Document:

EX-10.26

 Exhibit 10.26 

Specific Terms in this Exhibit have been redacted because confidential treatment for those terms has been requested. The redacted material has been separately
filed with the Securities and Exchange Commission, and the terms have been marked at the appropriate place with three asterisks [***]. 

DEFINITIVE AGREEMENT 

FOR THE DIVISION OF OPERATORSHIP 

FOR 
 BLACKSMITH —
MAGNOLIA AREA OF MUTUAL INTEREST 
 This Definitive Agreement for the Division of Operatorship (the “Definitive Agreement”),
executed on the date(s) indicated below, but effective for all purposes as of November 1, 2012 (“Effective Date”), is by and between Encana Oil & Gas (USA) Inc. (“Encana”) a Delaware corporation, whose address is
5851 Legacy Circle, Plano, Texas 75024, and SWEPI LP (“Shell”), a Delaware limited partnership whose address is P.O. Box 576, Houston, Texas 77001. Encana and Shell may hereinafter be referred to individually as a “Party”
and collectively as the “Parties”. 
 RECITALS 

WHEREAS, the Parties entered into that certain Blacksmith Acquisition and Exploration Agreement (the “Exploration Agreement”) dated
April 16, 2007, which, among other things, created an AMI (as defined below); and 
 WHEREAS, the Parties entered into that certain
Well Cap Agreement (the “Well Cap Agreement”) dated August 10, 2009, which, among other things, divided the AMI into two operational boundaries (each, an “Operational Boundary” and collectively, the “Operational
Boundaries”), in each of which a particular Party was intended to serve as Operator, as hereafter defined, of the wells drilled therein. Operational Boundaries are generally described as follows: DeSoto and Sabine Parishes, Louisiana are
generally operated by Shell; Red River and Natchitoches Parishes, Louisiana are generally operated by Encana; and 
 WHEREAS, the Parties
entered into that certain letter agreement dated September 11, 2009 (the “Termination Agreement”), whereby the Parties acknowledged completion of the Exploration Program as defined in the Exploration Agreement and as a result,
terminated the Exploration Agreement except for certain provisions thereof, which, among other things, require that the Parties mutually agree upon an efficient and equitable geographic division of operatorship in the AMI, within thirty
(30) days of the end of the first calendar quarter of 2011; and 
 WHEREAS, the Parties amended the Termination Agreement to extend the
timeframe for mutually agreeing on a geographic division of operatorship in the AMI by Letter Agreement dated December 20, 2011 (the “Third Amendment”), which stipulates that on or before January 20, 2012, the Parties shall
mutually agree upon an efficient and equitable geographic division of the AMI so that each Party is Operator of approximately fifty percent (50%) of the then current Acreage; and 

 WHEREAS, subsequent to the creation of the AMI, the Parties drilled, completed and are currently
operating numerous producing gas wells in the AMI; and 
 WHEREAS, the Parties entered into that certain Preliminary Agreement for the
Division of Operatorship, dated January 19, 2012, by and between the Parties (the “Preliminary Agreement”) for the purpose of agreeing on an efficient and equitable geographic division of the AMI so that each Party will be the
Operator of approximately fifty percent (50%) of the Acreage; and 
 WHEREAS, the Parties entered into that certain Fifth Amendment to the
Preliminary Agreement for the Division of Operatorship (the “Fifth Amendment”) dated August 31, 2012 to extend the timeframe for completing the Definitive Agreement and to extend the JOA coverage for drilled wells in which a JOA has
not yet been executed; and 
 WHEREAS, the Parties have agreed upon a process for the division of Operatorship and have transferred and will
continue to transfer Operatorship of Developed Acreage consistent with said process such that Encana will be the Operator of the Developed Acreage listed on Exhibit “A” and Shell will be the Operator of the Developed Acreage listed on
Exhibit “B”; and 
 WHEREAS, the Parties are entering into this Definitive Agreement for the purpose of setting forth the terms
under which the Parties shall operate and develop Acreage within the AMI from and after the Effective Date hereof. 
 NOW, THEREFORE, in
consideration of the premises and the mutual obligations and conditions contained herein, the sufficiency of which is hereby acknowledged, the Parties agree as follows: 

ARTICLE 1 — DEFINITIONS AND EXHIBITS 

1.1 Definitions. The following defined terms have the meaning given herein as follows: 

 

	 	(a)	“Acreage” shall refer collectively to the Developed Acreage and the Undeveloped Acreage, which terms are defined in this Section 1.1. 

 

	 	(b)	“Affiliate” shall mean a company which, directly or indirectly through one or more intermediaries, controls or is controlled by, or is under common control with a Party. For this purpose
“control” means the direct or indirect ownership of in aggregate fifty percent (50%) or more of the voting capital. 

  

	 	(c)	“AMI” shall mean the area of mutual interest established by the Exploration Agreement, as amended by the Termination Agreement. Notwithstanding termination of the AMI pursuant to Article 2(b) of the
Termination Agreement, references to the AMI throughout this Definitive Agreement shall refer to the boundaries of the AMI as they existed immediately prior to termination thereof. 

