall be no preferential right to purchase in those cases where any party wishes to mortgage its interest, or to transfer title to its interests to its mortgage in lieu of or pursuant to foreclosure of a mortgage of its interests, or
to dispose of its interests by merger, reorganization, consolidation, or by sale of all or substantially all of its Oil and Gas assets to any party, or by transfer of its interests to a subsidiary or parent company or to a subsidiary of a parent
company, or to any company in which such party owns a majority of the stock. 
 ARTICLE IX. 

INTERNAL REVENUE CODE ELECTION 
 If, for federal income tax purposes, this agreement and the operations hereunder are regarded as a partnership, and if the parties have not otherwise agreed to form a tax partnership pursuant to Exhibit
“G” or other agreement between them, each party thereby affected elects to be excluded from the application of all of the provisions of Subchapter “K,” Chapter 1, Subtitle “A,” of the Internal Revenue Code of 1986, as
amended (“Code”), as permitted and authorized by Section 761 of the Code and the regulations promulgated thereunder. Operator is authorized and directed to execute on behalf of each party hereby affected such evidence of this election
as may be required by the Secretary of the Treasury of the United States or the Federal Internal Revenue Service, including specifically, but not by way of limitation, all of the returns, statements, and the data required by Treasury Regulation
§1.761. Should there be any requirement that each party hereby affected give further evidence of this election, each such party shall execute such documents and furnish such other evidence as may be required by the Federal Internal Revenue
Service or as may be necessary to evidence this election. No such party shall give any notices or take any other action inconsistent with the election made hereby. If any present or future income tax laws of the state or states in which the Contract
Area is located or any future income tax laws of the United States contain provisions similar to those in Subchapter “K,” Chapter 1, Subtitle “A,” of the Code, under which an election similar to that provided by Section 761
of the Code is permitted, each party hereby affected shall make such election as may be permitted or required by such laws. In making the foregoing election, each such party states that the income derived by such party from operations hereunder can
be adequately determined without the computation of partnership taxable income. 
 ARTICLE X. 

CLAIMS AND LAWSUITS 
 Operator may settle any single uninsured third party damage claim or suit arising from operations hereunder if the expenditure does not exceed Fifty Thousand Dollars ($ 50,000.00) and if the
payment is in complete settlement of such claim or suit. If the amount required for settlement exceeds the above amount, the parties hereto shall assume and take over the further handling of the claim or suit, unless such authority is delegated to
Operator. All costs and expenses of handling settling, or otherwise discharging such claim or suit shall be a the joint expense of the parties participating in the operation from which the claim or suit arises. If a claim is made against any party
or if any party is sued on account of any matter arising from operations hereunder over which such individual has no control because of the rights given Operator by this agreement, such party shall immediately notify all other parties, and the claim
or suit shall be treated as any other claim or suit involving operations hereunder. 

  
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 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

 

 ARTICLE XI. 

FORCE MAJEURE 
 If any party is rendered unable, wholly or in part, by force majeure to carry out its obligations under this agreement, other than the obligation to indemnify or make money payments or furnish security,
that party shall give to all other parties prompt written notice of the force majeure with reasonably full particulars concerning it; thereupon, the obligations of the party giving the notice, so far as they are affected by the force majeure, shall
be suspended during, but no longer than, the continuance of the force majeure. The term “force majeure,” as here employed, shall mean an act of God, strike, lockout, or other industrial disturbance, act of the public enemy, war, blockade,
public riot, lightening, fire, storm, flood or other act of nature, explosion, governmental action, governmental delay, restraint or inaction, unavailability of equipment, and any other cause, whether of the kind specifically enumerated above or
otherwise, which is not reasonably within the control of the party claiming suspension. 
 The affected party shall use all
reasonable diligence to remove the force majeure situation as quickly as practicable. The requirement that any force majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes, lockouts, or other labor
difficulty by the party involved, contrary to its wishes; how all such difficulties shall be handled shall be entirely within the discretion of the party concerned. 
 ARTICLE XII. 
 NOTICES 

All notices authorized or required between the parties by any of the provisions of this agreement, unless otherwise specifically
provided, shall be in writing and delivered in person or by United States mail, courier service, telegram, telex, telecopier or any other form of facsimile, postage or charges prepaid, and addressed to such parties at the addresses listed on Exhibit
“A.” All telephone or oral notices permitted by this agreement shall be confirmed immediately thereafter by written notice. The originating notice given under any provision hereof shall be deemed delivered only when received by the party
to whom such notice is directed, and the time for such party to deliver any notice in response thereto shall run from the date the originating notice is received. “Receipt” for purposes of this agreement with respect to written notice
delivered hereunder shall be actual delivery of the notice to the address of the party to be notified specified in accordance with this agreement, or to the telecopy, facsimile or telex machine of such party. The second or any responsive notice
shall be deemed delivered when deposited in the United States mail or at the office of the courier or telegraph service, or upon transmittal by telex, telecopy or facsimile, or when personally delivered to the party to be notified, provided, that
when response is required within 24 or 48 hours, such response shall be given orally or by telephone, telex, telecopy or other facsimile within such period. Each party shall have the right to change its address at any time, and from time to time, by
giving written notice thereof to all other parties. If a party is not available to receive notice orally or by telephone when a party attempts to deliver a notice required to be delivered within 24 or 48 hours, the notice may be delivered in writing
by any other method specified herein and shall be deemed delivered in the same manner provided above for any responsive notice. 

ARTICLE XIII, 
 TERM OF AGREEMENT 
 This agreement shall remain in full force and effect as
to the Oil and Gas Leases and/or Oil and Gas Interests subject hereto for the period of time selected below; provided, however, no party hereto shall ever be construed as haying any right, title or interest in or to any Lease or Oil and Gas Interest
contributed by any other party beyond the term of this agreement. 
  

	 	 ̈x	Option No. 1: So long as any of the Oil and Gas Leases subject to this agreement remain or are continued in force as to any part of the Contract Area,
whether by production, extension, renewal or otherwise. 

  

	 	 ̈	Option No. 2: In the event the well described in Article VI.A., or any subsequent well drilled under any provision of this
agreement, results in the Completion of a well as a well capable of production of Oil and/or Gas in paying quantities, this agreement shall continue in force so long as any such well is capable of production, and for an additional period of
             days thereafter; provided, however, if, prior to the expiration of such additional period, one or more of the parties hereto are engaged in drilling, Reworking, Deepening,
Sidetracking, Plugging Back, testing or attempting to Complete or Re-complete a well or wells hereunder, this agreement shall continue in force until such operations have been completed and if production results therefrom this agreement shall
continue in force as provided herein. In the event the well described in Article VI.A., or any subsequent well drilled hereunder, results in a dry hole, and no other well is capable of producing Oil and/or Gas from the Contract Area, this agreement
shall terminate unless drilling, Deepening, Sidetracking, Completing, Re-completing, Plugging Back or Reworking operations are commenced within              days from the date of
abandonment of said well. “Abandonment” for such purposes shall mean either (i) a decision by all parties not to conduct any further operations on the well or (ii) the elapse of 180 days from the conduct of any operations on the
well, whichever first occurs. 

 The termination of this agreement shall not relieve any party hereto
from any expense, liability or other obligation or any remedy therefor which has accrued or attached prior to the date of such termination. 
 Upon termination of this agreement and the satisfaction of all obligations hereunder, in the event a memorandum of this Operating Agreement has been filed of record, Operator is authorized to file of
record in all necessary recording offices a notice of termination, and each party hereto agrees to execute such a notice of termination as to Operator’s interest, upon request of Operator, if Operator has satisfied all its financial
obligations. 
 ARTICLE XIV. 
 COMPLIANCE WITH LAWS AND REGULATIONS 
 A. Laws, Regulations and Orders: 

This agreement shall be subject to the applicable laws of the state in which the Contract Area is located, to the valid rules,
regulations, and orders of any duly constituted regulatory body of said state; and to all other applicable federal, state, and local laws, ordinances, rules, regulations and orders. 
 B. Governing Law: 
 This agreement and all matters pertaining hereto,
including but not limited to matters of performance, non-performance, breach, remedies, procedures, rights, duties, and interpretation or construction, shall be governed and determined by the law of the state in which the Contract Area is located.
If the Contract Area is in two or more states, the law of the state of Colorado shall govern. 
 C. Regulatory Agencies:

 Nothing herein contained shall grant, or be construed to grant, Operator the right or authority to waive or release any
rights, privileges, or obligations which Non-Operators may have under federal or state laws or under rules, regulations or orders promulgated under such laws in reference to oil, gas and mineral operations, including the location, operation, or
production of wells, on tracts offsetting or adjacent to the Contract Area. 

  
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 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

 

 With respect to the operations hereunder, Non-Operators agree to release Operator from
any and all losses, damages, injuries, claims and causes of action arising out of, incident to or resulting directly or indirectly from Operator’s interpretation or application of rules, rulings, regulations or orders of the Department of
Energy, Internal Revenue Service, or Federal Energy Regulatory Commission or predecessor or successor agencies to the extent such interpretation or application was made in good faith and does not constitute gross negligence. Each Non-Operator
further agrees to reimburse Operator for such Non-Operator’s share of production or any refund, fine, levy or other governmental sanction that Operator may be required to pay as a result of such an incorrect interpretation or application,
together with interest and penalties thereon owing by Operator as a result of such incorrect interpretation or application. 

ARTICLE XV. 

MISCELLANEOUS 
 A.
Execution: 
 This agreement shall be binding upon each Non-Operator when this agreement: or a counterpart thereof has been
executed by such Non-Operator and Operator notwithstanding that this agreement is not then or thereafter executed by all of the parties to which it is tendered or which are listed on Exhibit “A” as owning an interest in the Contract Area
or which own, in fact, an interest in the Contract Area. Operator may, however, by written notice to all Non-Operators who have become bound by this agreement as aforesaid, given at any time prior to the actual spud date of the Initial Well but in
no event later than five days prior to the date specified in Article VI.A. for commencement of the Initial Well, terminate this agreement if Operator in its sole discretion determines that there is insufficient participation to justify commencement
of drilling operations. In the event of such a termination by Operator, all further obligations of the parties hereunder shall cease as of such termination. In the event any Non-Operator has advanced or prepaid any share of drilling or other costs
hereunder, all sums so advanced shall be returned to such Non-Operator without interest. In the event Operator proceeds with drilling operations for the Initial Well without the execution hereof by all persons listed on Exhibit “A” as
having a current working interest in such well, Operator shall indemnify Non-Operators with respect to all costs incurred for the Initial Well which would have been charged to such person under this agreement if such person had executed the same and
Operator shall receive all revenues which would have been received by such person under this agreement if such person had executed the same. 

B. Successors and Assigns: 
 This agreement shall be binding upon and shall inure to the benefit of the parties hereto and their respective heirs, devisees, legal representatives, successors and assigns, and the terms hereof shall be
deemed to run with the Leases or Interests included within the Contract Area. 
 C. Counterparts: 

This instrument may be executed in any number of counterparts, each of which shall be considered an original for all purposes. 

D. Severability: 
 For
the purposes of assuming, or rejecting this agreement as an executory contract pursuant to federal bankruptcy laws, this agreement shall not be severable, but rather must be assumed or rejected in its entirety, and the failure of any party to this
agreement to comply with all of its financial obligations provided herein shall be a material default. 
 ARTICLE XVI.

 OTHER PROVISIONS 
 Article 1.F (Continued from line 27) The term “Producing Unit” means the area or acreage required by the applicable governmental authority to be attributed to a well, or in the case of
horizontal wells, to a wellbore. A “Unit” is, as appropriate, a Drilling Unit or a Producing Unit. If a Drilling Unit or Producing Unit is not fixed by any such rule or order, a Drilling Unit or Producing Unit shall be the drilling unit as
established by the pattern of drilling in the Contract Area unless fixed by express agreement of the Drilling Parties. 
 Article I.G.
(Continued from line 30)...and in the case of horizontal or multi-lateral well shall be the oil and gas lease or leases or interests within the spacing or drilling unit on which the surface location and wellbore are located.

 Article I.S. (Additional Definitions S. to Z. continued from line 56) The term “lateral” shall mean that portion of a
wellbore that deviates from approximately vertical orientation to approximately horizontal orientation and all wellbore beyond such deviation to a total depth. 
 T. The term “horizontal” shall mean a well containing a single lateral in which the wellbore deviates from approximately vertical orientation to approximately horizontal orientation in order
to drill within and test a specific geological interval, utilizing deviation equipment, services and technology. This shall include similar operations conducted in the re-entry of an existing wellbore. 

U. The term “multi-lateral well” shall mean a well which contains more than one lateral and in which the wellbore deviate from approximately
vertical orientation to approximately horizontal orientation in order to drill within and test a specific geological interval, utilizing deviation equipment, services and technology. This shall include similar operations conducted in the re-entry of
an existing wellbore. 
 V. The term “total depth” shall apply to all horizontal or multi-lateral wells drilled pursuant to
this Agreement and shall mean the length of the wellbore from the surface of the ground to the terminus of the wellbore. Each lateral together with the common vertical wellbore shall be considered a single wellbore and shall have a corresponding
total depth if the production from lateral is to be measured separately and not commingled in the vertical wellbore. If production from each lateral is to be commingled in the common vertical wellbore then the lateral(s) and vertical wellbore shall
be considered collectively as a single wellbore. When the proposed operation is the drilling of, or operations on, a well containing a lateral component, the term “depth” wherever used in the Agreement shall be deemed to read “total
depth” measured insofar as it applied to such well. 
 W. The term “deepen” when used in conjunction with a horizontal or
multi-lateral well shall mean an operation whereby a lateral is drilled to a distance greater than the distance set out in the proposed total depth. 
 X. For the purpose of the Agreement, as to a horizontal or multi-lateral well, the term “plug back” shall mean an operation to test or complete the well at a stratigraphically shallower
geological horizon in which an operation has been or is being completed and which is not within an existing lateral. 
 Y. As to any
possible conflicts that may arise during the completion phase of a horizontal or multi-lateral well, priority shall be given first to the horizontal lateral component within the objective formation, and then to objective formations in ascending
order above the authorized depth, and then to objective formations in descending order below the authorized depth. 
 Z. Operator shall
have the right to cease drilling a horizontal well at any time, for any reason, and such horizontal well shall be deemed to have reached its objective depth so long as Operator has drilled such horizontal well to the objective formation and has been
drilled laterally in the objective formation for a distance which is at least equal to fifty percent (50%) of the length of the total horizontal lateral component displacement (displacement from true vertical orientation) proposed for the
operation. 
 Article V.C. (Continued from line 57) Notwithstanding the foregoing, no field hands, employees or contractors on
site shall have the authority to execute a receipt, field ticket or other document containing release or indemnification language, and in the event such a receipt, field ticket or other document is executed by a field hand, employees or contractor
on site, any language purporting to release the service or material provider from liability or purporting to indemnify the service or material provider or to modify the terms of any applicable master service agreement shall not be binding on
Operator or the joint account. 
 Article VI.B.5. (Additional Language inserted at line 51)(This paragraph shall not be applicable
to operations in the lateral portion of a horizontal or multi-lateral well. Drilling operations which are intended to recover penetration of the target interval which are conducted in a horizontal or multi-lateral well shall be considered as
included in the original proposed drilling operations. 
 Article V1.E.2. (Additional Language inserted at line 17)...who then
have an interest in such well; provided, however, if in the judgment of the Operator, the well poses a significant hazard, such as hydrogen sulfide, the Operator may plug and abandon the well and charge such costs to the joint account,
notwithstanding the objection of a party. 
  

	A.	Operator Contribution. Operator shall contribute its Working Interest share of 5/7th of the Federal 6-7-16-21 Well, which was drilled within the Contract Area prior
to the date of this Agreement (the “Existing Well”) to the tax partnership created by this Agreement. Operator’s proportionate share of actual expenses to drill the Existing Well is $1,147,779.43. 


  
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 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

 


	B.	Tranche 1 Drilling Program. 

  

	 	(i)	Carried Interest. Non-Operator will contribute 100% of the capital, estimated to be $6,500,000, (the “Drilling Funds”), to fund Operators Working
Interest share (which is 5/7th) of the cost to (i) drill and complete three new well within the Contract Area at a location to be determined by Operator and (ii) complete the Existing Well (collectively, the “Tranche 1 Drilling
Program”). The new Tranche 1 wells and the Existing Well are individually referred to as a “Tranche 1 Well” and collectively as, the “Tranche 1 Wells.” Drilling and completion operations shall commence as soon as
practicable, but in no event shall the spud date of any of the Tranche Wells be later than 90 days from the date of this Agreement, the date of first production from the Tranche 1 Wells is anticipated in May 2013. 


 

	 	(ii)	Put Option. Beginning on the date that the last drilled and completed Tranche 1 Well has been producing oil or gas for 36 calendar months and continuing for
30 days thereafter (the “Put Option Period”). Non-Operator shall have the right by providing written notice to operator prior to expiration of the Put Option Period to require Operator to purchase all, but not less than all, of
Non-Operator s Working Interest share in the Tranche 1 Wells within 90 days of receiving Non-Operator’s written notice at the purchase price calculated as follows: 


75% of Non-Operator’s actual capital investment in the Tranche 1 Wells less 75% of the revenue received by Non-Operator for
sales of production during the first 36 calendar months for such Tranche 1 Wells, plus a “top up” amount. The “top up” amount shall be calculated to return 75% of the capital invested by Non-Operator and to create a total BFIT
rate of return of 8% for 75% of the Non-Operator capital invested. The return calculation shall be based on monthly cash flows. 
  

	 	(iii)	Change of Control Put Option. If at any time Operator plans to divest greater than 51% of its Working Interest in the Leases to a third-party and resign as
Operator (a “Change of Control Event’’). Operator shall notify Non-Operator in writing (a “Change of Control Notice”) at least 60 days prior to closing of a change of Control Event. Non-Operator shall have the right by
providing written notice to Operator within 15 days of receipt of the Change of Control Notice to require operator to purchase all, but not less than all, of Non-Operator’s interest in the Tranche 1 Wells. The purchase price shall be equal to
the PV12 of the expected net revenue from the Tranche 1 Wells as determined by a third party evaluator selected by the parties. The parties shall share the expense or the third party evaluator 50/50. 


 

	C.	Tranche 2 Drilling Program and Tranche 3 Drilling Program. 

  

	 	(i)	Tranche 2 Drilling Program. At the end of the 24th month of production obtained from the Tranche 1 Drilling Program, Non- Operator shall have the right, but
not the obligation, by providing written notice to Operator within 30 days thereof to elect to invest an additional $5,000,000 in Operator’s next drilling program (the “Tranche 2 Drilling Program”) within the Contract Area; provided
however, that if the Tranche 2 Drilling Program consists of four wells or less. Non-Operator shall have a onetime option to elect to defer the decision on the Tranche 2 Drilling Program until such time that a Tranche 2 Drilling Program consisting of
more than four wells is presented to Non-Operator. 

  

	 	(ii)	Tranche 3 Drilling Program. On the two year anniversary of electing to invest in the Tranche 2 Drilling Program. Non-Operator shall have the right, but not
the obligation, by providing written notice to Operator within 30 days thereof, to elect to invest an additional $5,000000 in Operator’s next drilling program (the “Tranche 3 Drilling Program”) within the Contract Area. For the
avoidance of doubt. Non-Operator’s right to elect to participate in the Tranche 3 Drilling Program is contingent upon Non- Operator electing to participate fully in the Tranche 2 Drilling Program. 


 

	 	(iii)	Cap on Non-Operator’s Investment. Non-Operator’s total investment in the Tranche 1, Tranche 2 and Tranche 3 Drilling Programs shall not exceed
$15,000,000. 

  

	 	(iv)	Carried Interest. Non-Operator shall carry Operator’s interest in all wells or partial wells drilled in the Tranche 2 and Tranche 3 Drilling Programs in
an amount equal to 10% of Non-Operator’s Working Interest in such wells. 

  

	 	(v)	Drilling at Operator’s Election. Drilling and completing wells in the Tranche 2 and Tranche 3 Drilling Programs shall be done at Operator’s election
and only in conjunction with Operator’s existing plans for development of the Contract Area. If no drilling opportunity exists in the year Non-Operator exercises its option to participate in the Tranche 2 or Tranche 3 Drilling Program.
Non-Operator’s election shall not be extinguished, but shall remain In effect until Operator presents a drilling plan to Non-Operator for the respective Drilling Program. 


 

	D.	Cost Overruns / No Refunds. Should actual costs to drill and complete the wells in the Tranche 1 Drilling Program. Tranche 2 Drilling Program or the Tranche 3
Uniting Program exceed the estimated amounts set forth in subsection B.(i). subsection C.(i) or subsection C.(ii), respectively. Operator shall be solely responsible for payment or such excess costs. Regardless of whether the Tranche 1 Drilling
Program comes in under budget, in no event shall any or all of the Prepaid Drilling Funds be refunded to operator or Non-Operator. 

  

	E.	Production and Revenue Sharing. Subject to Article XVI.F. Operator and Non-Operator shall share in the production from the Tranche 1 Wells, and provided
Non-Operator elects to invest in the Tranche 2 Drilling Program and Tranche 5 Drilling Program, any wells drilled within such Tranche 2 and Tranche 3 Drilling Programs, in proportion to their respective investments in such Drilling Programs.
Production from the Leases shall be sold by Operator pursuant to contracts between Operator and purchaser. Revenue from the sale of production shall be received by Operator and Operator shall remit to Non-Operator its Working Interest share of such
revenue, less Non-Operator’s proportionate share of royalty payments, overriding royalty payments, production payments production taxes and any other production payment obligation of Non-operator, including the facility throughput Fee described
in Article XVI. G below. 

  

	F.	Payout / Back-in Rights. Upon Non-Operator receiving gross revenue equal to 125% of its capital investment (“Payout”) in the Tranche 1 Drilling
Program. Tranche 2 Drilling Program or Tranche 3 Drilling Program, individually and not collectively. Operator’s Working interest in the applicable Drilling Program shall automatically be increased by an amount equal to 25% of
Non-Operator’s Working interest in such Drilling Program. For example, if Non-Operator’s Working Interest in the Tranche 1 Drilling Program is 80%, upon Payout, Operator’s Working Interest in the Tranche 1 Wells shall be increased to
40% (20% + (25% x 80%)). 

  

	G.	Facility Throughput Fee. Non-Operator shall pay Operator a fee (the “Facility Throughput Fee”) to cover Operator’s cost of capital to construct
production infrastructure. The Facility Throughput Fee shall commence on the first day of production of a Tranche 1 Well and continue for the life of each well drilled under any of the Drilling Programs in which Non-Operator elects to participate.
The initial Facility throughput Fee shall be $0.20 per MMCF. The Facility throughput Fee shall escalate annually on January 1 of each year percentage increase in the consumer Price Index for Utilities (CPI-U). The Facility Throughout Fee shall
be in addition to all amounts due and payable under the terms of the Agreement for the costs of operating the wells and Leases. If, in the future, compression shall be required to be installed on the Contract Area, the capital costs to acquire and
install such compression shall be allocated to all Working interest owners in proportion to their allocated share of production and will be in addition to the Facility Throughput Fee. 


 

	H.	Prepayment of Drilling Costs. Upon execution of this Agreement Non-Operator shall pay by wire transfer the Drilling Funds directly to Operator’s
drilling general contractor. Operator shall cause the drilling general contractor (referenced in subparagraph I, below) to provide Non-Operator with a demand letter for prepayment of the Drilling Funds. 


 

	I.	Agreement with Drilling General Contractor. Contemporaneously with the execution of this Agreement. Operator shall enter into an agreement with the general
contractor selected by Operator (the “Drilling contractor Agreement”) setting forth the drilling and completion requirements for the Tranche 1 Wells and such other terms and conditions Operator may agree to in its reasonable judgment. The
drilling general contractor is requiring prepayment of the Drilling Funds as a material inducement to enter into the Drilling Contractor Agreement. 


  
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 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

 

 IN WITNESS WHEREOF, this agreement shall be effective as of the 31st day of
December     , 2012. 

                    , who has prepared and circulated
this form for execution, represents and warrants that the form was printed from and, with the exception(s) listed below, is identical to the AAPL Form 610-1989 Model Form Operating Agreement, as published in computerized form by Forms On-A-Disk,
Inc. No changes, alterations, or modifications, other than those made by strikethrough and/or insertion and that are clearly recognizable as changes in Articles
                                        , have
been made to the form. 
  

									
	ATTEST OR WITNESS:	 		 		 	OPERATOR
				
		 		 		 	 Dejour Energy (USA) Corp.

				
	  
	 		 	By	 	  

				
	  
	 		 		 	 Harrison F. Blacker

		 		 		 	Type or print name
					
		 		 		 	Title	 	 President

					
		 		 		 	Date	 	 December 31, 2012

					
		 		 		 	Tax ID or S.S. No.	 	 20-4321050

	  
 NON-OPERATORS

 

		 		 		 	 Bakken Drilling Fund III, LP

		 		 		 	 By:       Bakken Drilling Fund Manager LLC,
Its Managing General
Partner

				
	  
	 		 	By	 	




				
	  
	 		 		 	 Randall Kenworthy

		 		 		 	Type or print name
					
		 		 		 	Title	 	 Manager

					
		 		 		 	Date	 	 December 31, 2012

					
		 		 		 	Tax ID or S.S. No.	 	 45-3573043

				
		 		 		 	  

				
	  
	 		 	By	 	  

				
	  
	 		 		 	  

		 		 		 	Type or print name
					
		 		 		 	Title	 	  

					
		 		 		 	Date	 	  

					
		 		 		 	Tax ID or S.S. No.	 	  

				
		 		 		 	  

				
	  
	 		 	By	 	  

				
	  
	 		 		 	  

		 		 		 	Type or print name
					
		 		 		 	Title	 	  

					
		 		 		 	Date	 	  

					
		 		 		 	Tax ID or S.S. No.	 	  



  
 - 19 -










 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

 


							
	 Acknowledgment in representative capacity:
	  		  		  	
				
	 State of
Colorado                            
	  	)	  		  	
		  	)	  	ss.	  	
	 City and County of Denver             
	  	)	  		  	

 This instrument was acknowledged before me on December 31, 2012 by Randall Kenworthy
                     as Manager of Bakken Drilling Fund Manager LLC, the Managing General Partner of Bakken Drilling Fund III, LP.

  

							
	 (Seal, if any)
	 		 	




				
	 




	 		 	Title (and Rank)	 	 Notary Public

	 		 	My commission expires:	 	 04/18/2016

	 		 		 	
	 		 		 	


  
 - 19 -










 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

 

 IN WITNESS WHEREOF, this agreement shall be effective as of the 31st day of
December, 2012. 

                    , who has prepared and circulated
this form for execution, represents and warrants that the form was printed from and, with the exception(s) listed below, is identical to the AAPL Form 610-1989 Model Form Operating Agreement, as published in computerized form by Forms On-A-Disk,
Inc. No changes, alterations, or modifications, other than those made by strikethrough and/or insertion and that are clearly recognizable as changes in
Articles                    , have been made to the form. 
  

									
	ATTEST OR WITNESS:	 		 		 	OPERATOR
				
		 		 		 	 Dejour Energy (USA) Corp.

				
	  
	 		 	By	 	




				
	  
	 		 		 	 Harrison F. Blacker

		 		 		 	Type or print name
					
		 		 		 	Title	 	 President

					
		 		 		 	Date	 	 December 31, 2012

					
		 		 		 	Tax ID or S.S. No.	 	 20-4321050

	
	  
 NON-OPERATORS

 

		 		 		 	 Bakken Drilling Fund III, LP

		 		 		 	 By:       Bakken Drilling Fund Manager LLC,
Its Managing General
Partner

				
	  
	 		 	By	 	  

				
	  
	 		 		 	 Randall Kenworthy

		 		 		 	Type or print name
					
		 		 		 	Title	 	 Manager

					
		 		 		 	Date	 	 December 31, 2012

					
		 		 		 	Tax ID or S.S. No.	 	  

				
		 		 		 	  

				
	  
	 		 	By	 	  

				
	  
	 		 		 	  

		 		 		 	Type or print name
					
		 		 		 	Title	 	  

					
		 		 		 	Date	 	  

					
		 		 		 	Tax ID or S.S. No.	 	  

				
		 		 		 	  

				
	  
	 		 	By	 	  

				
	  
	 		 		 	  

		 		 		 	Type or print name
					
		 		 		 	Title	 	  

					
		 		 		 	Date	 	  

					
		 		 		 	Tax ID or S.S. No.	 	  



  
 - 19 -










 A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 

 

 ACKNOWLEDGMENTS 

Note: The following forms of acknowledgment are the short forms approved by the Uniform Law on Notarial Acts. The validity and effect of
these forms in any state will depend upon the statutes of that state. 
  

							
	Individual acknowledgment:
				
	 State
of                      
	 	)	 		  	
		 	)	 	ss.	  	
	 County of
                 
	 	)	 		  	

 This instrument was acknowledged before me on
                     by
                     
  

							
	(Seal, if any)	 		 	  

				
		 		 	Title (and Rank)	 	  

				
		 		 	My commission expires:	 	  


  

							
	 Acknowledgment in representative capacity:

				
	 State of Colorado
	 	)	 		  	
		 	)	 	ss.	  	
	 City and County of Denver
	 	)	 		  	

 This instrument was acknowledged before me on December 31, 2012 by Harrison F. Blacker
as President of Dejour Energy (USA) Corp. 
  

							
	 (Seal, if any)
	 		 	




				
	 




	 		 	Title (and Rank)	 	 Notary Public

	 		 	My commission expires:	 	 11/13/2016

	 		 		 	
	 		 		 	


  
 - 19 -









 EXHIBIT “A” 

Attached to and made a part of that certain Operating Agreement dated December 31, 2012, by and between Dejour Energy (USA) Corp.,
as Operator, and Bakken Drilling Fund III LP, as Non-Operator, collectively referred to herein as “Parties” or individually as “Party”. 
  

	(1)	Lands Subject to this Agreement (Contract Area): 

 Township 6 South, Range 91 West of the 6th P.M. 
 Section 13: W 1/2SW 
1/4; 

Section 14:
S 1/2; 
 Section 15: NW 1/4NE 1/4,
SW 1/4NE 1/4,
NE 1/4NW 1/4,
W 1/4NW 1/4,
SE 1/4NW 1/4,
N 1/2SW 1/4,
SE 1/4; 
 Section 21: E 1/2NE 
1/4, SE 1/4SW 1/4,
SW 1/4SE 1/4; 

Section 22:
SW 1/4NW 1/4,
W 1/4SW 1/4,
SE 1/4SW 1/4; 

Section 23:
NE 1/4, N 1/2NW 
1/4; 

Section 24:
NE 1/4NE 1/4,
W 1/4NE 1/4,
NW 1/4, N 1/2SE 
1/4; 

Section 25:
SE 1/4SE 1/4,
SW 1/4SW 1/4; 

Section 26:
S 1/2 
 Garfield County, CO 

 

	(2)	Restrictions as to Depths, Formations or Substances: 

 None 
  

	(3)	Percentages of Working Interest of the Parties: 

  

					
	 Parties
	  	Percentage Interest	 
		
	 Before Payout:
	  			
		
	 Dejour Energy (USA) Corp.
	  	 	[18%] of 71.4285714	% 
		
	 Bakken Drilling Fund III LP
	  	 	[82%] of 71.4285714	% 
		
	 After Payout:
	  			
		
	 Dejour Energy (USA) Corp.
	  	 	[40%] of 71.4285714	% 
		
	 Bakken Drilling Fund III LP
	  	 	[60%] of 71.4285714	% 

 In each case, the Percentage Interest is based upon the actual cost of $1,147,779.43 expended by Operator to drill the
Existing Well, and the estimated capital contribution of $6,500,000 by Non-Operator for the Tranche 1 Drilling Program. The Parties anticipate updating Exhibit A from time to time to reflect the Percentage Interest of the Parties based on actual
investments made by each Party during the performance of the Drilling Programs. 
 Parties to Agreement: 

Dejour Energy (USA) Corp. 
 Attn: Land Department 
 1401 17th Street, Suite 850 

Denver, CO 80202 

Ph (303) 296-3535; FAX (303) 296-3888 
 Bakken Drilling Fund III LP 
 Attn: Don Scott 

[Address] 

[Address] 
 Ph
(    )        -            ; FAX
(    )        -             
 Oil and Gas Lease(s) Subject to this Agreement: 
  

	1.	Serial Number: COC-066370 


Effective Date: 12/01/2002 
 Lessor: USA Federal DOI-BLM 
 Land Description: 

Township 6 South, Range 91 West of the 6th P.M. 
 Section 21: E 1/2NE 
1/4, SE 1/4SW 1/4,
SW 1/4SE 1/4; 

Section 22:
SW 1/4NW 1/4,
W 1/2SW 1/4,
SE 1/4SW 1/4; 

Section 25:
SW 1/4SW 1/4; 
 Section 26: S 1/2 
 Containing 680.00 acres, more or less, in 
 Garfield County, CO 








	2.	Serial Number: COC-065531 


Effective Date: 12/01/2001 
 Lessor: USA Federal DOI-BLM 
 Land Description: 

Township 6 South, Range 91 West of the 6th P.M. 
 Section 13: W1/2SW 1/4; 
 Section 14: S 1/2; 
 Section 15: NW 1/4NE 
1/4, SW 1/4NE 1/4,
NE 1/4NW 1/4,
W 1/2NW 1/4,
SE 1/4NW 1/4,
N 1/2SW 1/4,
SE 1/4; 
 Section 23: NE 1/4,
N 1/2NW 1/4; 
 Section 24: NE 1/4NE 
1/4, W 1/2NE 1/4,
NW 1/4, N 1/2SE 
1/4; 

Section 25:
SE 1/4SE 1/4 
 Containing 1,520.00 acres, more or less, in 
 Garfield County, CO 








			
	



	  	 COPAS 2005 Accounting Procedure
 Recommended by COPAS


 EXHIBIT “C” 

ACCOUNTING PROCEDURE 
 JOINT OPERATIONS 
  

	
	Attached to and made part of that certain Operating Agreement, dated effective December 31, 2012, by and between Dejour Energy
	 (USA) Corp., as Operator, and Bakken Drilling Fund III LP, as Non-Operator.