  
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	 	(d)	“Blacksmith Agreements” shall collectively refer to the Exploration Agreement, the Well Cap Agreement, the Termination Agreement, the Third Amendment and the Preliminary Agreement (as amended by the
Fifth Amendment), each of which is defined in the recitals above. 

  

	 	(e)	“Block JOA” shall mean the form of JOA which was attached as Exhibit “E” to the Exploration Agreement, and which was adopted by the Parties for operations within each of the Drilling
Blocks. 

  

	 	(f)	“Change of Operator Form” shall mean either 1) Form
MD-10-R-A-1, titled “application to amend permit to drill for minerals”, or 2)
Form MD-10-R-AO, titled “application to amend permit to drill mineral or injection wells”, as appropriate, which is
submitted to the Commissioner for regulatory approval of a change of Operator. 

  

	 	(g)	“Commissioner” shall mean the Commissioner of Conservation for the State. 

  

	 	(h)	“Confidential Information” shall have the meaning given to it in Section 6.1 below. 

  

	 	(i)	“Current Operator” shall mean the Party that is the Operator of the specific Developed Acreage from the Effective Date of this Definitive Agreement until the Transfer Date of such Developed Acreage.

  

	 	(j)	“Developed Acreage” shall mean all Leases owned by the Parties in which a Unit exists and contains a well that is drilling, producing or capable of production (including drilled but not completed) from
the Haynesville Zone or Jurassic formations, as defined by the Commissioner. 

  

	 	(k)	“DNR” shall mean the Department of Natural Resources for the State. 

  

	 	(l)	“Drilling Block” shall mean the eight drilling blocks, covering up to the equivalent of sixteen (16) government sections apiece, which were established by the Parties pursuant to Article 4 of the
Exploration Agreement. 

  

	 	(m)	“Industry JOA” shall mean the form of JOA attached hereto and incorporated herein as Exhibit “D”. 

  

	 	(n)	“JOA” shall mean joint operating agreement. 

  

	 	(o)	“Lease(s)” shall mean any oil, gas and mineral lease, sublease, or other similar or related agreements within the boundaries of the AMI in which both Parties own an undivided interest as a result of or
in connection with the Blacksmith Agreements. The term Lease(s) shall also include, without limitation, any surface leases, subsurface servitude agreements, and other similar agreements which are directly related to Leases. 

  
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	 	(p)	“Lease Payment” shall have the meaning given to it in Section 4.1 below. 

  

	 	(q)	“Memorandum” shall mean an appropriate memorandum of Lease, memorandum of JOA, or other such memorandum containing the information required by Louisiana law to place third parties on notice of the
agreement when filed in the appropriate parish records for the parishes) in which the affected real property is located. 

  

	 	(r)	“Notice” shall mean written notice provided in accordance with Article 9 below. 

  

	 	(s)	“Operator” shall mean the Party that is designated as operator of record with the DNR for a particular Unit. 

  

	 	(t)	“Operatorship” shall mean the right to be the Operator. 

  

	 	(u)	“Pro Forma JOA” shall mean the form of JOA which was attached as Exhibit “A” to the Termination Agreement, and which was adopted by the Parties for operations on all Acreage outside of the
Drilling Blocks. 

  

	 	(v)	“Regulatory Transfer Date” shall mean the effective date reflected on the applicable Change of Operator Form, for the Developed Acreage, which shall be on the 1st day of the month in which the well is
transferred. 

  

	 	(w)	“State” shall mean the State of Louisiana. 

  

	 	(x)	“Transfer Date” shall mean the actual date on which Operatorship of specific Developed Acreage is physically transferred from the Current Operator to the Operator; provided, however, for revenue
accounting and production volume reporting purposes the Transfer Date shall be effective on the first day of the month in which the actual transfer occurs. 

  

	 	(y)	“Undeveloped Acreage” shall mean all Leases owned by the Parties which are not Developed Acreage. Once Undeveloped Acreage is developed by unitization and the drilling of the initial Unit well, it will
be deemed to become, for purposes of this Definitive Agreement, Developed Acreage. 

  

	 	(z)	“Unit” shall mean a drilling and production unit established by order of the Commissioner. 

1.2 Exhibits. The following Exhibits are attached hereto and are incorporated and made a part hereof: 

 

	 	(a)	Exhibit “A” — Schedule of Developed Acreage to be operated by Encana upon completion of the transfers set forth in Section 2.1 below. 

 

	 	(b)	Exhibit “B” — Schedule of Developed Acreage to be operated by Shell upon completion of the transfers set forth in Section 2.1 below. 

  
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	 	(c)	Exhibit “C” — Map depicting post-transfer Operatorship of the Developed Acreage. 

  

	 	(d)	Exhibit “D” — Form of Industry JOA. 

 ARTICLE 2 — TRANSFER OF
OPERATORSHIP AND REGULATORY COMPLIANCE 
 2.1 Transfer of Operatorship. The Parties acknowledge and agree that they have
established an informal process for transferring Operatorship of Developed Acreage in order to accomplish the division, of Operatorship required by the Termination Agreement and have followed the process for all transfers of Operatorship that have
been completed prior to the execution of this Definitive Agreement. The Parties shall continue to transfer Operatorship of the Developed Acreage in accordance with the process until Encana is the Operator of Developed Acreage reflected on Exhibit
“A” and Shell is the Operator of Developed Acreage reflected on Exhibit “13”, in each case, no later than December 31, 2012, except as otherwise agreed by the Parties. Notwithstanding anything contained in this Definitive
Agreement to the contrary, the transfer of Operatorship of Developed Acreage is expressly subject to and contingent upon the DNR’s approval of the requested change of Operator. 