	  

	  

	  


 I. GENERAL PROVISIONS 
 IF THE PARTIES FAIL TO SELECT EITHER ONE OF COMPETING “ALTERNATIVE” PROVISIONS, OR SELECT ALL THE COMPETING “ALTERNATIVE” PROVISIONS, ALTERNATIVE 1 IN EACH SUCH INSTANCE SHALL BE
DEEMED TO HAVE BEEN ADOPTED BY THE PARTIES AS A RESULT OF ANY SUCH OMISSION OR DUPLICATE NOTATION. 
 IN THE EVENT THAT ANY
“OPTIONAL” PROVISION OF THIS ACCOUNTING PROCEDURE IS NOT ADOPTED BY THE PARTIES TO THE AGREEMENT BY A TYPED, PRINTED OR HANDWRITTEN INDICATION, SUCH PROVISION SHALL NOT FORM A PART OF THIS ACCOUNTING PROCEDURE, AND NO INFERENCE SHALL BE
MADE CONCERNING THE INTENT OF THE PARTIES IN SUCH EVENT. 
  

	1.	DEFINITIONS 

 All terms
used in this Accounting Procedure shall have the following meaning, unless otherwise expressly defined in the Agreement: 

“Affiliate” means for a person, another person that controls, is controlled by, or is under common control with that
person. In this definition, (a) control means the ownership by one person, directly or indirectly, of more than fifty percent (50%) of the voting securities of a corporation or, for other persons, the equivalent ownership interest (such as
partnership interests), and (b) “person” means an individual, corporation, partnership, trust, estate, unincorporated organization, association, or other legal entity. 

“Agreement” means the operating agreement, farmout agreement, or other contract between the Parties to which this
Accounting Procedure is attached. 
 “Controllable Material” means Material that, at the time of acquisition or
disposition by the Joint Account, as applicable, is so classified in the Material Classification Manual most recently recommended by the Council of Petroleum Accountants Societies (COPAS). 

“Equalized Freight” means the procedure of charging transportation cost to the Joint Account based upon the distance from
the nearest Railway Receiving Point to the property. 
 “Excluded Amount” means a specified excluded trucking
amount most recently recommended by COPAS. 
 “Field Office” means a structure, or portion of a structure,
whether a temporary or permanent installation, the primary function of which is to directly serve daily operation and maintenance activities of the Joint Property and which serves as a staging area for directly chargeable field personnel.

 “First Level Supervision” means those employees whose primary function in Joint Operations is the direct
oversight of the Operator’s field employees and/or contract labor directly employed On-site in a field operating capacity. First Level Supervision functions may include, but are not limited to: 

 

	 	•	 	 Responsibility for field employees and contract labor engaged in activities that can include field operations, maintenance, construction, well remedial
work, equipment movement and drilling 


  

	 	•	 	 Responsibility for day-to-day direct oversight of rig operations 



 

	 	•	 	 Responsibility for day-to-day direct oversight of construction operations 



 

	 	•	 	 Coordination of job priorities and approval of work procedures 



 

	 	•	 	 Responsibility for optimal resource utilization (equipment, Materials, personnel) 



 

	 	•	 	 Responsibility for meeting production and field operating expense targets 



 

	 	•	 	 Representation of the Parties in local matters involving community, vendors, regulatory agents and landowners, as an incidental part of the
supervisor’s operating responsibilities 


  

	 	•	 	 Responsibility for all emergency responses with field staff 



 

	 	•	 	 Responsibility for implementing safety and environmental practices 



 

	 	•	 	 Responsibility for field adherence to company policy 


  


	 	•	 	 Responsibility for employment decisions and performance appraisals for field personnel 



 

	 	•	 	 Oversight of sub-groups for field functions such as electrical, safety, environmental, telecommunications, which may have group or team leaders.



 “Joint Account” means the account showing the charges paid and credits received in the
conduct of the Joint Operations that are to be shared by the Parties, but does not include proceeds attributable to hydrocarbons and by-products produced under the Agreement. 
 “Joint Operations” means all operations necessary or proper for the exploration, appraisal, development, production, protection, maintenance, repair, abandonment, and restoration of the
Joint Property. 

  
 COPYRIGHT © 2005 by
Council of Petroleum Accountants Societies, Inc. (COPAS) 


  
 1 










			
	



	  	 COPAS 2005 Accounting Procedure
 Recommended by COPAS, Inc.


  

 “Joint Property” means the real and personal property subject to the
Agreement. 
 “Laws” means any laws, rules, regulations, decrees, and orders of the United States of America or
any state thereof and all other governmental bodies, agencies, and other authorities having jurisdiction over or affecting the provisions contained in or the transactions contemplated by the Agreement or the Parties and their operations, whether
such laws now exist or are hereafter amended, enacted, promulgated or issued. 
 “Material” means personal
property, equipment, supplies, or consumables acquired or held for use by the Joint Property. 
 “Non-Operators”
means the Parties to the Agreement other than the Operator. 
 “Offshore Facilities” means platforms, surface
and subsea development and production systems, and other support systems such as oil and gas handling facilities, living quarters, offices, shops, cranes, electrical supply equipment and systems, fuel and water storage and piping, heliport, marine
docking installations, communication facilities, navigation aids, and other similar facilities necessary in the conduct of offshore operations, all of which are located offshore. 

“Off-site” means any location that is not considered On-site as defined in this Accounting Procedure. 

“On-site” means on the Joint Property when in direct conduct of Joint Operations. The term “On-site” shall also
include that portion of Offshore Facilities, Shore Base Facilities, fabrication yards, and staging areas from which Joint Operations are conducted, or other facilities that directly control equipment on the Joint Property, regardless of whether such
facilities are owned by the Joint Account. 
 “Operator” means the Party designated pursuant to the Agreement to
conduct the Joint Operations. 
 “Parties” means legal entities signatory to the Agreement or their successors
and assigns. Parties shall be referred to individually as “Party.” 
 “Participating Interest” means
the percentage of the costs and risks of conducting an operation under the Agreement that a Party agrees, or is otherwise obligated, to pay and bear. 
 “Participating Party” means a Party that approves a proposed operation or otherwise agrees, or becomes liable, to pay and bear a share of the costs and risks of conducting an operation
under the Agreement. 
 “Personal Expenses” means reimbursed costs for travel and temporary living expenses.

 “Railway Receiving Point” means the railhead nearest the Joint Property for which freight rates are
published, even though an actual railhead may not exist. 
 “Shore Base Facilities” means onshore support
facilities that during Joint Operations provide such services to the Joint Property as a receiving and transshipment point for Materials; debarkation point for drilling and production personnel and services; communication, scheduling and dispatching
center; and other associated functions serving the Joint Property. 
 “Supply Store” means a recognized source
or common stock point for a given Material item. 
 “Technical Services” means services providing specific
engineering, geoscience, or other professional skills, such as those performed by engineers, geologists, geophysicists, and technicians, required to handle specific operating conditions and problems for the benefit of Joint Operations; provided,
however, Technical Services shall not include those functions specifically identified as overhead under the second paragraph of the introduction of Section III (Overhead). Technical Services may be provided by the Operator, Operator’s
Affiliate, Non-Operator, Non-Operator Affiliates, and/or third parties. 
  

	2.	STATEMENTS AND BILLINGS 


The Operator shall bill Non-Operators on or before the last day of the month for their proportionate share of the Joint Account for the
preceding month. Such bills shall be accompanied by statements that identify the AFE (authority for expenditure), lease or facility, and all charges and credits summarized by appropriate categories of investment and expense. Controllable Material
shall be separately identified and fully described in detail, or at the Operator’s option, Controllable Material may be summarized by major Material classifications. Intangible drilling costs, audit adjustments, and unusual charges and credits
shall be separately and clearly identified. 
 The Operator may make available to Non-Operators any statements and bills required
under Section I.2 and/or Section I.3.A (Advances and Payments by the Parties) via email, electronic data interchange, internet websites or other equivalent electronic media in lieu of paper copies. The Operator shall provide the Non-Operators
instructions and any necessary information to access and receive the statements and bills within the timeframes specified herein. A statement or billing shall be deemed as delivered twenty-four (24) hours (exclusive of weekends and holidays)
after the Operator notifies the Non-Operator that the statement or billing is available on the website and/or sent via email or electronic data interchange transmission. Each Non-Operator individually shall elect to receive statements and billings
electronically, if available from the Operator, or request paper copies. Such election may be changed upon thirty (30) days prior written notice to the Operator. 

  
 COPYRIGHT © 2005 by
Council of Petroleum Accountants Societies, Inc. (COPAS) 


  
 2 










			
	



	  	 COPAS 2005 Accounting Procedure
 Recommended by COPAS, Inc.


  


	3.	ADVANCES AND PAYMENTS BY THE PARTIES 

  

	 	A.	Unless otherwise provided for in the Agreement, the Operator may require the Non-Operators to advance their share of the estimated cash outlay for the succeeding
month’s operations within fifteen (15) days after receipt of the advance request or by the first day of the month for which the advance is required, whichever is later. The Operator shall adjust each monthly billing to reflect advances
received from the Non-Operators for such month. If a refund is due, the Operator shall apply the amount to be refunded to the subsequent month’s billing or advance, unless the Non-Operator sends the Operator a written request for a cash refund.
The Operator shall remit the refund to the Non-Operator within fifteen (15) days of receipt of such written request. 

  

	 	B.	Except as provided below, each Party shall pay its proportionate share of all bills in full within fifteen (15) days of receipt date. If payment is not made within
such time, the unpaid balance shall bear interest compounded monthly at the prime rate published by the Wall Street Journal on the first day of each month the payment is delinquent, plus three percent (3%), per annum, or the maximum contract
rate permitted by the applicable usury Laws governing the Joint Property, whichever is the lesser, plus attorney’s fees, court costs, and other costs in connection with the collection of unpaid amounts. If the Wall Street Journal ceases
to be published or discontinues publishing a prime rate, the unpaid balance shall bear interest compounded monthly at the prime rate published by the Federal Reserve plus three percent (3%), per annum. Interest shall begin accruing on the first day
of the month in which the payment was due. Payment shall not be reduced or delayed as a result of inquiries or anticipated credits unless the Operator has agreed. Notwithstanding the foregoing, the Non-Operator may reduce payment, provided it
furnishes documentation and explanation to the Operator at the time payment is made, to the extent such reduction is caused by: 

  

	 	(1)	being billed at an incorrect working interest or Participating Interest that is higher than such Non-Operator’s actual working interest or Participating Interest,
as applicable; or 

  

	 	(2)	being billed for a project or AFE requiring approval of the Parties under the Agreement that the Non-Operator has not approved or is not otherwise obligated to pay
under the Agreement; or 

  

	 	(3)	being billed for a property in which the Non-Operator no longer owns a working interest, provided the Non-Operator has furnished the Operator a copy of the recorded
assignment or letter in-lieu. Notwithstanding the foregoing, the Non-Operator shall remain responsible for paying bills attributable to the interest it sold or transferred for any bills rendered during the thirty (30) day period following the
Operator’s receipt of such written notice; or 

  

	 	(4)	charges outside the adjustment period, as provided in Section I.4 (Adjustments). 


 

	4.	ADJUSTMENTS 

  

	 	A.	Payment of any such bills shall not prejudice the right of any Party to protest or question the correctness thereof; however, all bills and statements, including payout
statements, rendered during any calendar year shall conclusively be presumed to be true and correct, with respect only to expenditures, after twenty-four (24) months following the end of any such calendar year, unless within said period a Party
takes specific detailed written exception thereto making a claim for adjustment. The Operator shall provide a response to all written exceptions, whether or not contained in an audit report, within the time periods prescribed in Section I.5
(Expenditure Audits). 

  

	 	B.	All adjustments initiated by the Operator, except those described in items (1) through (4) of this Section I.4.B, are limited to the twenty-four
(24) month period following the end of the calendar year in which the original charge appeared or should have appeared on the Operator’s Joint Account statement or payout statement. Adjustments that may be made beyond the twenty-four
(24) month period are limited to adjustments resulting from the following: 

  

	 	(1)	a physical inventory of Controllable Material as provided for in Section V (Inventories of Controllable Material), or 


 

	 	(2)	an offsetting entry (whether in whole or in part) that is the direct result of a specific joint interest audit exception granted by the Operator relating to another
property, or 

  

	 	(3)	a government/regulatory audit, or 

  

	 	(4)	a working interest ownership or Participating Interest adjustment. 

  

	5.	EXPENDITURE AUDITS 

  

	 	A.	A Non-Operator, upon written notice to the Operator and all other Non-Operators, shall have the right to audit the Operator’s accounts and records relating to the
Joint Account at any time during the calendar year in which such bill was rendered and within the twenty-four (24) month period following the end of such calendar year in which such bill was rendered; however, conducting an audit shall
not extend the time for the taking of written exception to and the adjustment of accounts as provided for in Section I.4 (Adjustments). Any Party that is subject to payout accounting under the Agreement shall have the right to audit the
accounts and records of the Party responsible for preparing the payout statements, or of the Party furnishing information to the Party responsible for preparing payout statements. Audits of payout accounts may include the volumes of hydrocarbons
produced and saved and proceeds received for such hydrocarbons as they pertain to payout accounting required under the Agreement. Unless otherwise provided in the Agreement, audits of a payout account shall be conducted within the twenty-four
(24) month period following the end of the calendar year in which the payout statement was rendered. 

 Where
there are two or more Non-Operators, the Non-Operators shall make every reasonable effort to conduct a joint audit in a manner that will result in a minimum of inconvenience to the Operator. The Operator shall bear no portion of the
Non-Operators’ audit cost incurred under this paragraph unless agreed to by the Operator. The audits shall not be conducted more than once each year without prior approval of the Operator, except upon the resignation deemed resignation
or removal of the Operator, and shall be made at the expense of those Non-Operators approving such audit. 

  
 COPYRIGHT © 2005 by
Council of Petroleum Accountants Societies, Inc. (COPAS) 


  
 3 










			
	



	  	 COPAS 2005 Accounting Procedure
 Recommended by COPAS, Inc.


  

 The Non-Operator leading the audit (hereinafter “lead audit company”) shall
issue the audit report within ninety (90) days after completion of the audit testing and analysis; however, the ninety (90) day time period shall not extend the twenty-four (24) month requirement for taking specific detailed written
exception as required in Section I.4.A (Adjustments) above. All claims shall be supported with sufficient documentation. 

A timely filed written exception or audit report containing written exceptions (hereinafter “written exceptions”) shall, with
respect to the claims made therein, preclude the Operator from asserting a statute of limitations defense against such claims, and the Operator hereby waives its right to assert any statute of limitations defense against such claims for so long as
any Non-Operator continues to comply with the deadlines for resolving exceptions provided in this Accounting Procedure. If the Non-Operators fail to comply with the additional deadlines in Section I.5.B or I.5.C, the Operator’s waiver of its
rights to assert a statute of limitations defense against the claims brought by the Non-Operators shall lapse, and such claims shall then be subject to the applicable statute of limitations, provided that such waiver shall not lapse in the event
that the Operator has failed to comply with the deadlines in Section I.5.B or I.5.C. 
  

	 	B.	The Operator shall provide a written response to all exceptions in an audit report within one hundred eighty (180) days after Operator receives such report. Denied
exceptions should be accompanied by a substantive response. If the Operator fails to provide substantive response to an exception within this one hundred eighty (180) day period, the Operator will owe interest on that exception or portion
thereof, if ultimately granted, from the date it received the audit report. Interest shall be calculated using the rate set forth in Section I.3.B (Advances and Payments by the Parties). 


 

	 	C.	The lead audit company shall reply to the Operator’s response to an audit report within ninety (90) days of receipt, and the Operator shall reply to the lead
audit company’s follow-up response within ninety (90) days of receipt; provided, however, each Non-Operator shall have the right to represent itself if it disagrees with the lead audit company’s position or believes the lead audit
company is not adequately fulfilling its duties. Unless otherwise provided for in Section I.5.E, if the Operator fails to provide substantive response to an exception within this ninety (90) day period, the Operator will owe interest on that
exception or portion thereof, if ultimately granted, from the date it received the audit report. Interest shall be calculated using the rate set forth in Section I.3.B (Advances and Payments by the Parties). 


 

	 	D.	If any Party fails to meet the deadlines in Sections I.5.B or I.5.C or if any audit issues are outstanding fifteen (15) months after Operator receives the audit
report, the Operator or any Non-Operator participating in the audit has the right to call a resolution meeting, as set forth in this Section I.5.D or it may invoke the dispute resolution procedures included in the Agreement, if applicable. The
meeting will require one month’s written notice to the Operator and all Non-Operators participating in the audit. The meeting shall be held at the Operator’s office or mutually agreed location, and shall be attended by representatives of
the Parties with authority to resolve such outstanding issues. Any Party who fails to attend the resolution meeting shall be bound by any resolution reached at the meeting. The lead audit company will make good faith efforts to coordinate the
response and positions of the Non-Operator participants, throughout the resolution process; however, each Non-Operator shall have the right to represent itself. Attendees will make good faith efforts to resolve outstanding issues, and each Party
will be required to present substantive information supporting its position. A resolution meeting may be held as often as agreed to by the Parties. Issues unresolved at one meeting may be discussed at subsequent meetings until each such issue is
resolved. 

 If the Agreement contains no dispute resolution procedures and the audit issues cannot be resolved by
negotiation, the dispute shall be submitted to mediation. In such event, promptly following one Party’s written request for mediation, the Parties to the dispute shall choose a mutually acceptable mediator and share the costs of mediation
services equally. The Parties shall each have present at the mediation at least one individual who has the authority to settle the dispute. The Parties shall make reasonable efforts to ensure that the mediation commences within sixty (60) days
of the date of the mediation request. Notwithstanding the above, any Party may file a lawsuit or complaint (1) if the Parties are unable after reasonable efforts, to commence mediation within sixty (60) days of the date of the mediation
request, (2) for statute of limitations reasons, or (3) to seek a preliminary injunction or other provisional judicial relief, if in its sole judgment an injunction or other provisional relief is necessary to avoid irreparable damage or to
preserve the status quo. Despite such action, the Parties shall continue to try to resolve the dispute by mediation. 
  