2.2 Signage. The Parties shall take such actions as may be necessary or appropriate so that the signage for Developed Acreage
accurately reflects the Operator on the Transfer Date in accordance with applicable State law and/or regulations. 
 2.3 Reporting to the
State. The Current Operator shall continue to file any required documents or reports with the State until such time as the transfer of Operatorship has been approved by the DNR, after which time the Operator shall assume such obligations with
respect to such Developed Acreage beginning with the Regulatory Transfer Date. The Parties will reasonably cooperate in order to file the reports required to be filed by each Party. 

2.4 Compliance with Leases, Laws and Regulations. The Operator, or Current Operator, as appropriate, shall comply with the terms of the
Leases and with applicable laws and regulations. 
 ARTICLE 3 — TERMINATION OF BLACKSMITH AGREEMENTS 

From and after the Effective Date of this Definitive Agreement, the Parties agree that the Blacksmith Agreements shall terminate in their
entirety and shall have no further force or effect, except that with respect to wells covered by the Well Cap Agreement, the Well Cap Agreement shall continue to apply as originally written. 

ARTICLE 4 — LEASE OBLIGATIONS 

4.1 Definition of Lease Payments. For purposes of this Definitive Agreement, a “Lease Payment” shall mean a payment by a
Party or an Affiliate, other than Lease royalty payments, related to existing Leases including, but not limited to, extension payments, bonus clause payments, delay rental payments, option extension payments, bonus payments and payments made to
exercise rights under a Lease option agreement, where such payment is necessary to prevent the termination or extinguishment of all or part of a Lease or Unit or Lease option agreement (an “Extinguishment Event”), or to exercise rights
under a Lease option agreement at the end of the term of the option agreement. 

  
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 4.2 Administration of Lease Payments. All Lease Payments on Developed Acreage, including
but not limited to shut-in well payments, shall be administered by the Operator of the Developed Acreage. Lease Payments on Undeveloped Acreage shall be administered by the Party that acquired the Lease(s), or
the Party on whose behalf such Lease(s) was acquired by a broker. If the Party responsible for administering a Lease Payment (the “Administering Party”) pursuant to the foregoing provisions decides not to make any such Lease Payment, such
Party will notify the other Party (the “Non-Administering Party”) as soon as possible, but no later than sixty (60) days prior to the date any Lease Payment is due, of its decision so
that the Non-Administering Party may make such Lease Payment for its sole account. The Administering Party will relinquish its interest in the applicable Acreage that would have been lost for failure to make
such Lease Payments by assigning one hundred percent (100%) of its interest in the applicable Acreage to the Non-Administering Party within thirty (30) days of receipt of written Notice from the Non-Administering Party, with proof of payment enclosed, that payment has been made. If neither Party elects to make a Lease Payment, each Party shall be responsible for recording in the applicable parish or
parishes any release of the Party’s interest required by the Lease or by State law. 
 4.3 Notification. All Lease Payments paid
or proposed to be paid by an Administering Party will be reported to the Non-Administering Party via written Notice given by the Administering Party either before the payment is tendered or no later than
thirty (30) days after the payment is tendered. Such Notice shall include, but not be limited to, a description of the type of payment, a description of the oil and gas Lease(s) and lands covered by the payment, the cost of the payment,
and, if payment has already been tendered, a copy of proof of payment. 
 4.4 Election. The
Non-Administering Party shall have thirty (30) days after receipt of the Notice from the Administering Party to furnish the Administering Party with written Notice of its election to pay its proportionate
share of the Lease Payment. Failure to provide such Notice within the required period will be deemed an election by the Non-Administering Party not to tender payment to maintain its proportionate share of the
Leases(s). An election made by the Non-Administering Party to pay its proportionate share of a Lease Payment is made without any recourse for the return of its proportionate share of such payment from the
Administering Party, even if the Parties are able to otherwise maintain such Lease by conducting drilling operations. 
 4.5
Assignments. If a Non-Administering Party elects not to pay, or is deemed to have elected not to pay, its proportionate share of a Lease Payment after receipt of Notice from the Administering Party. The
Non-Administering Party shall, within thirty (30) days of giving its Notice or within thirty (30) days of being deemed to have elected not to make a payment, deliver to the Paying Party an
assignment of 100% of its interest in the applicable Lease(s). 

  
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 ARTICLE 5 — OPERATING AGREEMENTS 

5.1 Risk Fee Option Unavailable. It is agreed between the Parties that, with respect to Acreage covered by this Definitive Agreement,
the risk fee option available to an Operator under Louisiana Revised Statutes Section 30:10 is not an available option to the Parties in those instances where the non-Operator Party elects not to
participate in a proposed well. Therefore, within thirty (30) days of an initial well being spud in any Unit with respect to Acreage covered by this Definitive Agreement, the Parties shall execute a JOA and Memorandum of JOA in accordance with
Section 5.2 below. The Operator shall record a copy of the signed Memorandum of JOA in the official conveyance records for the parish(es) in which the Unit is located within thirty (30) days after execution thereof. 