	 	E.	 ̈ (Optional Provision – Forfeiture Penalties) 


If the Non-Operators fail to meet the deadline in Section I.5.C, any unresolved exceptions that were not addressed by the Non-Operators
within one (1) year following receipt of the last substantive response of the Operator shall be deemed to have been withdrawn by the Non-Operators. If the Operator fails to meet the deadlines in Section I.5.B or I.5.C, any unresolved exceptions
that were not addressed by the Operator within one (1) year following receipt of the audit report or receipt of the last substantive response of the Non-Operators, whichever is later, shall be deemed to have been granted by the Operator and
adjustments shall be made, without interest, to the Joint Account. 
  

	6.	APPROVAL BY PARTIES 

  

	 	A.	GENERAL MATTERS 

 Where an
approval or other agreement of the Parties or Non-Operators is expressly required under other Sections of this Accounting Procedure and if the Agreement to which this Accounting Procedure is attached contains no contrary provisions in regard
thereto, the Operator shall notify all Non-Operators of the Operator’s proposal and the agreement or approval of a majority in interest of the Non-Operators shall be controlling on all Non-Operators. 

  
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 This Section I.6.A applies to specific situations of limited duration where a Party
proposes to change the accounting for charges from that prescribed in this Accounting Procedure. This provision does not apply to amendments to this Accounting Procedure, which are covered by Section I.6.B. 

 

	 	B.	AMENDMENTS 

 If the Agreement to
which this Accounting Procedure is attached contains no contrary provisions in regard thereto, this Accounting Procedure can be amended by an affirmative vote of two ( 2 ) or more Parties, one of which is the Operator, having a
combined working interest of at least seventy-five percent ( 75 %), which approval shall be binding on all Parties, provided, however, approval of at least one (1) Non-Operator shall be required. 

 

	 	C.	AFFILIATES 

 For the purpose of
administering the voting procedures: of Sections I.6.A and I.6.B, if Parties to this Agreement are Affiliates of each other, then such Affiliates shall be combined and treated as a single Party having the combined working interest or Participating
Interest of such Affiliates. 
 For the purposes of administering the voting procedures, in Section I.6.A, if a Non-Operator is
an Affiliate of the Operator, votes under Section I.6.A shall require the majority in interest of the Non-Operator(s) after excluding the interest of the Operator’s Affiliate. 

II. DIRECT CHARGES 
 The
Operator shall charge the Joint Account with the following items: 
  

	1.	RENTALS AND ROYALTIES 


Lease rentals and royalties paid by the Operator, on behalf of all Parties, for the Joint Operations. 

 

	2.	LABOR 

  

	 	A.	Salaries and wages, including incentive compensation programs as set forth in COPAS MFI-37 (“Chargeability of Incentive Compensation Programs”), for:


  

	 	(1)	Operator’s field employees directly employed On-site in the conduct of Joint Operations, 


 

	 	(2)	Operator’s employees directly employed on Shore Base Facilities, Offshore Facilities, or other facilities serving the Joint Property if such costs are not charged
under Section II.6 (Equipment and Facilities Furnished by Operator) or are not a function covered under Section III (Overhead), 

  

	 	(3)	Operator’s employees providing First Level Supervision, 

  

	 	(4)	Operator’s employees providing On-site Technical Services for the Joint Property if such charges are excluded from the overhead rates in Section III
(Overhead), 

  

	 	(5)	Operator’s employees providing Off-site Technical Services for the Joint Property if such charges are excluded from the overhead rates in Section III
(Overhead). 

 Charges for the Operator’s employees identified in Section II.2.A may be made based on
the employee’s actual salaries and wages, or in lieu thereof, a day rate representing the Operator’s average salaries and wages of the employee’s specific job category. 

Charges for personnel chargeable under this Section II.2.A who are foreign nationals shall not exceed comparable compensation paid to an
equivalent U.S. employee pursuant to this Section II.2, unless otherwise approved by the Parties pursuant to Section I.6.A (General Matters). 
  

	 	B.	Operator’s cost of holiday, vacation, sickness, and disability benefits, and other customary allowances paid to employees whose salaries and wages are chargeable
to the Joint Account under Section II.2.A, excluding severance payments or other termination allowances. Such costs under this Section II.2.B may be charged on a “when and as-paid basis” or by “percentage assessment” on the
amount of salaries and wages chargeable to the Joint Account under Section II.2.A. If percentage assessment is used, the rate shall be based on the Operator’s cost experience. 


 

	 	C.	Expenditures or contributions made pursuant to assessments imposed by governmental authority that are applicable to costs chargeable to the Joint Account under Sections
II.2.A and B. 


  
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	 	D.	Personal Expenses of personnel whose salaries and wages are chargeable to the Joint Account under Section II.2.A when the expenses are incurred in connection with
directly chargeable activities. 

  

	 	E.	Reasonable relocation costs incurred in transferring to the Joint Property personnel whose salaries and wages are chargeable to the Joint Account under Section II.2.A.
Notwithstanding the foregoing, relocation costs that result from reorganization or merger of a Party, or that are for the primary benefit of the Operator, shall not be chargeable to the Joint Account. Extraordinary relocation costs, such as those
incurred as a result of transfers from remote locations, such as Alaska or overseas, shall not be charged to the Joint Account unless approved by the Parties pursuant to Section I.6.A (General Matters). 


 

	 	F.	Training costs as specified in COPAS MFI-35 (“Charging of Training Costs to the Joint Account”) for personnel whose salaries and wages are chargeable under
Section II.2.A. This training charge shall include the wages, salaries, training course cost, and Personal Expenses incurred during the training session. The training cost shall be charged or allocated to the property or properties directly
benefiting from the training. The cost of the training course shall not exceed prevailing commercial rates, where such rates are available. 

  

	 	G.	Operator’s current cost of established plans for employee benefits, as described in COPAS MFI-27 (“Employee Benefits Chargeable to Joint Operations and
Subject to Percentage Limitation”), applicable to the Operator’s labor costs chargeable to the Joint Account under Sections II.2.A and B based on the Operator’s actual cost not to exceed the employee benefits limitation percentage
most recently recommended by COPAS. 

  

	 	H.	Award payments to employees, in accordance with COPAS MFI-49 (“Awards to Employees and Contractors”) for personnel whose salaries and wages are chargeable
under Section II.2.A. 

  

	3.	MATERIAL 

 Material
purchased or furnished by the Operator for use on the Joint Property in the conduct of Joint Operations as provided under Section IV (Material Purchases, Transfers, and. Dispositions). Only such Material shall be purchased for or transferred
to the Joint Property as may be required for immediate use or is reasonably practical and consistent with efficient and economical operations. The accumulation of surplus stocks shall be avoided. 

 

	4.	TRANSPORTATION 

  

	 	A.	Transportation of the Operator’s, Operator’s Affiliate’s, or contractor’s personnel necessary for Joint. Operations. 


 

	 	B.	Transportation of Material between the Joint Property and another property, or from the Operator’s warehouse or other storage point to the Joint Property, shall be
charged to the receiving property using one of the methods listed below. Transportation of Material from the Joint Property to the Operator’s warehouse or other storage point shall be paid for by the Joint Property using one of the methods
listed below: 

  

	 	(1)	If the actual trucking charge is less than or equal to the Excluded Amount the Operator may charge actual trucking cost or a theoretical charge from the Railway
Receiving Point to the Joint Property. The basis for the theoretical charge is the per hundred weight charge plus fuel surcharges from the Railway Receiving Point to the Joint Property. The Operator shall consistently apply the selected alternative.


  

	 	(2)	If the actual trucking charge is greater than the Excluded Amount, the Operator shall charge Equalized Freight. Accessorial charges such as loading and unloading costs,
split pick-up costs, detention, call out charges, and permit fees shall be charged directly to the Joint Property and shall not be included when calculating the Equalized Freight. 


 

	5.	SERVICES 

 The cost of
contract services, equipment, and utilities used in the conduct of Joint Operations, except for contract services, equipment, and utilities covered by Section III (Overhead), or Section II.7 (Affiliates), or excluded under Section II.9
(Legal Expense). Awards paid to contractors shall be chargeable pursuant to COPAS MFI-49 (“Awards to Employees and Contractors”). 
 The costs of third party Technical Services are chargeable to the extent excluded from the overhead rates under Section III (Overhead). 

 

	6.	EQUIPMENT AND FACILITIES FURNISHED BY OPERATOR 

 In the absence of a separately negotiated agreement, equipment and facilities furnished by the Operator will be charged as follows: 

 

	 	A.	 The Operator shall charge the Joint Account for use of Operator-owned equipment and facilities, including but not limited to production facilities,
Shore Base Facilities, Offshore Facilities, and Field Offices, at rates commensurate with the costs of ownership and operation. The cost of Field Offices shall be chargeable to the extent the Field Offices provide direct service to personnel who are
chargeable pursuant to Section II.2.A (Labor). Such rates may include labor, maintenance, repairs, other operating expense, insurance, taxes, depreciation using straight line depreciation method, and interest on gross investment less
accumulated depreciation not to exceed ten percent (10 %) per annum; provided, however, depreciation shall not be charged when the 



  
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equipment and facilities investment have been fully depreciated. The rate may include an element of the estimated cost for abandonment, reclamation, and dismantlement. Such rates shall not exceed
the average commercial rates currently prevailing in the immediate area of the Joint Property. 

  

	 	B.	In lieu of charges in Section II.6.A above, the Operator may elect to use average commercial rates prevailing in the immediate area of the Joint Property, less twenty
percent (20%). If equipment and facilities are charged under this Section II.6.B, the Operator shall adequately document and support commercial rates and shall periodically review and update the rate and the supporting documentation. For
automotive equipment, the Operator may elect to use rates published by the Petroleum Motor Transport Association (PMTA) or such other organization recognized by COPAS as the official source of rates. 


 

	7.	AFFILIATES 

  

	 	A.	Charges for an Affiliate’s goods and/or services used in operations requiring an AFE or other authorization from the Non-Operators may be made without the approval
of the Parties provided (i) the Affiliate is identified and the Affiliate goods and services are specifically detailed in the approved AFE or other authorization, and (ii) the total costs for such Affiliate’s goods and services billed
to such individual project do not exceed $ 25,000.00 If the total costs for an Affiliate’s goods and services charged to such individual project are not specifically detailed in the approved AFE or authorization or exceed such amount,
charges for such Affiliate shall require approval of the Parties, pursuant to Section I.6.A (General Matters). 

  

	 	B.	For an Affiliate’s goods and/or services used in operations not requiring an AFE or other authorization from the Non-Operators, charges for such Affiliate’s
goods and services shall require approval of the Parties, pursuant to Section I.6.A (General Matters), if the charges exceed $ 50,000.00 in a given calendar year. 


 

	 	C.	The cost of the Affiliate’s goods or services shall not exceed average commercial rates prevailing in the area of the Joint Property, unless the Operator obtains
the Non-Operators’ approval of such rates. The Operator shall adequately document and support commercial rates and shall periodically review and update the rate and the supporting documentation; provided, however, documentation of commercial
rates shall not be required if the Operator obtains Non-Operator approval of its Affiliate’s rates or charges prior to billing Non-Operators for such Affiliate’s goods and services. Notwithstanding the foregoing, direct charges for
Affiliate-owned communication facilities or systems shall be made pursuant to Section II.12 (Communications). 

 If the Parties fail to designate an amount in Sections II.7.A or II.7.B, in each instance the amount deemed adopted by the Parties as a result of such omission shall be the amount established as the
Operator’s expenditure limitation in the Agreement. If the Agreement does not contain an Operator’s expenditure limitation, the amount deemed adopted by the Parties as a result of such omission shall be zero dollars ($ 0.00). 

 

	8.	DAMAGES AND LOSSES TO JOINT PROPERTY 

 All costs or expenses necessary for the repair or replacement of Joint Property resulting from damages or losses incurred, except to the extent such damages or losses result from a Party’s or
Parties’ gross negligence or willful misconduct, in which case such Party or Parties shall be solely liable. 
 The Operator
shall furnish the Non-Operator written notice of damages or losses incurred as soon as practicable after a report has been received by the Operator. 
  

	9.	LEGAL EXPENSE 

 Recording
fees and costs of handling, settling, or otherwise discharging litigation, claims, and liens incurred in or resulting from operations under the Agreement, or necessary to protect or recover the Joint Property, to the extent permitted under the
Agreement. Costs of the Operator’s or Affiliate’s legal staff or outside attorneys, including fees and expenses, are not chargeable unless approved by the Parties pursuant to Section I.6.A (General Matters) or otherwise provided for
in the Agreement. 
 Notwithstanding the foregoing paragraph, costs for procuring abstracts, fees paid to outside attorneys for
title examinations (including preliminary, supplemental, shut-in royalty opinions, division order title opinions), and curative work shall be chargeable to the extent permitted as a direct charge in the Agreement. 

 

	10.	TAXES AND PERMITS 

 All
taxes and permitting fees of every land and nature, assessed or levied upon or in connection with the Joint Property, or the production therefrom, and which have been paid by the Operator for the benefit of the Parties, including penalties and
interest, except to the extent the penalties and interest result from the Operator’s gross negligence or willful misconduct. 
 If ad valorem taxes paid by the Operator are based in whole or in part upon separate valuations of each Party’s working interest, then notwithstanding any contrary provisions, the charges to the
Parties will be made in accordance with the tax value generated by each Party’s working interest. 

  
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 Costs of tax consultants or advisors, the Operator’s employees, or Operator’s-
Affiliate employees in matters regarding ad valorem or other tax matters, are not permitted as direct charges unless approved by the Parties pursuant to Section I.6.A (General Matters). 

Charges to the Joint Account resulting from sales/use tax audits, including extrapolated amounts and penalties and interest, are
permitted, provided the Non-Operator shall be allowed to review the invoices and other underlying source documents which served as the basis for tax charges and to determine that the correct amount of taxes were charged to the Joint Account. If the
Non-Operator is not permitted to review such documentation, the sales/use tax amount shall not be directly charged unless the Operator can conclusively document the amount owed by the Joint Account. 

 

	11.	INSURANCE 

 Net premiums
paid for insurance required to be carried for Joint Operations for the protection of the Parties. If Joint Operations are conducted at locations where the Operator acts as self-insurer in regard to its worker’s compensation and employer’s
liability insurance obligation, the Operator shall charge the Joint Account manual rates for the risk assumed in its self-insurance program as regulated by the jurisdiction governing the Joint Property. In the case of offshore operations in federal
waters, the manual rates of the adjacent state shall be used for personnel performing work On-site, and such rates shall be adjusted for offshore operations by the U.S. Longshoreman and Harbor Workers (USL&H) or Jones Act surcharge, as
appropriate. 
  

	12.	COMMUNICATIONS 

 Costs of
acquiring, leasing, installing, operating, repairing, and maintaining communication facilities or systems, including satellite, radio and microwave facilities, between the Joint Property and the Operator’s office(s) directly responsible for
field operations in accordance with the provisions of COPAS MFI-44 (“Field Computer and Communication Systems”). If the communications facilities or systems serving the Joint Property are Operator-owned, charges to the Joint Account shall
be made as provided in Section II.6 (Equipment and Facilities Furnished by Operator). If the communication facilities or systems serving the Joint Property are owned by the Operator’s Affiliate, charges to the Joint Account shall not
exceed average commercial rates prevailing in the area of the Joint Property. The Operator shall adequately document and support commercial rates and shall periodically review and update the rate and the supporting documentation. 

 

	13.	ECOLOGICAL, ENVIRONMENTAL, AND SAFETY 

 Costs incurred for Technical Services and drafting to comply with ecological, environmental and safety Laws or standards recommended by Occupational Safety and Health Administration (OSHA) or other
regulatory authorities. All other labor and functions incurred for ecological, environmental and safety matters, including management, administration, and permitting, shall be covered by Sections II.2 (Labor), II.5 (Services), or
Section III (Overhead), as applicable. 
 Costs to provide or have available pollution containment and removal equipment
plus actual costs of control and cleanup and resulting responsibilities of oil and other spills as well as discharges from permitted outfalls as required by applicable Laws, or other pollution containment and removal equipment deemed appropriate by
the Operator for prudent operations, are directly chargeable. 
  

	14.	ABANDONMENT AND RECLAMATION 

 Costs incurred for abandonment and reclamation of the Joint Properly, including costs required by lease agreements or by Laws. 

 

	15.	OTHER EXPENDITURES 

 Any
other expenditure not covered or dealt with in the foregoing provisions of this Section II (Direct Charges), or in Section III (Overhead) and which is of direct benefit to the Joint Property and is incurred by the Operator in the
necessary and proper conduct of the Joint Operations. Charges made under this Section II.15 shall require approval of the Parties, pursuant to Section I.6.A (General Matters). 

III. OVERHEAD 
 As
compensation for costs not specifically identified as chargeable to the Joint Account pursuant to Section II (Direct Charges), the Operator shall charge the Joint Account in accordance with this Section III. 

Functions included in the Overhead Charges overhead rates regardless of whether performed by the Operator, Operator’s Affiliates or third
parties and regardless of location, shall include, but not be limited to, costs and expenses of: 
  

	 	•	 	 warehousing, other than for warehouses that are jointly owned under this Agreement 



 

	 	•	 	 design and drafting (except when allowed as a direct charge under Sections II.13, III.1.A(ii), and III.2, Option B) 



 

	 	•	 	 inventory costs not chargeable under Section V (Inventories of Controllable Material) 



 

	 	•	 	 procurement 


  

	 	•	 	 administration 


  

	 	•	 	 accounting and auditing 


  

	 	•	 	 gas dispatching and gas chart integration 



  
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	 	•	 	 human resources 


  

	 	•	 	 management 


  

	 	•	 	 supervision not directly charged under Section II.2 (Labor) 



 

	 	•	 	 legal services not directly chargeable under Section II.9 (Legal Expense) 



 

	 	•	 	 taxation, other than those costs identified as directly chargeable under Section II.10 (Taxes and Permits) 



 

	 	•	 	 preparation and monitoring of permits and certifications; preparing regulatory reports; appearances before or meetings with governmental agencies or
other authorities having jurisdiction over the Joint Property, other than On-site inspections; reviewing, interpreting, or submitting comments on or lobbying with respect to Laws or proposed Laws. 



Overhead charges shall include the mean (a) all salaries or and wages plus applicable payroll
burdens, benefits, and Personal Expenses of personnel performing overhead functions, as well as (b) all office and other related expenses of overhead functions and (c) all other overhead expenses.

  

	1.	OVERHEAD – DRILLING AND PRODUCING OPERATIONS 

 As compensation for costs incurred but not chargeable under -Section II (Direct Charges) and not covered by other provisions of this Section III, the Operator shall charge on either: 

 

	 	þ	(Alternative 1) Fixed Rate Basis, Section III.1.B. 

  

	 	 ̈	(Alternative 2) Percentage Basis, Section III.1.C. 


 

	 	A.	TECHNICAL SERVICES 

  

	 	(i)	Except as otherwise provided in Section II.13 (Ecological Environmental, and Safety) and Section III.2 (Overhead – Major Construction and
Catastrophe), or by approval of the Parties pursuant to Section I.6.A (General Matters), the salaries, wages, related payroll burdens and benefits, and Personal Expenses for On-site Technical Services, including third party
Technical Services: 

  

	 	þ	(Alternative 1 – Direct) shall be charged direct to the Joint Account. 


 

	 	 ̈	(Alternative 2 – Overhead) shall be covered by the overhead rates. 


 

	 	(ii)	Except as otherwise provided in Section II.13 (Ecological, Environmental, and Safety) and Section III.2 (Overhead – Major Construction and
Catastrophe), or by approval of the Parties pursuant to Section I.6.A (General Matters), the salaries, wages, related payroll burdens and benefits, and Personal Expenses for Off-site Technical Services, including third party
Technical Services: 

  

	 	 ̈	(Alternative 1 – All Overhead) shall be covered by the overhead rates. 


 

	 	þ	(Alternative 2 – All Direct) shall be charged direct to the Joint Account. 


 

	 	 ̈	(Alternative 3 – Drilling Direct) shall be charged direct to the Joint Account, only
to the extent such Technical Services are directly attributable to drilling, redrilling, deepening, or sidetracking operations, through completion, temporary abandonment, or abandonment if a dry hole. Off-site Technical Services for all other
operations, including workover, recompletion, abandonment of producing wells, and the construction or expansion of fixed assets not covered by Section III.2 (Overhead Major Construction and Catastrophe) shall be covered by the overhead
rates. 

 Notwithstanding anything to the contrary in this Section III, Technical Services provided by
Operator’s Affiliates are subject to limitations set forth in Section II.7 (Affiliates), Charges for Technical personnel performing non-technical work shall not be governed by this Section III.1.A, but instead governed by other
provisions of this Accounting Procedure relating to the type of work being performed. 
  

	B.	OVERHEAD – FIXED RATE BASIS 

  

	 	(1)	The Operator shall charge the Joint Account at the following rates per well per month: 


Drilling Well Rate per month $ 12,000.00 (prorated for less than a full month) 

Producing Well Rate per month $ 1,200.00 
  

	 	(2)	Application of Overhead – Drilling Well Rate shall be as follows: 

  

	 	(a)	Charges for onshore drilling wells shall begin on the spud date and terminate on the date the drilling and/or completion equipment used on the well is released,
whichever occurs later. Charges for offshore and inland waters drilling wells shall begin on the date the drilling or completion equipment arrives on location and terminate on the date the drilling or completion equipment moves off location, or is
released, whichever occurs first. No charge shall be made during suspension of drilling and/or completion operations for fifteen (15) or more consecutive calendar days. 


 

	 	(b)	Charges for any well undergoing any type of workover, recompletion, and/or abandonment for a period of five (5) or more consecutive work-days shall be made at the
Drilling Well Rate. Such charges shall be applied for the period from date operations, with rig or other units used in operations, commence through date of rig or other unit release, except that no charges shall be made during suspension of
operations for fifteen (15) or more consecutive calendar days. 


  
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	 	(3)	Application of Overhead – Producing Well Rate shall be as follows: 

  

	 	(a)	An active well that is produced, injected into for recovery or disposal, or used to obtain water supply to support operations for any portion of the month shall be
considered as a one-well charge for the entire month. 

  

	 	(b)	Each active completion in a multi-completed well shall be considered as a one-well charge provided each completion is considered a separate well by the governing
regulatory authority. 

  

	 	(c)	A one-well charge shall be made for the month in which plugging and abandonment operations are completed on any well, unless the Drilling Well Rate applies, as provided
in Sections III.1.B.(2)(a) or (b). This one-well charge shall be made whether or not the well has produced. 

  

	 	(d)	An active gas well shut in because of overproduction or failure of a purchaser, processor, or transporter to take production shall be considered as a one-well charge
provided the gas well is directly connected to a permanent sales outlet. 

  

	 	(e)	Any well not meeting the criteria set forth in Sections III.1.B.(3) (a), (b), (c), or (d) shall not qualify for a producing overhead charge.


  

	 	(4)	The well rates shall be adjusted on the first day of April each year following the effective date of the Agreement; provided, however, if this Accounting Procedure is
attached to or otherwise governing the payout accounting under a farmout agreement, the rates shall be adjusted on the first day of April each year following the effective date of such farmout agreement. The adjustment shall be computed by applying
the adjustment factor most recently published by COPAS. The adjusted rates shall be the initial or amended rates agreed to by the Parties increased or decreased by the adjustment factor described herein, for each year from the effective date of such
rates, in accordance with COPAS MFI-47 (“Adjustment of Overhead Rates”). 

  

	C.	OVERHEAD PERCENTAGE BASIS 

  

	 	(1)	The Operator shall charge the Joint Account at the following rates: 


 

	 	(a)	Development Rate                     percent
(    )% of the cost of development of the Joint Property, exclusive of costs provided under Section II.9 (Legal Expense) and all Material salvage credits 


 

	 	(b)	Operating Rate                     percent
(    )% of the cost of development of the Joint Property, exclusive of costs provided under Sections II.1 (Rental and Royalties) II.9 (Legal Expense) and all Material salvage credits; the value of substances
purchased for enhanced recovery; all property and ad valorem taxes, and any other taxes and assessments that are levied, assessed, and paid upon the mineral interest in and to the Joint Property. 


 

	 	(2)	Application of Overhead – Percentage Basis shall be as follows: 


 

	 	(a)	The Development Rate shall be applied to all costs in connection with: 


 

	 	[i]	drilling, redrilling, sidetracking, or deepening of a well 


 

	 	[ii]	a well undergoing plugback or workover operations for a period of five (5) or more consecutive work days 


 

	 	[iii]	preliminary expenditures necessary in preparation for drilling 


 

	 	[iv]	expenditures incurred in abandoning when the well is not completed as a producer 


 

	 	[v]	construction or installation of fixed assets, the expansion of fixed assets and any other project clearly discernible as fixed asset other than Major
Construction or Catastrophe as defined in Section II.2 (Overhead Major Construction and Catastrophe). 

  

	 	(b)	The Operating Rate shall be applied to all other costs in connection with Joint Operations, except those subject to Section III.2 (Overhead Major
Construction and Catastrophe). 

  

	2.	OVERHEAD – MAJOR CONSTRUCTION AND CATASTROPHE 

 To compensate the Operator for overhead costs incurred in connection with a Major Construction project or Catastrophe, the Operator shall either negotiate a rate prior to the beginning of the project, or
shall charge the Joint Account for overhead based on the following rates for any Major Construction project in excess of the Operator’s expenditure limit under the Agreement, or for any Catastrophe regardless of the amount. If the Agreement to
which this Accounting Procedure is attached does not contain an expenditure limit, Major Construction Overhead shall be assessed for any single Major Construction project costing in excess of $100,000 gross. 

  
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 Major Construction shall mean the construction and installation of fixed assets, the
expansion of fixed assets, and any other project clearly discernible as a fixed asset required for the development and operation of the Joint Property, or in the dismantlement, abandonment, removal, and restoration of platforms, production
equipment, and other operating facilities. 
 Catastrophe is defined as a sudden calamitous event bringing damage, loss, or
destruction to property or the environment, such as an oil spill, blowout, explosion, fire, storm, hurricane, or other disaster. The overhead rate shall be applied to those costs necessary to restore the Joint Property to the equivalent condition
that existed prior to the event. 
  

	 	A.	If the Operator absorbs the engineering, design and drafting costs related to the project: 


 

	 	(1)	6 % of total costs if such costs are less than $100,000; plus 

  

	 	(2)	4 % of total costs in excess of $100,000 but less than $1,000,000; plus 

  

	 	(3)	2 % of total costs in excess of $1,000,000. 

  

	 	B.	If the Operator charges engineering, design and drafting costs related to the project directly to the Joint Account: 


 

	 	(1)	3 % of total costs if such costs are less than $100,000; plus 

  

	 	(2)	2 % of total costs in excess of $100,000 but less than $1,000,000; plus 


 

	 	(3)	1 % of total costs in excess of $1,000,000. 

 Total cost shall mean the gross cost of any one project. For the purpose of this paragraph, the component parts of a single Major Construction project shall not be treated separately, and the cost of
drilling and workover wells and purchasing and installing pumping units and downhole artificial lift equipment shall be excluded. For Catastrophes, the rates shall be applied to all costs associated with each single occurrence or event. 

On each project, the Operator shall advise the Non-Operator(s) in advance which of the above options shall apply. 

For the purposes of calculating Catastrophe Overhead, the cost of drilling relief wells, substitute wells, or conducting other well
operations directly resulting from the catastrophic event shall be included. Expenditures to which these rates apply shall not be reduced by salvage or insurance recoveries. Expenditures that qualify for Major Construction or Catastrophe Overhead
shall not qualify for overhead under any other overhead provisions. 
 In the event of any conflict between the provisions of
this Section III.2 and the provisions of Sections II.2 (Labor), II.5 (Services), or II.7 (Affiliates), the provisions of this Section III.2 shall govern. 

 

	3.	AMENDMENT OF OVERHEAD RATES 

 The overhead rates provided for in this Section III may be amended from time to time if, in practice, the rates are found to be insufficient or excessive, in accordance with the provisions of Section
I.6.B (Amendments). 
 IV. MATERIAL PURCHASES, TRANSFERS, AND DISPOSITIONS 

The Operator is responsible for Joint Account Material and shall make proper and timely charges and credits for direct purchases, transfers, and
dispositions. The Operator shall provide all Material for use in the conduct of Joint Operations; however, Material may be supplied by the Non-Operators, at the Operator’s option. Material furnished by any Party shall be furnished without any
express or implied warranties as to quality, fitness for use, or any other matter. 
  

	1.	DIRECT PURCHASES 

 Direct
purchases shall be charged to the Joint Account at the price paid by the Operator after deduction of all discounts received. The Operator shall make good faith efforts to take discounts offered by suppliers, but shall not be liable for failure to
take discounts except to the extent such failure was the result of the Operator’s gross negligence or willful misconduct. A direct purchase shall be deemed to occur when an agreement is made between an Operator and a third party for the
acquisition of Material for a specific well site or location. Material provided by the Operator under “vendor stocking programs,” where the initial use is for a Joint Property and title of the Material does not pass from the manufacturer,
distributor, or agent until usage, is considered a direct purchase. If Material is found to be defective or is returned to the manufacturer, distributor, or agent for any other reason, credit shall be passed to the Joint Account within sixty
(60) days after the Operator has received adjustment from the manufacturer, distributor, or agent. 

  
 COPYRIGHT © 2005 by
Council of Petroleum Accountants Societies, Inc. (COPAS) 


  
 11 











			
	



	  	 COPAS 2005 Accounting Procedure
 Recommended by COPAS, Inc.


  


	2.	TRANSFERS 

 A transfer is
determined to occur when the Operator (i) furnishes Material from a storage facility or from another operated property, (ii) has assumed liability for the storage costs and changes in value, and (iii) has previously secured and held
title to the transferred Material. Similarly, the removal of Material from the Joint Property to a storage facility or to another operated property is also considered a transfer; provided, however, Material that is moved from the Joint Property to a
storage location for safe-keeping pending disposition may remain charged to the Joint Account and is not considered a transfer. Material shall be disposed of in accordance with Section IV.3 (Disposition of Surplus) and the Agreement to which
this Accounting Procedure is attached. 
  

	 	A.	PRICING 

 The value of Material
transferred to/from the Joint Property should generally reflect the market value on the date of physical transfer. Regardless of the pricing method used, the Operator shall make available to the Non-Operators sufficient documentation to verify the
Material valuation. When higher than: specification grade or size tubulars are used in the conduct of Joint Operations, the Operator shall charge the Joint Account at the equivalent price for well design specification tubulars, unless such higher
specification grade or sized tubulars are approved by the Parties pursuant to Section I.6.A (General Matters). Transfers of new Material will be priced using one of the following pricing methods; provided, however, the Operator shall use
consistent pricing methods, and not alternate between methods for the purpose of choosing the method most favorable to the Operator for a specific transfer: 
  

	 	(1)	Using published prices in effect on date of movement as adjusted by the appropriate COPAS Historical Price Multiplier (HPM) or prices provided by the COPAS Computerized
Equipment Pricing System (CEPS). 

  

	 	(a)	For oil country tubulars and line pipe, the published price shall be based upon eastern mill carload base prices (Houston, Texas, for special end) adjusted as of date
of movement, plus transportation cost as defined in Section IV.2.B (Freight). 

  

	 	(b)	For other Material, the published price shall be the published list price in effect at date of movement, as listed by a Supply Store nearest the Joint Property where
like Material is normally available, or point of manufacture plus transportation costs as defined in Section IV.2.B (Freight). 

  

	 	(2)	Based on a price quotation from a vendor that reflects a current realistic acquisition cost. 


 

	 	(3)	Based on the amount paid by the Operator for like Material in the vicinity of the Joint Property within the previous twelve (12) months from the date of physical
transfer. 

  

	 	(4)	As agreed to by the Participating Parties for Material being transferred to the Joint Property, and by the Parties owning the Material for Material being transferred
from the Joint Property. 

  

	 	B.	FREIGHT 

 Transportation costs
shall be added to the Material transfer price using the method prescribed by the COPAS Computerized Equipment Pricing System (CEPS). If not using CEPS, transportation costs shall be calculated as follows: 

 

	 	(1)	Transportation costs for oil country tubulars and line pipe shall be calculated using the distance from eastern mill to the Railway Receiving Point based on the carload
weight basis as recommended by the COPAS MFI-38 (“Material Pricing Manual”) and other COPAS MFIs in effect at the time of the transfer. 

  

	 	(2)	Transportation costs for special mill items shall be calculated from that mill’s shipping point to the Railway Receiving Point For transportation costs from other
than eastern mills, the 30,000-pound interstate truck rate shall be used. Transportation costs for macaroni tubing shall be calculated based on the interstate truck rate per weight of tubing transferred to the Railway Receiving Point.


  

	 	(3)	Transportation costs for special end tubular goods shall be calculated using the interstate truck rate from Houston, Texas, to the Railway Receiving Point.


  

	 	(4)	Transportation costs for Material other than that described in Sections IV.2.B.(1) through (3), shall be calculated from the Supply Store or point of manufacture,
whichever is appropriate, to the Railway Receiving Point 

 Regardless of whether using CEPS or manually
calculating transportation costs, transportation costs from the Railway Receiving Point to the Joint Property are in addition to the foregoing, and may be charged to the Joint Account based on actual costs incurred. All transportation costs are
subject to Equalized Freight as provided in Section II.4 (Transportation) of this Accounting Procedure. 
  

	 	C.	TAXES 

 Sales and use taxes shall
be added to the Material transfer price using either the method contained in the COPAS Computerized Equipment Pricing System (CEPS) or the applicable tax rate in effect for the Joint Property at the time and place of transfer. In either case, the
Joint Account shall be charged or credited at the rate that would have governed had the Material been a direct purchase. 

  
 COPYRIGHT © 2005 by
Council of Petroleum Accountants Societies, Inc. (COPAS) 


  
 12 











			
	



	  	 COPAS 2005 Accounting Procedure
 Recommended by COPAS, Inc.