5.2 Industry JOA. From and alter the Effective Date of this Definitive Agreement, the Parties agree that all existing Block JOAs and
Pro Forma JOAs are hereby terminated, and the Parties further agree that all operations on Acreage in the AMI, notwithstanding any executed Block JOA or Pro Forma JOA to the contrary, shall be deemed to be governed by the terms and conditions of the
Industry JOA. The Parties shall, promptly following the execution of this Definitive Agreement, but in no event later than July 1, 2013 execute in place of each terminated Block JOA or Pro Forma JOA an Industry JOA, each of which shall have a
contract area identical to the area covered by a single Unit. Following execution of each Industry JOA, the Operator under the Industry JOA for the applicable Unit shall record an appropriate Memorandum of Industry JOA in the real property records
for the parish(es) in which the contract area therefore is located. 
 5.3 Existing Third Party JOAs. The Parties acknowledge that
they have executed a number of JOAs with various third parties covering Units in the AMI. This Definitive Agreement shall have no effect on such third party JOAs, which shall continue in force and effect in accordance with the terms thereof. 

ARTICLE 6 — CONFIDENTIALITY 

6.1 Definition of Confidential Information. Confidential and proprietary data referred to herein as “Confidential
Information” shall include, but not be limited to, each Party’s geological, geophysical, land, engineering, environmental, and well information, technical information, including interpretations and models covering the AMI, all geological
and geophysical data acquired or produced by the Parties and funded by the joint account, together with all legal information, terms, negotiations or any other information regarding the business transactions between the Parties pursuant to this
Definitive Agreement, or information regarding any aspect of the Definitive Agreement itself. The term Confidential Information shall not include information that (a) is in a Party’s or its Affiliate’s possession prior to
disclosure, (b) is or becomes known to the public other than as a result of a breach of this Definitive Agreement, (c) becomes available to a Party on a non-confidential basis from a source other
than the other Party and not as a result of any breach of this Definitive Agreement or (d) is developed by a Party without the use of Confidential Information. 

6.2 No Disclosure. Unless required by law, including without limitation any applicable securities laws, absent express written consent
of the other Party, neither Party, except as modified by that certain Waiver of Confidentiality dated April 2, 2012, shall disclose the Confidential Information to any person or entity, including current leaseholders and mineral owners
in the AMI, except to its own and its Affiliates’ officers, directors, employees and outside attorneys, accountants and financial, engineering and geological advisors, agents, 

  
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consultants, representatives, on a need-to-know basis, and each Party agrees to direct such persons to not disclose
to any other person or persons the Confidential Information, and accepts full responsibility should they disclose such. Notwithstanding the foregoing, without consent of the other Party, either Party may disclose the Confidential information to a
third party who agrees in writing to the equivalent or more stringent confidentiality terms included herein to keep the disclosures confidential, solely for purposes of evaluating the possibility of entering into a transaction pursuant to which the
third party would acquire all or substantially all of the disclosing Party’s interest in the AMI. 
 6.3 Unauthorized Access.
The Parties shall use reasonable efforts to prevent access by unauthorized persons to the Confidential Information, such efforts to reflect at least the same general degree of security that each Party accords its own Confidential Information, but in
any event not less than a reasonable degree of care. 
 6.4 Compulsory Disclosure. In the event either Party is requested or required
under compulsion of legal process to disclose Confidential Information, such Party shall not, unless required by law, disclose the Confidential Information until the other Party has first (a) received prompt written notice of such
request or requirement to disclose, and (b) had an adequate opportunity to obtain a protective order or other reliable assurance that confidential treatment will be accorded to its Confidential Information. The Party so requested shall not
oppose actions by the other Party to assure such confidential treatment. 
 6.5 Announcements. Except to the extent permitted above,
neither Party shall issue any press release or make any public announcement related to this Definitive Agreement or the activities hereunder without the prior written consent of the other Party. Copies of any permitted press release or announcement
shall be sent to the other Party for approval in advance of its publication, so that the other Party may make comments and/or modifications. 

ARTICLE 7 — DISPUTE RESOLUTION 

Any dispute, controversy, or claim (a “Dispute”) arising out of or in connection with this Definitive Agreement and which is not
otherwise resolved by procedures set forth in this Definitive Agreement shall be referred to and determined by binding arbitration, as the sole and exclusive remedy of the Parties as to the Dispute, conducted in accordance with the American
Arbitration Association (“AAA”) rules for arbitration of commercial disputes (the “Rules”), which are deemed to be incorporated by reference, except that in the event of any conflict between those Rules and the arbitration
provisions set forth below, the provisions set forth below shall govern and control. The arbitral tribunal (the “Tribunal”) shall apply the law referred to in Section 10.3 of the Definitive Agreement in resolving the Dispute. The
Tribunal shall be composed of three arbitrators knowledgeable in oil and gas law, with each Party appointing one arbitrator, and the two arbitrators so appointed appointing the third arbitrator who shall act as Chairman of the Tribunal. If any
arbitrator fails to be appointed as aforesaid, then such arbitrator shall be appointed by the AAA in accordance with the Rules. The arbitration shall be held in Houston, Texas and the proceedings shall be conducted and concluded as soon as
reasonably practicable, based upon the schedule established by the Tribunal, but in any event the decision of the Tribunal shall be rendered within ninety (90) days following the selection of the Chairman of the Tribunal. The decision of the
Tribunal shall be final and binding upon the Parties. Judgment 

  
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upon the award rendered by the Tribunal may be entered in, and enforced by, any court of competent jurisdiction. Each Party shall bear the expense of the arbitrator selected by it, and the
Parties shall share equally the fees of the Chairman of the Tribunal. Each Party shall bear its own expenses, including expenses of its counsel. 