  


	 	D.	CONDITION 

  

	 	(1)	Condition “A” – New and unused Material in sound and serviceable condition shall be charged at one hundred percent (100%) of the price as determined
in Sections IV.2.A (Pricing), IV.2.B (Freight), and IV.2.C (Taxes). Material transferred from the Joint Property that was not placed in service shall be credited as charged without gain or loss; provided, however, any unused
Material that was charged to the Joint Account through a direct purchase will be credited to the Joint Account at the original cost paid less restocking fees charged by the vendor. New and unused Material transferred from the Joint Property may be
credited at a price other than the price originally charged to the Joint Account provided such price is approved by the Parties owning such Material, pursuant to Section I.6.A (General Matters). All refurbishing costs required or
necessary to return the Material to original condition or to correct handling, transportation, or other damages will be borne by the divesting property. The Joint Account is responsible for Material preparation, handling, and transportation costs
for new and unused Material charged to the Joint Property either through a direct purchase or transfer. Any preparation costs incurred, including any internal or external coating and wrapping, will be credited on new Material provided these services
were not repeated for such Material for the receiving property. 

  

	 	(2)	Condition “B” – Used Material in sound and serviceable condition and suitable for reuse without reconditioning shall be priced by multiplying the price
determined in Sections IV.2.A (Pricing), IV.2.B (Freight), and IV.2.C (Taxes) by seventy-five percent (75%). 

 Except as provided in Section IV.2.D(3), all reconditioning costs required to return the Material to Condition “B” or to correct handling, transportation or other damages will be borne by the
divesting property. 
 If the Material was originally charged to the Joint Account as used Material and placed in service for
the Joint Property, the Material will be credited at the price determined in Sections IV.2.A (Pricing), IV.2.B (Freight), and IV.2.C (Taxes) multiplied by sixty-five percent (65%). 

Unless otherwise agreed to by the Parties that paid for such Material, used Material transferred from the Joint Property that was not
placed in service on the property shall be credited as charged without gain or loss. 
  

	 	(3)	Condition “C” – Material that is not in sound and serviceable condition and not suitable for its original function until after reconditioning shall be
priced by multiplying the price determined in Sections IV.2.A (Pricing), IV.2.B (Freight), and IV.2.C (Taxes) by fifty percent (50%). 

 The cost of reconditioning may be charged to the receiving property to the extent Condition “C” value, plus cost of reconditioning, does not exceed Condition “B” value. 

 

	 	(4)	Condition “D” – Material that (i) is no longer suitable for its original purpose but useable for some other purpose, (ii) is obsolete, or
(iii) does not meet original specifications but still has value and can be used in other applications as a substitute for items with different specifications, is considered Condition “D” Material. Casing, tubing, or drill pipe used as
line pipe shall be priced as Grade A and B seamless line pipe of comparable size and weight. Used casing, tubing, or drill pipe utilized as line pipe shall be priced at used line pipe prices. Casing, tubing, or drill pipe used as higher pressure
service lines than standard line pipe, e.g., power oil lines, shall be priced under normal pricing procedures for casing, tubing, or drill pipe. Upset tubular goods shall be priced on a non-upset basis. For other items, the price used should result
in the Joint Account being charged or credited with the value of the service rendered or use of the Material, or as agreed to by the Parties pursuant to Section 1.6.A (General Matters). 


 

	 	(5)	Condition “E” – Junk shall be priced at prevailing scrap value prices. 


 

	 	E.	OTHER PRICING PROVISIONS 

  

	 	(1)	Preparation Costs 

 Subject to
Section II (Direct Charges) and Section III (Overhead) of this Accounting Procedure, costs, incurred by the Operator in making Material serviceable including inspection, third party surveillance services, and other similar services
will be charged to the Joint Account at prices which reflect the Operator’s actual costs of the services. Documentation must be provided to the Non-Operators upon request to support the cost of service. New coating and/or wrapping shall be
considered a component of the Materials and priced in accordance with Sections IV.1 (Direct Purchases) or IV.2.A (Pricing), as applicable. No charges or credits shall be made for used coating or wrapping. Charges and credits for
inspections shall be made in accordance with COPAS MFI-38 (“Material Pricing Manual”). 
  

	 	(2)	Loading and Unloading Costs 


Loading and unloading costs related to the movement of the Material to the Joint Property shall be charged in accordance with the methods
specified in COPAS MFI-38 (“Material Pricing Manual”). 

  
 COPYRIGHT © 2005 by
Council of Petroleum Accountants Societies, Inc. (COPAS) 


  
 13 











			
	



	  	 COPAS 2005 Accounting Procedure
 Recommended by COPAS, Inc.


  


	3.	DISPOSITION OF SURPLUS 


Surplus Material is that Material, whether new or used, that is no longer required for Joint Operations. The Operator may purchase, but
shall be under no obligation to purchase, the interest of the Non-Operators in surplus Material. 
 Dispositions for the purpose
of this procedure are considered to be the relinquishment of title of the Material from the Joint Property to either a third party, a Non-Operator, or to the Operator. To avoid the accumulation of surplus Material, the Operator should make good
faith efforts to dispose of surplus within twelve (12) months through buy/sale agreements, trade, sale to a third party, division in kind, or other dispositions as agreed to by the Parties. 

Disposal of surplus Materials shall be made in accordance with the terms of the Agreement to which this Accounting Procedure is attached.
If the Agreement contains no provisions governing disposal of surplus Material, the following terms shall apply: 
  

	 	•	 	 The Operator may, through a sale to an unrelated third party or entity, dispose of surplus Material having a gross sale value that is less than or
equal to the Operator’s expenditure limit as set forth in the Agreement to which this Accounting Procedure is attached without the prior approval of the Parties owning such Material. 



 

	 	•	 	 If the gross sale value exceeds the Agreement expenditure limit, the disposal must be agreed to by the Parties owning such Material.



  

	 	•	 	 Operator may purchase surplus Condition “A” or “B” Material without approval of the Parties owning such Material, based on the
pricing methods set forth in Section IV.2 (Transfers). 


  

	 	•	 	 Operator may purchase Condition “C” Material without prior approval of the Parties owning such Material if the value of the Materials, based
on the pricing methods set forth in Section IV.2 (Transfers), is less than or equal to the Operator’s expenditure limitation set forth in the Agreement The Operator shall provide documentation supporting the classification of the
Material as Condition C. 


  

	 	•	 	 Operator may dispose of Condition “D” or “E” Material under procedures normally utilized by Operator without prior approval of the
Parties owning such Material. 


  

	4.	SPECIAL PRICING PROVISIONS 

  

	 	A.	PREMIUM PRICING 

 Whenever
Material is available only at inflated prices due to national emergencies, strikes, government imposed foreign trade restrictions, or other unusual causes over which the Operator has no control, for direct purchase the Operator may charge the Joint
Account for the required Material at the Operator’s actual cost incurred in providing such Material, making it suitable for use, and moving it to the Joint Property. Material transferred or disposed of during premium pricing situations shall be
valued in accordance with Section IV.2 (Transfers) or Section IV.3 (Disposition of Surplus), as applicable. 
  

	 	B.	SHOP-MADE ITEMS 

 Items
fabricated by the Operator’s employees, or by contract laborers under the direction of the Operator, shall be priced using the value of the Material used to construct the item plus the cost of labor to fabricate the item. If the Material is
from the Operator’s scrap or junk account, the Material shall be priced at either twenty-five percent (25%) of the current price as determined in Section IV.2.A (Pricing) or scrap value, whichever is higher. In no event shall the
amount charged exceed the value of the item commensurate with its use. 
  

	 	C.	MILL REJECTS 

 Mill rejects
purchased as “limited service” casing or tubing shall be priced at eighty percent (80%) of K-55/J-55 price as determined in Section IV.2 (Transfers). Line pipe converted to casing or tubing with casing or tubing couplings
attached shall be priced as K-55/J-55 casing or tubing at the nearest size and weight. 
 V. INVENTORIES OF CONTROLLABLE
MATERIAL 
 The Operator shall maintain records of Controllable Material charged to the Joint Account, with sufficient detail to perform
physical inventories. 
 Adjustments to the Joint Account by the Operator resulting from a physical inventory of Controllable Material shall be
made within twelve (12) months following the taking of the inventory or receipt of Non-Operator inventory report. Charges and credits for overages or shortages will be valued for the Joint Account in accordance with Section IV.2
(Transfers) and shall be based on the Condition “B” prices in effect on the date of physical inventory unless the inventorying Parties can provide sufficient evidence another Material condition applies. 

  
 COPYRIGHT © 2005 by
Council of Petroleum Accountants Societies, Inc. (COPAS) 


  
 14 











			
	



	  	 COPAS 2005 Accounting Procedure
 Recommended by COPAS, Inc.


  


	1.	DIRECTED INVENTORIES 


Physical inventories shall be performed by the Operator upon written request of a majority in working interests of the Non-Operators
(hereinafter, “directed inventory”); provided, however, the Operator shall not be required to perform directed inventories more frequently than once every five (5) years. Directed inventories shall be commenced within one hundred
eighty (180) days after the Operator receives written notice that a majority in interest of the Non-Operators has requested the inventory. All Parties shall be governed by the results of any directed inventory. 

Expenses of directed inventories will be borne by the Joint Account; provided, however, costs associated with any post-report follow-up
work in settling the inventory will be absorbed by the Party incurring such costs. The Operator is expected to exercise judgment in keeping expenses within reasonable limits. Any anticipated disproportionate or extraordinary costs should be
discussed and agreed upon prior to commencement of the inventory. Expenses of directed inventories may include fee following: 
  

	 	A.	A per diem rate for each inventory, person, representative of actual salaries, wages, and payroll burdens and benefits of the personnel performing fee inventory or a
rate agreed to by the Parties pursuant to Section I.6.A (General Matters). The per diem rate shall also be applied to a reasonable number of days for pre-inventory work and report preparation. 


 

	 	B.	Actual transportation costs and Personal Expenses for the inventory team. 

  


	 	C.	Reasonable charges for report preparation and distribution to the Non-Operators. 


 

	2.	NON-DIRECTED INVENTORIES 

  

	 	A.	OPERATOR INVENTORIES 

 Physical
inventories that are not requested by the Non-Operators may be performed by the Operator, at the Operator’s discretion. The expenses of conducting such Operator-initiated inventories shall not be charged to the Joint Account. 

 

	 	B.	NON-OPERATOR INVENTORIES 


Subject to fee terms of fee Agreement to which this Accounting Procedure is attached, the Non-Operators may conduct a physical inventory
at reasonable times at their sole cost and risk after giving fee Operator at least ninety (90) days prior written notice. The Non-Operator inventory report shall be furnished to the Operator in writing within ninety (90) days of completing
the inventory fieldwork. 
  

	 	C.	SPECIAL INVENTORIES 

 The expense
of conducting inventories other than those described in Sections V.1 (Directed Inventories), V.2.A (Operator Inventories), or V.2.B (Non-Operator Inventories), shall be charged to the Party requesting such inventory; provided,
however, inventories required due to a change of Operator shall be charged to the Joint Account in fee same manner as described in Section V.1 (Directed Inventories). 

  
 COPYRIGHT © 2005 by
Council of Petroleum Accountants Societies, Inc. (COPAS) 


  
 15 









 EXHIBIT “D” 

Attached to and made a part of that certain Operating Agreement dated December 31, 2012, 

by and between Dejour Energy (USA) Corp., as Operator, 
 and Bakken Drilling Fund III LP, as Non-Operator 
 INSURANCE PROVISIONS

 ARTICLE 1. 
 INSURANCE FOR BENEFIT OF JOINT ACCOUNT 
 1.1 Insurance Coverages to be Maintained by
Operator for the Joint Account. Prior to commencing any operations subject to this Agreement, Operator shall, at the joint expense and for the protection of the parties hereto, procure and, at all times while operations are conducted hereunder,
maintain with responsible insurance companies, the following insurance coverage: 
  

	 	(a)	Workers’ Compensation Insurance. For any employees of Operator, Workers’ Compensation Insurance in full compliance with the laws of the state(s) in
which operations will be conducted. 

  

	 	(b)	Employers’ Liability Insurance. Employer’s Liability insurance in the limits of not less than $1,000,000 per accident covering injury or death to any
employee who may be outside the scope of the Workers’ Compensation statutes of the state(s) in which operations will be conducted. 

  

	 	(c)	Commercial General Liability Insurance. Commercial General Liability insurance with combined single limits per occurrence (and any general aggregate if
applicable) of not less than $1,000,000 for Bodily Injury and Property Damage, including Bodily Injury and Property Damage liability due to Blowout, Explosion and Cratering, sudden and accidental pollution liability, Products and Completed
Operations, Action Over Indemnity (to cover bodily injury to employees when assumed under a written contract) and Broad Form Contractual Liability as respects any contract into which the Operator may enter under the terms of this Agreement,
providing the following additional coverages: Endorsement providing that a claim “in rem” shall be treated as a claim against the insured. 

  

	 	(d)	Automobile. If Operator uses any vehicles in its operations subject to this Agreement, Business Automobile Liability insurance, including Physical Damage
coverage, covering all owned (if any are owned), hired and/or non-owned vehicles with a $1,000,000 liability limit for any one accident or loss. 

  

	 	(e)	Umbrella. Umbrella or Excess Liability Insurance covering each occurrence of bodily injury and/or property damage in excess of the per occurrence and aggregate
limits provided in the primary liability insurance policies specified in this Exhibit such that the combination of General Liability coverage and Excess Liability (or umbrella) coverage is not less than $5,000,000. 


 

	 	(f)	Control of Well Insurance. Control of Well Insurance covering the costs of controlling a Blowout, including a well out of control underground, the expenses
involved in re-drilling or restoring the well, certain other related costs and Pollution Liability. (These are descriptive terms only and exact coverage can be found only in the policy.) The limit for this insurance shall be a minimum of $5,000,000
(100%) Combined Single Limit per occurrence with a deductible not to exceed $250,000 (100%) per occurrence for wells at a depth from the surface to 10,000 feet and with a deductible not to exceed $375,000 (100%) per occurrence for
wells at a depth from 10,000 feet and below. Care, Custody and Control Limit with a deductible not to exceed $100,000 (100%) per occurrence. Non-Operators not wishing to be covered under this policy must notify Operator prior to a spud date and
provide evidence of satisfactory insurance; and by such refusal of coverage each Non-Operator agrees to be responsible for its proportionate share of such loss and indemnify the Operator and the other Non-Operators from any such loss that would have
been covered under the Operator’s coverage (whether individually for the Operator or for the benefit of the joint account), regardless of the degree or type of negligence, whether sole, joint, concurrent, or gross, anything in this agreement to
the contrary notwithstanding. 

  

	 	(g)	Aircraft Liability Insurance. In the event Operator uses either fixed or rotor wing aircraft, insurance covering all owned, non-owned or chartered aircraft
utilized in operations hereunder with limits of a least $10,000,000 per occurrence including Passenger Liability. 

 1.2
Primary. All insurance carried by Operator hereunder for the joint account, and any provided by contactors or subcontractors, shall provide that such insurance is the primary coverage, even as to any other insurance carried by any party
hereto. 
 1.3 Carriers. All of the foregoing insurance carried by Operator for the joint account or by contractors and subcontractors as
required below shall be provided by an insurance company or companies approved to do business in the state(s) in which operations are to be conducted. 

  
  

			
	Exhibit D – Insurance Provision	  	Page 1









 ARTICLE 2. 
 ADDITIONAL INSURED, WAIVER OF SUBROGATION 
 2.1. Additional Insured. Each
Non-Operator shall be named as an additional insured under all liability insurance policies except Workers’ Compensation and Employer’s Liability carried by Operator for the joint account pursuant hereto unless such party has elected to
carry its own insurance if the same is authorized hereunder. 
 2.2. Subrogation. The insurance policies to be carried by Operator for
the joint account, by a party hereto for its own account, and/or by a contractor or subcontractor furnishing goods or services for the benefit of the joint account shall provide that the underwriters waive subrogation (whether by loan receipt,
equitable assignment, or otherwise) against all of the parties hereto (and their employees, officers, directors, owners, shareholders and agents). 
 ARTICLE 3. 
 MISCELLANEOUS 

3.1 Additional Insurance. Each party shall have the right to acquire and maintain at its own cost such additional insurance as it desires to
protect itself against any liability not covered by the insurance described above which is maintained by Operator for the joint account. All such insurance maintained by any party to this agreement for its own account shall inure solely to the
benefit of such party and shall contain a waiver by the insurance company of all rights of subrogation in favor of the parties hereto. 
 3.2.
Contractors. Operator shall use reasonable efforts to require contractors and subcontractors performing work for the joint account to provide such insurance as deemed necessary by Operator in relation to the work to be performed by said
contractors or subcontractors. Any release, hold harmless, or indemnity provisions and any Additional Insured and Waiver requirements under contracts entered into for such work will list the non-operators as indemnitees and Additional Insureds and
waivers of subrogation will be for their benefit as well as for the Operator’s benefit. 
 3.3. Certificates. Certificates for the
insurance carried by Operator for the joint account shall be obtained by Operator and furnished to Non-Operators. Each such Certificate shall provide that the insurance described therein may not be cancelled, reduced, or materially changed (insofar
as it relates to this Agreement) without written notice of a least thirty (30) days being given to Non-Operators prior to the date of the intended cancellation, reduction, or change. The insurer or its duly authorized agent shall sign the
Certificates of Insurance that must be provided pursuant to this Exhibit. Failure of a party to object to: (1) another party’s failure to furnish Certificates, or (2) any defect in a Certificate shall not be deemed a waiver of a
party’s duty to furnish the insurance coverage described above. 
 3.4. Endorsements. The General Liability Insurance policy shall
contain contractual liability coverage appropriate to the operation and a Co-owners Endorsement. 
 3.5. Operator Liability. It is
further understood and agreed that Operator is not a warrantor of the financial responsibility of the insurer with whom such insurance is carried, and that except for willful negligence, Operator shall not be liable to Non-Operators for any loss
suffered on account of the insufficiency of the insurance carried, or of the insurer with whom carried. Operator shall not be liable to Non-Operator for any loss accruing by reason of Operator’s inability to procure or maintain the insurance
described above. Operator agrees that if at any time during the term of this Agreement, it is unable to obtain or maintain such insurance, it shall promptly notify Non-Operators of such fact in writing. 