ARTICLE 8 — TAXES 

The Parties shall pay all federal, state, and local Tax or other Taxes that are directly imposed on each Party resulting from this Definitive
Agreement. “Tax or Taxes” include the following U.S. taxes: federal, state, and local excise taxes, sales and transaction taxes, gross receipts taxes, utility taxes, environmental taxes and fees or any other taxes that may be required to
be collected or paid by either Party as a result of this Definitive Agreement. 
 ARTICLE 9 — NOTICES 

All Notices authorized or required between the parties and required by any of the provisions of this agreement, unless otherwise specifically
provided, shall be given in writing by U.S. mail or overnight courier or telegram, postage or charges prepaid, or by facsimile, or telecopier and addressed to the parties to whom the Notice is given at the addresses listed below. The originating
Notice given under any provision hereof shall be deemed given only when received by the party to whom such Notice is directed, and the time for such party to give any Notice in response thereto shall run from the date the originating Notice is
received. The second or any responsive Notice shall be deemed given when deposited in the US mail or overnight courier or with the telegraph company, with postage or charges prepaid, or sent by facsimile, or telecopier, 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. 
  

	 	(a)	If to Encana: 

 Encana Oil & Gas (USA) Inc. 

5851 Legacy Circle 
 Plano,
Texas 75024 
 Attention: Team Lead Land 

Facsimile: (214) 242-7204 
  

	 	(b)	If to Shell: 

 SWEPI LP 

200 North Dairy Ashford 

Houston, Texas 77079 

Attention: John Bentz, Team Lead Shale Gas & Tight Gas 

Facsimile: (281) 544-5022 

ARTICLE 10 — MISCELLANEOUS 

10.1 Term of Definitive Agreement. Upon execution by both Parties, this Definitive Agreement shall be effective for a “Term”
beginning on the Effective Date and continuing until the earlier of (a) the point in time at which the Parties, or their respective successors or permitted 

  
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assigns no longer have a joint interest in any Leases; or (h) the point in time at which all Leases become Developed Acreage; provided that Article 6 shall continue in force and effect until
July 26, 2014, after which date Article 6 shall terminate and shall be of no further force or effect. 
 10.2 Entire
Agreement. This Definitive Agreement, together with the exhibits attached hereto, contains the final and entire agreement of the Parties with respect to the subject matter hereof. If there is a conflict between the terms contained in the body of
this Definitive Agreement and the terms of any of the exhibits attached hereto, the terms of the body of the Definitive Agreement shall control to the extent of such conflict. There are no representations, warranties or promises, oral or written,
between the Parties with respect to the subject matter of this Definitive Agreement other than those expressly contained within this Definitive Agreement. Except as set forth herein, upon execution of this Definitive Agreement by all Parties, this
Definitive Agreement shall supersede and replace the Blacksmith Agreements and all other previous agreements, negotiations, understandings or promises, whether written or oral, relating to the subject matter of this Definitive Agreement. Each of the
Parties acknowledges that the other Party has not made any promise, representation or warranty that is not expressly stated in this Definitive Agreement with respect to the subject hereof. This Definitive Agreement shall not be modified, changed or
amended (nor any provision of this Definitive Agreement waived), except by a written amendment signed by all Parties. 
 10.3 Governing
Law. This Definitive Agreement and the legal relations between the Parties shall be governed by and construed in accordance with the laws of the State of Louisiana, without regard to principles of conflicts of laws otherwise applicable to such
determinations. 
 10.4 Assignment. Neither Party may assign this Definitive Agreement and the obligations and benefits herein to any
other person without the prior written consent of the other Party, which consent shall not be unreasonably delayed, conditioned or withheld. Notwithstanding anything to the contrary in this Definitive Agreement, either Party may assign its rights
and interests under this Definitive Agreement to an Affiliate at any time without the prior written consent of the other Party, provided that the assigning Party shall remain liable to the other Party for all duties, obligations and liabilities
hereunder. 
 10.5 Relationship of the Parties. It is not the intention of the Parties hereto to create a partnership joint venture,
mining partnership or association taxable as a corporation; and neither this Definitive Agreement nor the operations hereunder shall be construed as creating such a relationship. The liability of the Parties hereto shall be several and not joint or
collective, and each Party shall be responsible only for its obligations. Nothing contained herein shall be construed to constitute either Party to be the partner of the other Party. 

10.6 Further Assurances. The Parties agree to execute, acknowledge and deliver all instruments, agreements or other documents and to
take such commercially reasonable actions which may be necessary or advisable to consummate the transactions contemplated by this Definitive Agreement. 