  
  

			
	Exhibit D – Insurance Provision	  	Page 2









 EXHIBIT “F” 

Attached to and made a part of that certain Operating Agreement dated December 31, 2012, 

by and between Dejour Energy (USA) Corp., as Operator, 
 and Bakken Drilling Fund III LP, as Non-Operator 
 NON-DISCRIMINATION AND

 CERTIFICATION OF NON-SEGREGATED FACILITIES 
 In connection with the performance of work under the Operating Agreement, the Operator agrees to comply with all the provisions of Section 202(1) to (7) inclusive, of Executive Order 11246 (30
F.R. 12319), which are hereby incorporated by reference in this Agreement, and all provisions of said Executive Order 11246 and all rules, regulations and relevant orders of the Secretary of Labor. 

END OF EXHIBIT “F” – sole page 







 Exhibit G to 
 Joint Operating Agreement among Dejour Energy (USA), Corp., as Operator, and Bakken Drilling Fund III LP dated as of December 31, 2012 

TAX PARTNERSHIP PROVISIONS 
 OF THE [DEJOUR-BDF III] 2012 TAX PARTNERSHIP 
 (EIN: [—]) 
 (For Name of Tax Reporting Partner and Special Elections, See
Secs. 8 and 9) 
 Table of Contents 
  

							
	 1. General Provisions
	  	 	3	  
			
	 1.1.
	  	 Designation Of Documents
	  	 	3	  
			
	 1.2.
	  	 Relationship of the Parties
	  	 	3	  
			
	 1.3.
	  	 Priority Of Provisions Of The TPPs
	  	 	3	  
			
	 1.4.
	  	 Survivorship
	  	 	3	  
		
	 2. Tax Reporting Partner
	  	 	4	  
			
	 2.1.
	  	 Tax Reporting Partner
	  	 	4	  
			
	 2.2.
	  	 Tax Matters Partner
	  	 	4	  
		
	 3. Income Tax Compliance and Capital Accounts
	  	 	5	  
			
	 3.1.
	  	 Tax Returns
	  	 	5	  
			
	 3.2.
	  	 Fair Market Value Capital Accounts
	  	 	5	  
			
	 3.3.
	  	 Information Requests
	  	 	5	  
			
	 3.4.
	  	 Best Efforts Without Liability
	  	 	6	  
		
	 4. Tax and FMV Capital Account Elections
	  	 	6	  
			
	 4.1.
	  	 General Elections
	  	 	6	  
			
	 4.2.
	  	 Depletion
	  	 	6	  
			
	 4.3.
	  	 Election Out Under Code §761(a)
	  	 	6	  
			
	 4.4.
	  	 Consent Requirements For Subsequent Tax Or FMV Capital Account Elections
	  	 	7	  
		
	 5. Capital Contributions and FMV Capital Accounts
	  	 	7	  









							
	 5.1.
	  	 Capital Contributions
	  	 	7	  
			
	 5.2.
	  	 FMV Capital Accounts
	  	 	7	  
		
	 6. Partnership Allocations
	  	 	8	  
			
	 6.1.
	  	 FMV Capital Account Allocations
	  	 	8	  
			
	 6.2.
	  	 Tax Return and Tax Basis Capital Account Allocations
	  	 	9	  
		
	 7. Termination and Liquidating Distribution
	  	 	10	  
			
	 7.1.
	  	 Termination of the Partnership
	  	 	10	  
			
	 7.2.
	  	 Return of Unexpended Contributions and Unshared Property
	  	 	11	  
			
	 7.3.
	  	 Balancing of FMV Capital Accounts
	  	 	11	  
			
	 7.4.
	  	 Deemed Sale Gain/Loss Charge Back
	  	 	11	  
			
	 7.5.
	  	 No Deficit Restoration Obligation
	  	 	11	  
			
	 7.6.
	  	 Distribution to balance capital accounts
	  	 	11	  
			
	 7.7.
	  	 FMV determination
	  	 	12	  
			
	 7.8.
	  	 Final Distribution
	  	 	12	  
		
	 8. Transfers, Indemnification, and Correspondence
	  	 	12	  
			
	 8.1.
	  	 Transfer of Partnership Interests
	  	 	12	  
			
	 8.2.
	  	 Correspondence
	  	 	12	  
			
	 8.3.
	  	 Indemnification
	  	 	12	  
		
	 9. Elections and Changes to above Provisions
	  	 	13	  
			
	 9.1.
	  	 Special Tax Elections
	  	 	13	  
			
	 9.2.
	  	 Special Allocations
	  	 	13	  
			
	 9.3.
	  	 Change of Required Approval for Other Elections
	  	 	15	  


  
 2 









	 	1.	General Provisions 

 1.1.
Designation Of Documents. 
 This exhibit is referred to in, and is part of, the agreement identified above and, if so provided,
a part of any agreement to which such agreement is an exhibit. Such agreements (including all exhibits thereto, other than this exhibit) shall be hereinafter referred to as the “Underlying Agreement” and this exhibit is hereinafter
referred to as the “Tax Partnership Provisions” or the “TPPs”. Except as may be otherwise provided in the TPPs, terms defined and used in the Underlying Agreement shall have the same meaning when used herein. 

1.2. Relationship of the Parties. 
 Dejour Energy (USA) Corp. and Bakken Drilling Fund III LP shall be hereinafter referred to as “Party” or “Parties.” The Parties understand and agree that the arrangement and
undertakings evidenced by the Underlying Agreement result in a partnership between the Parties for purposes of Federal income taxation and certain State income tax laws which incorporate or follow Federal income tax principles as to tax
partnerships. Such partnership for tax purposes is hereinafter referred to as the “Partnership.” For every other purpose of the Underlying Agreement, the Parties understand and agree that their legal relationship to each other under
applicable State law with respect to all property subject to the Underlying Agreement is one of tenants in common, or undivided interest owners, or lessee(s) or sublessee(s) and not a partnership; that the liabilities of the Parties shall be several
and not joint or collective; that each Party shall be responsible solely for its own obligations; and that the other parties to the Underlying Agreement that have not signed the Underlying Agreement or these TPPs have no rights, obligations or
liabilities hereunder. 
 1.3. Priority Of Provisions Of The TPPs. 

If there is a conflict or inconsistency, whether direct or indirect, actual or apparent, between the terms and conditions of the TPPs and
the terms and conditions of the Underlying Agreement, or any other exhibit or any part thereof, the terms and conditions of the TPPs shall govern and control. 
 1.4. Survivorship. 
 1.4.1. Any termination of the Underlying Agreement shall not
affect the continuing application of the TPPs for the termination and liquidation of the Partnership. 
 1.4.2. Any termination
of the Underlying Agreement shall not affect the continuing application of the TPPs for the resolution of all matters regarding Federal and State income reporting. 
 1.4.3. These TPPs shall inure to the benefit of, and be binding upon, the Parties hereto and their successors and assigns. 

  
 3 








 1.4.4. The effective date of the Underlying Agreement shall be the effective date of these
TPPs. The Partnership shall continue in full force and effect from, and after such date, until termination and liquidation of the Partnership. 
  

	 	2.	Tax Reporting Partner 

 2.1. Tax
Reporting Partner. 
 Dejour Energy (USA) Corp., as the Tax Reporting Partner (the “TRP”), is responsible for
compliance with all tax reporting obligations of the Partnership, see Sec. 3.1, below. In the event of any change in the TRP, the Party serving as the TRP at the beginning of a given taxable year shall continue as the TRP with respect to all matters
concerning such year. 
 2.2. Tax Matters Partner 
 2.2.1. The TRP shall also be the Tax Matters Partner as defined in Code §6231(a) (the “TMP”) and references to the TRP shall then include references to the TMP and vice versa.

 2.2.2. The TMP shall not be required to incur any expenses for the preparation for, or pursuance of, administrative or
judicial proceedings, unless the Parties agree on a method for sharing such expenses. 
 2.2.3. The Parties shall furnish the
TMP, within two weeks from the receipt of the request, the information the TMP may reasonably request to comply with the requirements on furnishing information to the Internal Revenue Service. 

2.2.4. The TMP shall not agree to any extension of the statute of limitations for making assessments on behalf of the Partnership
without first obtaining the written consent of the other Party. The TMP shall not bind the other Party to a settlement agreement in tax audits without obtaining the written concurrence of such Party. 

2.2.5. Any Party who enters in a settlement agreement with the Secretary of the Treasury with respect to any partnership items, as
defined in Code §6231(a)(3), shall notify the other Party of the terms within ninety (90) days from the date of such settlement. 
 2.2.6. If any Party intends to file a notice of inconsistent treatment under Code §6222(b), such Party shall, prior to the filing of such notice, notify the TMP of the (actual or potential)
inconsistency of the Party’s intended treatment of a partnership item with the treatment of that item by the Partnership. Within one week of receipt the TMP shall remit copies of such notification to the other Parties. If an inconsistency
notice is filed solely because a Party has not received a Schedule K-1 in time for filing of its income tax return, the TMP need not be notified. 

  
 4 








 2.2.7. No Party shall file pursuant to Code §6227 a request for an administrative
adjustment of partnership items (a “RFAA”) without first notifying the other Party. If the other Party agrees with the requested adjustment, the TMP shall file the RFAA on behalf of the Partnership. If such agreement is not obtained within
thirty (30) days from such notice, or within the period required to timely file the RFAA, if shorter, any Party, including the TMP, may file a RFAA on its own behalf. 
 2.2.8. Any Party intending to file with respect to any partnership item, or any other tax matter involving the Partnership, a petition under Code §§6226, 6228, or any other provision, shall
notify the other Party prior to such filing of the nature of the contemplated proceeding. In the case where the TMP is the Party intending to file such petition, such notice shall be given within a reasonable time to allow the other Party to
participate in the choice of forum for such petition. If the Parties do not agree on the appropriate forum, then the forum shall be chosen by majority vote. Each Party shall have a vote in accordance with its percentage interest in the Partnership
profits and losses for the year under audit. If a majority cannot agree, the TMP shall choose the forum. If a Party intends to seek review of any court decision rendered as a result of such proceeding, the Party shall notify the other Party prior to
seeking such review. 
  

	 	3.	Income Tax Compliance and Capital Accounts 

 3.1. Tax Returns. 
 The TRP shall prepare and file all required Federal and State
partnership income tax returns and all such expenses incurred to do so shall be borne by the partnership. In preparing the returns, the TRP shall use its best efforts. Not less than thirty (30) days prior to the return due date (including
extensions), the TRP shall submit to each Party for review a copy of the return as proposed. 
 3.2. Fair Market Value Capital
Accounts. 
 The TRP shall establish and maintain for each Party fair market value (“FMV”) capital accounts and tax
basis capital accounts. The TRP shall submit to each Party, along with a copy of any proposed partnership income tax return, an accounting of such Party’s FMV capital accounts as of the end of the return period. 

3.3. Information Requests. 
 In addition to any obligation under Sec. 2.2.3, each Party agrees to furnish to the TRP not later than sixty (60) days before the return due date (including extensions) such information relating to
the operations conducted under the Underlying Agreement and regarding themselves and their affiliates as may be required for the proper preparation of such returns. Similarly, each Party agrees to furnish timely to the TRP, as requested, any
information and data necessary for the preparation and/or filing of other required reports and notifications, and for the computation of the capital accounts. As provided in Code §6050K(c), a Party transferring its interest must notify the TRP
to allow compliance with Code §6050K(a) (see also Sec. 8.1). 

  
 5 








 3.4. Best Efforts Without Liability. 

The TRP and the other Party shall use their best efforts to comply with responsibilities outlined in this Section, and with respect to
the service as TMP as outlined Sec. 2.2, and in doing so shall incur no liability to any other Party. 
  

	 	4.	Tax and FMV Capital Account Elections 

 4.1. General Elections. 
 For both income tax return and capital account purposes,
the Partnership shall elect: 
 4.1.1. to deduct when incurred intangible drilling and development costs (“IDC”);

 4.1.2. to use the maximum allowable accelerated tax method and the shortest permissible tax life for depreciation;

 4.1.3. the accrual method of accounting; and 
 4.1.4. to report income on a calendar year basis; 
 and the Partnership shall also
make any elections as specially noted in Sec. 9.1, below. 
 4.2. Depletion. 

Solely for FMV capital account purposes, depletion shall be calculated by using simulated cost depletion within the meaning of Treas.
Reg. §1.704-1 (b)(2)(iv)(k)(2), unless the use of simulated percentage depletion is elected in Sec. 9.1, below. The simulated cost depletion allowance shall be determined under the principles of Code §612 and be based on the FMV capital
account basis of each property. Solely for purposes of this calculation, remaining reserves shall be determined consistently by the TRP. 
 4.3. Election Out Under Code §761(a). 
 4.3.1. The Parties agree not to
elect to be excluded from the application of Subchapter K of Chapter 1 of the Code. The TRP shall notify all Parties of an intended election to be excluded from the application of Subchapter K of Chapter 1 of the Code not later than sixty
(60) days prior to the filing date or the due date (including extensions) for the Federal partnership income tax return, whichever comes earlier. Any Party that does not consent to such election must provide the TRP with written objection
within thirty (30) days of such notice. No election-out shall be made unless all Parties consent to such election-out. Even after an effective election-out, the TRP’s rights and obligations, other than the relief from tax return filing
obligations of the Partnership, shall continue. 

  
 6 








 4.3.2. After an election-out, to avoid an unintended impairment of the election-out: The
Parties will avoid, without prior coordination, any operational changes which would terminate the qualification for the election-out status; all Parties will monitor the continuing qualification of the Partnership for the election-out status and
will notify the other Party if, in their opinion, a change in operations will jeopardize the election-out; and, all Parties will use, unless agreed to by them otherwise, the cumulative gas balancing method as described in Treas. Reg. §1.761-
2(d)(2). 
 4.4. Consent Requirements For Subsequent Tax Or FMV Capital Account Elections. 

Unless stipulated differently in Sec. 9.3, future elections, in addition to or in amendment of those in the TPPs, must be approved by the
affirmative consent of the Parties. 
  

	 	5.	Capital Contributions and FMV Capital Accounts 

 The provisions of this Sec. 5 and any other provisions of the TPPs relating to the maintenance of the capital accounts are intended to comply with Treas. Reg. §1.704- 1(b) and shall be interpreted
and applied in a manner consistent with such regulations. Specific special allocations to so comply shall be provided in Sec. 9.2. 
 5.1. Capital Contributions. 
 The respective capital contributions of each Party
to the Partnership shall be (a) each Party’s interest in the oil and gas leases included in the Contract Area (as defined in the Underlying Agreement and set out in Exhibit “A” therein), including all associated lease and well
equipment, and (b) all amounts of money paid by each Party in connection with the acquisition, exploration, development, and operation of the lease(s) and related equipment, and all other costs characterized as contributions or expenses borne
by such Party under the Underlying Agreement. The interests in oil and gas lease(s) described in clause (a) of this Sec. 5.1 is hereinafter referred to as the “Contributed Leases.” The contribution of the leases and any other
properties shall be made by each Party’s execution of the Underlying Agreement. 
 5.2. FMV Capital Accounts. 

The FMV capital accounts shall be increased and decreased as follows: 

5.2.1. The FMV capital account of a Party shall be increased by: 

(1) the amount of money and the FMV (as of the date of contribution) of any property contributed by such Party to the Partnership (net
of liabilities assumed by the Partnership or to which the contributed property is subject); 
 (2) that Party’s share of
Partnership items of income or gain, allocated in accordance with Sec. 6.1 and Sec. 9.2; 

  
 7 








 (3) that Party’s share of basis increases pursuant to Treas. Reg.
§1.704-1(b)(2)(iv)(j) or any item to be treated in a similar manner; and 
 (4) that Party’s share of any Code
§705(a)(l)(B) item. 
 5.2.2. The FMV capital account of a Party shall be decreased by: 

(1) the amount of money and the FMV of property distributed to such Party (net of liabilities assumed by such Party or to which the
property is subject); 
 (2) that Party’s Sec. 6.1 and Sec. 9.2 allocated share of Partnership loss and deductions, or
items thereof; 
 (3) that Party’s share of basis decreases pursuant to Treas. Reg. §1.704-1(b)(2)(iv)(j) or any item
to be treated in a similar manner; and 
 (4) that Party’s share of any Code §705(a)(2)(B) item or any item treated
as such under Treas. Reg. §1.704-1(b)(2)(iv)(i). 
 5.2.3. “FMV” when it applies to property contributed by a
Party to the Partnership shall be assumed, for purposes of Sec. 5.2.1, to equal the adjusted tax basis, as defined in Code §1011, of that property unless the Parties agree otherwise as indicated in Sec. 9.1. 

5.2.4. As provided in Treas. Reg. §1.704-1(b)(2)(iv)(e), upon distribution of Partnership property to a Party the capital accounts
will be adjusted to reflect the manner in which the unrealized income, gain, loss and deduction inherent in distributed property (not previously reflected in the FMV capital accounts) would be allocated among the Parties if there were a taxable
disposition of such property at its FMV as of the time of distribution. Furthermore, if so agreed to in Sec. 9.1, under the rules of Treas. Reg. § 1.704-1(b)(2)(iv)(f), the FMV capital accounts shall be revalued at certain times to reflect
value changes of the Partnership property. 
  