10.7 Counterparts. This Definitive Agreement may be executed in any number of counterparts, each of which shall be deemed an original,
but all of which shall constitute a single agreement. 

  
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 10.8 No Third Party Beneficiaries. Nothing in this Definitive Agreement, express or
implied, is intended to confer upon any third person any benefits, rights or remedies. 
 10.9 Headings for Convenience. Except for
the definition headings contained in Section 1.1 hereof, all captions, numbering sequences, and headings contained in this Definitive Agreement are inserted for convenience only and will in no way define, limit or describe the scope or
intent of this Definitive Agreement or any part hereof. 
 10.10 Covenants Running with the Land. This Definitive Agreement and the
terms, conditions and covenants herein shall be deemed to be covenants running with the land, and a burden on each of the Parties’ interests in the Acreage, and shall be binding on and shall inure to the benefit of each of the respective
Parties hereto and their successors and permitted assigns. 
 10.11 Conflict between Map and Exhibits. In the event of a conflict
between the schedules contained in Exhibits “A” and “B”, on the one hand, and the map contained in Exhibit “C”, on the other hand, the terms of the schedules contained in Exhibits “A” and “B” shall
govern to the extent of the conflict. 
 10.12 Severability. In case of a conflict between the provisions of this Definitive
Agreement and the provisions of any applicable laws or regulations, the provisions of the laws or regulations will govern over the provisions of this Definitive Agreement to the extent of such conflict. The Parties intend that every provision of
this Definitive Agreement and of the exhibits attached hereto be severable, if for any reason, and for so long as, any clause or provision of this Definitive Agreement is held by a court of competent jurisdiction to be illegal, invalid,
unenforceable or unconscionable under any present or future law (or interpretation thereof). The remainder of this Definitive Agreement shall not be affected by such illegality or invalidity. Any such invalid provision shall be deemed to have been
severed from this Definitive Agreement as if the Definitive Agreement had been executed with the invalid provision eliminated. The surviving provisions of this Definitive Agreement shall remain in force and effect unless the removal of the invalid
provisions destroys the legitimate purposes of this Definitive Agreement, in which event this Definitive Agreement shall be null and void. 

10.13 Gender and Number. The use of pronouns in whatever gender or number will be deemed to be a proper reference to the Parties to
this Definitive Agreement though the Parties may be individuals, business entities, or groups thereof. Any necessary grammatical changes required to make the provisions of this Definitive Agreement refer to the correct gender or number will in all
instances be assumed as though each case was fully expressed. 
 10.14 Independent Representation. Each Party has had the benefit of
independent representation with respect to the subject matter of this Definitive Agreement. This Definitive Agreement, though drawn by one Party, will be considered for all purposes as prepared through the joint efforts of the Parties and will be
construed fairly and reasonably and not more strictly against one Party than the other as a result of the preparation, submittal or other event of negotiation, drafting or execution hereof. 

[Signature Pages to Follow] 

  
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 IN WITNESS WHEREOF, this Definitive Agreement is executed on the date(s) indicated below, but
effective for all purposes as of the Effective Date. 
  

							
	 ENCANA OIL & GAS (US) INC.
  
	  	SWEPI LP
	By:	 	  
	  	By:	  	  

		 	 Mark Virant
 Attorney-in-Fact
  
	  		  	
Attorney-in-Fact

	Date:	 	  
	  	Date:	  	  

 Exhibit “A” 

Schedule of Developed Acreage to be operate by Encana upon completion of the Division of Operatorship 

 

															
	 GeolD
	  	 Well Name
	 	 Well

No.
	 	 Parish
	 	 API #
	 	 LA

Serial
	 	 Unit Name
	 	 Comments

	8N11W10	  	OLYMPIA MINERALS 10H	 	1	 	SABINE	 	17085221810000	 	241095	 	HA RA SUM	 	
	8N11W6	  	OLYMPIA MINERALS 6	 	1	 	SABINE	 	17085221990000	 	241429	 	JUR RA SUM	 	
	8N12W1	  	OLYMPIA MINERALS 1H	 	1	 	SABINE	 	17085221540000	 	240711	 	JUR RA SUN	 	
	8N12W10	  	OLYMPIA MIN 10 H	 	1	 	SABINE	 	17085223920000	 	244057	 	HA RA SUU	 	
	8N12W12	  	OLYMPIA MIN 12	 	1	 	SABINE	 	17085223830000	 	243851	 	HA RA SUW	 	
	8N12W4	  	OLYMPIA MINERALS 4 H	 	1	 	SABINE	 	17085221750000	 	241012	 	HA RA SUM	 	
	8N12W4	  	OLYMPIA MINERALS 4 H	 	002-ALT	 	SABINE	 	17085223680000	 	243536	 	HA RA SUM	 	
	9N11W30	  	OLYMPIA MIN 30 H	 	1	 	SABINE	 	17085222660000	 	242529	 	JUR RA SUG	 	
	9N11W31	  	MARTIN TIMBER 31 H	 	1	 	SABINE	 	17085222620000	 	242474	 	JUR RA SUL	 	
	9N12W10	  	SISTRUNK ETUX 10 H	 	002-ALT	 	SABINE	 	17085224140000	 	240904	 	HA RA SUN	 	
	9N12W16	  	DEANNA SISTRUNK 16 H	 	1	 	SABINE	 	17085222080000	 	241598	 	HA RA SUB	 	
	9N12W17	  	MCDONALD 17	 	1	 	SABINE	 	17085223120000	 	242901	 	HA RA SUII	 	
	9N12W23	  	OLYMPIA MINERALS 23	 	1	 	SABINE	 	17085222760000	 	242644	 	JUR RA SUD	 	
	9N12W24	  	OLYMPIA MIN 24 H	 	1	 	SABINE	 	17085222380000	 	241938	 	JUR RA SUE	 	
	9N12W25	  	OLYMPIA MIN 25	 	1	 	SABINE	 	17085223340000	 	243116	 	JUR RA SUH	 	
	9N12W26	  	OLYMPIA MINERALS 26	 	2	 	SABINE	 	17085221900000	 	241236	 	JUR RA SUA	 	
	9N12W3	  	TJ SISTRUNK ETUX 3 H	 	1	 	SABINE	 	17085221330000	 	239983	 	HA RA SUJ	 	
	9N12W3	  	WEYERHAEUSER CO 3 H	 	001-ALT	 	SABINE	 	17085223150000	 	243833	 	HA RA SUJ	 	
	9N12W3	  	WEYERHAEUSER CO 3 H	 	002-ALT	 	SABINE	 	17085223160000	 	243834	 	HA RA SUJ	 	
	9N12W3	  	WEYERHAEUSER CO 3 H	 	003-ALT	 	SABINE	 	17085223170000	 	243835	 	HA RA SUJ	 	
	9N12W3	  	TJ SISTRUNK ETAL 3 H	 	001-ALT	 	SABINE	 	17085223390000	 	243185	 	HA RA SUJ	 	
	9N12W3	  	TJ SISTRUNK ETAL 3 H	 	002-ALT	 	SABINE	 	17085223400000	 	243186	 	HA RA SUJ	 	
	9N12W3	  	TJ SISTRUNK ETAL 3 H	 	002-ALT	 	SABINE	 	17085223410000	 	244042	 	HA RA SUJ	 	
	9N12W3	  	TJ SISTRUNK ETAL 3 H	 	002-ALT	 	SABINE	 	17085223410000	 	243187	 	HA RA SUJ	 	
	9N12W3	  	TJ SISTRUNK ETAL 3 H	 	004-ALT	 	SABINE	 	17085223420000	 	243188	 	HA RA SUJ	 	
	9N12W3	  	TJ SISTRUNK ETAL 3 H	 	003-ALT	 	SABINE	 	17085223900000	 	244043	 	HA RA SUJ	 	
	9N12W6	  	FRANK FOX 6	 	1	 	SABINE	 	17085223200000	 	242937	 	HA RA SUK	 	
	9N12W8	  	BRUMLEY 8	 	1	 	SABINE	 	17085223550000	 	243365	 	HA RA SUL	 	
	9N12W9	  	JIMMY RAY BROWN 9 H	 	1	 	SABINE	 	17085221400000	 	240294	 	HA RA SUM	 	
	9N12W9	  	DEANNA SISTRUNK 9 H	 	003-ALT	 	SABINE	 	17085222830000	 	242715	 	HA RA SUM	 	
	9N12W9	  	DEANNA SISTRUNK 9 H	 	001-ALT	 	SABINE	 	17085222910000	 	242750	 	HA RA SUM	 	
	9N12W9	  	DEANNA SISTRUNK 9 H	 	002-ALT	 	SABINE	 	17085222920000	 	242751	 	HA RA SUM	 	
	9N12W9	  	THERESA SPEARS 9 H	 	001-ALT	 	SABINE	 	17085222930000	 	242752	 	HA RA SUM	 	
	9N12W9	  	THERESA SPEARS 9 H	 	002-ALT	 	SABINE	 	17085222940000	 	242753	 	HA RA SUM	 	
	9N12W9	  	THERESA SPEARS 9 H	 	003-ALT	 	SABINE	 	17085222950000	 	242754	 	HA RA SUM	 	
	9N12W9	  	JIMMY RAY BROWN 9 H	 	002-ALT	 	SABINE	 	17085223140000	 	242912	 	HA RA SUM	 	
	9N12W9	  	THERESA SPEARS 9 H	 	4	 	SABINE	 	17085223500000	 	243313	 	HA RA SUM	 	
	9N12W9	  	THERESA SPEARS 9 H	 	5	 	SABINE	 	17085223510000	 	243314	 	HA RA SUM	 	
	9N12W9	  	THERESA SPEARS 9 H	 	6	 	SABINE	 	17085223520000	 	243315	 	HA RA SUM	 	
	9N12W9	  	DEANNA SISTRUNK 9 H	 	4	 	SABINE	 	17085223570000	 	243411	 	HA RA SUM	 	
	9N12W9	  	DEANNA SISTRUNK 9 H	 	5	 	SABINE	 	17085223580000	 	243412	 	HA RA SUM	 	
	9N12W9	  	DEANNA SISTRUNK 9 H	 	6	 	SABINE	 	17085223590000	 	243413	 	HA RA SUM	 	
	10N11W20	  	ALTON BRANDON 20 H	 	1	 	SABINE	 	17085222320000	 	241853	 	HA RA SUW	 	
	10N11W21	  	MATTHEW MURRAY 21	 	1	 	SABINE	 	17085221620000	 	240869	 	HA RA SUE	 	
	10N11W23	  	COOK-TAYLOR 23 H	 	1	 	SABINE	 	17085221610000	 	240861	 	HA RA SUR	 	
	10N11W27	  	RONNY BROADWAY 27	 	1	 	SABINE	 	1085221770000	 	24 122	 	HA RA SUF	 	
	10N11W28	  	RAINES TRACT 28	 	1	 	SABINE	 	17085222490000	 	242171	 	JUR RA SUF	 	
	10N11W30	  	BLANKENSHIP 30 H	 	1	 	SABINE	 	17085222370000	 	241935	 	JUR RA SUD	 	
	10N11W31	  	MURRAY 31	 	1	 	SABINE	 	17085220900000	 	236843	 	JUR RA SUA	 	SWEPI will P&A
	10N11W31	  	LA MINERALS 31	 	001-ALT	 	SABINE	 	17085222090000	 	241602	 	JUR RA SUA	 	SWEPI Contract Operator
	10N11W32	  	CREST RESOURCES 32	 	1	 	SABINE	 	17085221800000	 	241088	 	JUR RA SUH	 	
	10N11W33	  	SANDRA BRYAN 33	 	1	 	SABINE	 	17085221790000	 	241087	 	JUR RA SUG	 	
	10N11W34	  	BENTON JOHNSON 34 H	 	1	 	SABINE	 	17085222310000	 	241852	 	HA RA SUD	 	