	 	6.	Partnership Allocations 

 6.1.
FMV Capital Account Allocations. 
 Unless otherwise provided in Sec. 9.2, each item of income, gain, loss, or deduction shall
be allocated to each Party as follows: 
 6.1.1. Actual or deemed income from the sale, exchange, distribution or other
disposition of production shall be allocated to the Party entitled to such production or the proceeds from the sale of such production. The amount received from the sale of production and the amount of the FMV of production taken in kind by the
Parties are deemed to be identical; accordingly, such items may be omitted from the adjustments made to the FMV capital accounts of the Parties. 

  
 8 








 6.1.2. Exploration costs, IDC, operating and maintenance costs shall be allocated to each
Party in accordance with its respective contribution, or obligation to contribute, to such cost. 
 6.1.3. Depreciation shall
be allocated to each Party in accordance with its respective contribution, or obligation to contribute, to the cost of the underlying asset. 
 6.1.4. Simulated depletion shall be allocated to each Party in accordance with its FMV capital account adjusted basis in each oil and gas property of the Partnership. 

6.1.5. Except as provided in Sec. 7.4, loss (or simulated loss) upon the sale, exchange, distribution, abandonment or other disposition
of depreciable or depletable property shall be allocated to the Parties in the ratio of their respective FMV capital account adjusted bases in the depreciable or depletable property. 

6.1.6. Gain (or simulated gain) upon the sale, exchange, distribution, or other disposition of depreciable or depletable property shall
be allocated to the Parties so that the FMV capital account balances of the Parties will most closely reflect their respective percentage or fractional interests in such property under the Underlying Agreement. 

6.1.7. Costs or expenses of any other kind shall be allocated to each Party in accordance with its respective contribution, or
obligation to contribute, to such costs or expenses. 
 6.1.8. Any other income item shall be allocated to the Parties in
accordance with the manner in which such income is realized by each Party. 
 6.2. Tax Return and Tax Basis Capital Account
Allocations. 
 6.2.1. Unless otherwise expressly provided in this Sec. 6.2, the allocations of the Partnership’s items of
income, gain, loss, or deduction for tax return and tax basis capital account purposes shall follow the principles of the allocations under Sec. 6.1. However, the Partnership’s gain or loss on the taxable disposition of a Partnership property
in excess of the gain or loss under Sec. 6.1, if any, is allocated to the contributing Party to the extent of such Party’s pre-contribution gain or loss. 
 6.2.2. The Parties recognize that under Code §613A(c)(7)(D) the depletion allowance is to be computed separately by each Party. For this purpose, each Party’s share of the adjusted tax basis in
each oil and gas property shall be equal to its contribution to the adjusted tax basis of such property. 
 6.2.3. Under Code
§613A(c)(7)(D), gain or loss on the disposition of an oil and gas property is to be computed separately by each Party. According to Treas. Reg. §1.704-1(b)(4)(v), the amount realized shall be allocated as follows: (i) an amount that
represents recovery of adjusted simulated depletion basis is allocated 

  
 9 








 
(without being credited to the FMV capital accounts) to the Parties in the same proportion as the aggregate simulated depletion basis was allocated to such Parties under Sec. 5.2; and
(ii) any remaining realization is allocated in accordance with Sec. 6.1.6. 
 6.2.4. In accordance with Treas. Reg.
§1.1245-1 (e), depreciation recapture shall be allocated, to the extent possible, among the Parties to reflect their prior sharing of the depreciation. 
 6.2.5. In accordance with the principles of Treas. Reg. §1.1254-5, any recapture of IDC is determined and reported by each Party separately. Similarly, any recapture of depletion shall be computed
separately by each Party, in accordance with its depletion allowance computed pursuant to Sec. 6.2.2. 
 6.2.6. For Partnership
properties with FMV capital account values different from their adjusted tax bases, subject to Sec. 6.2.3, 6.2.4 and 6.2.5, the Parties intend that allocations be made pursuant to the “traditional method with curative allocations” under
Treas. Reg. §1.704-3(c). 
 6.2.7. The qualified investment for investment tax credit purposes with respect to any
property shall be allocated among the Parties in accordance with their respective contributions to the qualified investment (as defined in the Code) in such property. 
 6.2.8. Take-in-kind. 
 If indicated “Yes” in Sec. 9.1, below, each Party
has the right to determine the market for its proportionate share of production. All items of income, deductions, and credits arising from such marketing of production shall be recognized by the Partnership and shall be allocated to the Party whose
production is so marketed. If indicated “No” in Sec. 9.1, below, the take-in-kind production of each Party will be treated as distributed to such Party. 
  

	 	7.	Termination and Liquidating Distribution 

 7.1. Termination of the Partnership. 
 The Partnership shall terminate upon the
first to occur of (a) a deemed termination of the Partnership pursuant to Code §708(b)(1)(A), (b) the effectiveness of an election by the Parties to be excluded from the application of Subchapter K of Chapter 1 of the Code (if and
when the Parties unanimously agree to make such an election) or (c) the occurrence of any other event which causes the Partnership to terminate as a matter of federal or state tax law. 

Upon termination, as provided in Code §708(b)(1)(A), the business shall be wound-up and concluded, and the assets shall be
distributed to the Parties as described below by the end of such calendar year (or, if later, within ninety (90) days after the date of such termination). The assets shall be valued and distributed to the Parties in the order provided in Secs.
7.2, 7.6, and 7.8 

  
 10 









 7.2. Return of Unexpended Contributions and Unshared Property 

First, all cash representing unexpended contributions by any Party and any property in which no interest has been earned by any other
Party in that property under the Underlying Agreement shall be returned to the contributor. 
 7.3. Balancing of FMV Capital
Accounts. 
 Second, the FMV capital accounts of the Parties shall be determined as described hereafter. The TRP shall take the
actions specified under Secs. 7.3 through 7.6 in order to cause FMV capital accounts of the Parties to reflect as closely as possible their interests under the Underlying Agreement. This is hereafter referred to as the “balancing of the FMV
capital accounts” and, when each Party’s FMV capital account balance is equal to the fair market value of its interest in the Partnership’s properties under the Underlying Agreement, the FMV capital accounts of the Parties shall be
referred to as “balanced.” 
 7.4. Deemed Sale Gain/Loss Charge Back. 

The FMV of all Partnership properties shall be determined and the gain or loss for each property, which would have resulted if sold at
such FMV, shall be allocated to the Parties to cause (to the extent possible) the FMV capital accounts of the Parties to reflect as closely as possible their interests under the Underlying Agreement. 

7.5. No Deficit Restoration Obligation. 
 Notwithstanding anything to the contrary, upon a liquidation within the meaning of Treas. Reg. §1.704-1(b)(2)(ii)(g), if any Party has a Deficit Capital Account (after giving effect to all
contributions, distributions, allocations and other FMV capital account adjustments for all years, including the year during which such liquidation occurs), such Party shall have no obligation created hereby to make any contribution so as to restore
its FMV capital account to zero, and the negative balance of such Party’s FMV capital account shall not be considered a debt owed by such Party to the other Party(ies), to the tax partnership, or to any other person for any purpose whatsoever.
This Sec. 7.5 shall not affect the obligations that the Parties may have without regard to the TPPs. 
 7.6. Distribution to
balance capital accounts. 
 7.6.1. If the Parties agree, any cash or an undivided interest in certain selected properties
shall be distributed to one or more Parties as necessary for the purpose of balancing the FMV capital accounts. 

  
 11 









 7.6.2. Unless Sec.7.6.1 applies, an undivided interest in each and every property shall be
distributed to one or more Parties in accordance with their FMV capital accounts. 
 7.7. FMV determination. 

If a property is to be valued for purposes of balancing the capital accounts and making a distribution under this Sec. 7, the Parties
must first attempt to agree on the FMV of the property; failing such an agreement, the TRP shall cause a nationally recognized independent engineering firm to prepare an appraisal of the FMV of such property. 

7.8. Final Distribution. 
 After the FMV capital accounts of the Parties have been adjusted pursuant to Secs.7.3 to 7.6, all remaining property and interests then held by the Partnership shall be distributed to the Parties in
accordance with their positive FMV capital account balances. 
  

	 	8.	Transfers, Indemnification, and Correspondence 

 8.1. Transfer of Partnership Interests. 
 Transfers of Partnership interests shall
be governed by the Underlying Agreement. These TPPs shall inure to the benefit of and be binding upon the Parties hereto and their successors and assigns. A Party transferring its interest, or any part thereof, shall notify the TRP in writing within
two (2) weeks after such transfer. 
 8.2. Correspondence. 

All correspondence relating to the preparation and filing of the Partnership’s income tax returns and capital accounts shall be sent
to: 
 (Attach separate list, if necessary) 
  

			
	 TRP
  
	  	“Attn to:” reference
	Dejour Energy (USA) Corp.	  	Land Department
	1401 17th Street, Suite 850	  	
	Denver, CO 80202	  	

  

			
	 Other Party:
  
	  	
	 Bakken Drilling Fund III LP

5251 DTC Parkway, Suite 200
 Greenwood Village,
CO 80111
	  	Don Scott

 8.3. Indemnification. 
 Bakken Drilling Fund III LP shall indemnify and save harmless Dejour Energy (USA) Corp. and its agents, employees, officers and directors from all suits, actions, or


  
 12 









 
claims of any character, type, or description brought or made for or on account of any injuries or damages received or sustained by any person or persons, arising out of, or occasioned as a
result of tax treatment by the Internal Revenue Service, by the acts of Dejour Energy (USA) Corp. or its agents, employees, officers and directors, in the execution or performance as the TMP or TRP Tax, if Dejour Energy (USA) Corp. acted in good
faith and acted without fraud, deceit, gross negligence, willful misconduct or intentional breach of the Underlying Agreement or these TPPs. 
  

	 	9.	Elections and Changes to above Provisions 

 9.1. Special Tax Elections. 
 With respect to Sec. 4.1, the Parties agree (if not
agreed, insert “No”): 
  

			
	a) that the Partnership shall elect to account for dispositions of depreciable assets under the general asset method to the extent permitted by Code §168(i)(4).	  	No
	b) that the Partnership shall elect under Code §754 to adjust the basis of Partnership property, with the adjustments provided in Code §734 for a distribution of property
and in Code §743 for a transfer of a partnership interest. In case of distribution of property the TRP shall adjust all tax basis capital accounts. In the case of a transfer of a partnership interest the acquiring party(ies) shall establish and
maintain its (their) tax basis capital account(s).	  	Yes
	c) that the Partnership shall elect under Code §6231 to be subject to the TEFRA rules.	  	No
	d) that the Partnership shall elect under Code §709 to amortize over the shortest permissible period all deferred organizational expenses.	  	Yes
	e) that the Partnership shall elect under Code §195 to amortize over the shortest permissible period all deferred business start-up expenses.	  	Yes
		
	With respect to Sec. 4.2. Depletion the Parties agree that the Partnership shall use simulated percentage depletion instead of simulated cost depletion.	  	No
	With respect to Sec. 5.2.4, under the rules of Treas. Reg. § 1.704-1(b)(2)(iv)(f) the Parties agree that the FMV capital accounts shall be revalued to reflect value
changes of the Partnership property upon the occurrence of the events specified in (5)(i) through (iii) of said -1(b)(2)(iv)(f) regulations.	  	Yes
	With respect to Sec. 6.2.8, the income attributable to take-in-kind production will be reflected on the tax return.	  	No

 With respect to Sec. 5.2.3, the FMV for the listed properties are determined on Schedule 5.2.3, which
shall describe each property that becomes subject to the Underlying Agreement and the agreed fair market value of such property at the time it becomes subject to the Underlying Agreement. 

9.2. Special Allocations. 
 9.2.1. Notwithstanding the provisions of Sec. 6, if any Party unexpectedly receives any adjustments, allocations or distributions described in Treas. Reg. §1.704 1(b)(2)(ii)(d)(4),
(5) or (6), which reduces the adjusted FMV capital 

  
 13 









 
account balance of such Party to below zero (a “Deficit Capital Account”), gross income shall be specially allocated to such Party in an amount and manner sufficient to eliminate, to
the extent required by the Treasury Regulations, the adjusted capital account deficit of such Party as quickly as possible. For purposes of this Sec. 9.2.1 and Sec. 9.2.3, the adjusted FMV capital account balance of a Party shall be the same as such
Party’s capital account balance increased by the sum of (i) amount, if any, which such Party is unconditionally obligated to contribute to the tax partnership, and (ii) the amount, if any, which such Party is deemed to be obligated to
contribute to the tax partnership under Treasury Regulations under Code §704(b). 
 9.2.2. If there is a net decrease in
partnership minimum gain for a taxable year of the tax partnership, each Party shall be allocated items of income and gain for that year equal to that Party’s share of the net decrease in partnership minimum gain, all in accordance with Treas.
Reg. §1.704-2(f). If, during a taxable year of the tax partnership, there is a net decrease in partner nonrecourse debt minimum gain, any Party having a share of that partner nonrecourse debt minimum gain as of the beginning of the year shall
be allocated items of income and gain for the year (and, if necessary, for succeeding years) equal to that partner’s share of the net decrease in partner nonrecourse debt minimum gain, all in accordance with Treas. Reg. §1.704-2(i)(4).
Pursuant to Treas. Reg. §1.704-2(i)(l), deductions attributable to “partner nonrecourse liability” shall be allocated to whichever Party bears the economic risk of loss for such liability (or is treated as bearing such risk).

 9.2.3. If any Party would be allocated an item of deduction or loss which would reduce its adjusted FMV capital account
balance to below zero, such Party shall be allocated only the amount of such item which would reduce its adjusted FMV capital account balance to zero, and any remaining amount of such item shall be allocated to the other Parties. 

9.2.4. The allocations set forth in Secs. 9.2.1, 9.2.2 and 9.2.3 (the “Regulatory Allocations”) are intended to comply with
certain requirements of Treasury Regulations. It is the intent of the Parties that, to the extent possible, all Regulatory Allocations shall be offset either with other Regulatory Allocations or with special allocations of other items of income,
gain, loss or deduction pursuant to this Sec. 9.2.4. Therefore, notwithstanding any other provisions of Sec. 6, the TRP shall make such offsetting special allocations of income, gain, loss or deduction in whatever manner it determines appropriate so
that, after such offsetting allocations are made, the FMV capital account balance of each Party is, to the extent possible, equal to the capital account balance such Party would have had if the Regulatory Allocations were not part of the TPPs and
all items were allocated pursuant to Sec. 6 without regard to the Regulatory Allocations. The TRP shall have the discretion to administer this Sec. 9.2.4 in any reasonable manner which eliminates, to the extent reasonably feasible, any character
discrepancy between the amounts allocated under Regulatory Allocations and the corresponding amounts allocated under this Sec. 9.2.4. 

  
 14 









 9.3. Change of Required Approval for Other Elections. 

Notwithstanding Sec. 4.4, the following tax elections shall be approved by the Parties holding the following threshold of interests under
the Underlying Agreement (to be measured after Payout (as defined in the Underlying Agreement): 
  

			
	Election	  	Threshold
	N/A	  	N/A


  
 15 









 Schedule 5.2.3 to 
 Tax Partnership Provisions of the [DEJOUR-BDF III] 2012 Tax Partnership, EIN: [—] 

Fair Market Value of Property Contributed to 
 [DEJOUR-BDF III] 2012 Tax Partnership (EIN [—]) 
  

							
	 Contributor
	  	Property	  	Fair Market Value	 
	 Bakken Drilling Fund III LP
	  	Cash	  	$	4,850,000	  
	 Dejour Energy (USA) Corp.
	  	Contributed Leases	  	$	1,147,779.43	  








 EXHIBIT “H” 

Attached to and made a part of that certain Operating Agreement dated December 31, 2012, 

by and between Dejour Energy (USA) Corp., as Operator, 
 and Bakken Drilling Fund III LP, as Non-Operator 
 WELL INFORMATION REQUIREMENTS

  

	A.	The following information shall be furnished, free of charge, to the Consenting Parties, when requested of Operator: 


 

	 	1.	A written summary of your drilling, logging, and casing program at least 48 hours prior to the spudding of the well. 


 

	 	2.	One copy each of the staked location survey plat and the state drilling permit. This information shall be furnished at least 48 hours prior to the spudding of the well.


  

	 	3.	A daily drilling/completion report and mud log, if mud logger is used. 

  

	 	4.	One copy of each report filed with any State or Federal regulatory agency. 


 

	 	5.	One copy of any log, survey or analysis at the time it is run. 

  

	 	6.	The following information shall be furnished within seven (7) days after reaching total depth, or as soon as the listed information is available, whether the well
is a producer or a dry hole: 

  

	 	(a)	One copy of each wireline log (open hole and cased hole) run. 

  

	 	(b)	One composite sepia (or film) copy of each open hole log run. 

  

	 	(c)	One copy of the composite mud log, if a mud logger is used. 

  

	 	(d)	One LAS format composite library tape of each open hole log run. 

  

	 	(e)	One copy of any core descriptions, studies, or analyses. 

  

	 	(f)	One copy of any chemical analysis and each drill stem, pressure or production test. 


 

	B.	Unwashed cuttings samples, if collected, are requested for this well. 


  
  

			
	Exhibit H – Well Information Requirements	  	Sole Page