  
 1 

															
	 GeolD
	  	 Well Name
	 	 Well

No.
	 	 Parish
	 	 API #
	 	 LA

Serial
	 	 Unit Name
	 	 Comments

	10N11W8	  	COOK-TAYLOR LAND 8 H	 	1	 	DESOTO	 	17031252580000	 	241519	 	HA RA SUB	 	
	10N11W9	  	COOK-TAYLOR LAND 9H	 	1	 	DESOTO	 	17031256050000	 	242702	 	HA RA SUGG	 	
	10N12W25	  	HARDEE SANDERS 25 H	 	1	 	SABINE	 	17085221560000	 	240769	 	JUR RA SUC	 	
	10N12W4	  	CALDWELL TRUST 4 H	 	1	 	DESOTO	 	17031254710000	 	242223	 	HA RA SUB	 	
	10N9W6	  	SEMP RUSS PLTNS 6 H	 	1	 	NATCHITOCH ES	 	17069204090000	 	241008	 	HA RA SUE	 	
	10N9W8	  	J L MESSENGER 8	 	1	 	NATCHITOCH ES	 	17069204080000	 	237289	 	HA RA SUA	 	
	11N10W36	  	MARGARET DOWNS 36 H	 	1	 	NATCHITOCH ES	 	17069204110000	 	241381	 	HA RA SUL	 	
	11N12W10	  	BLACKSTONE IVORY 10	 	2	 	DESOTO	 	17031253630000	 	241843	 	HA RA SUA	 	
	11N12W15	  	BLACKSTONE IVORY 15	 	1	 	DESOTO	 	17031245910000	 	239011	 	HA RA SUA	 	
	11N12W16	  	ROCKING G FARMS 16	 	1	 	DESOTO	 	17031254810000	 	242259	 	JUR RA SUA	 	
	11N12W17	  	SUSTAINABLE FST 17	 	1	 	DESOTO	 	17031255540000	 	242521	 	JUR RA SUB	 	
	11N12W20	  	LONNIE WELCH 20 H	 	1	 	DESOTO	 	17031250330000	 	240705	 	JUR RA SUC	 	
	11N12VV22	  	SAN PATRICIO 22 H	 	1	 	DESOTO	 	17031251520000	 	241166	 	HA RA SUE	 	
	11N12W27	  	SAN PATRICIO 27	 	1	 	DESOTO	 	17031255170000	 	242390	 	HA RA SUJ	 	
	11N12W28	  	BRUSHY GROUP 28 H	 	1	 	DESOTO	 	17031253760000	 	241913	 	JUR RA SUD	 	
	11N12W29	  	ROCKING G FARMS 29	 	1	 	DESOTO	 	17031254060000	 	242038	 	JUR RA SUA	 	
	11N12W32	  	ROBERT RUST ETAL 32H	 	1	 	DESOTO	 	17031254310000	 	242111	 	JUR RA SUF	 	SWEPI Contract Operator”
	11N12W33	  	BRUSHY GROUP 33	 	1	 	DESOTO	 	17031258870000	 	244032	 	JUR RA SUE	 	
	12N10W22	  	PAUL SLATER 41 H	 	2	 	RED RIVER	 	17081210950000	 	240548	 	HA RA SUN	 	
	12N10W32	  	YVES LELONG 32	 	1	 	RED RIVER	 	17081211260000	 	242803	 	HA RB SUII	 	
	12N11W10	  	NABORS PROP 10 H	 	1	 	DESOTO	 	17031258500000	 	243876	 	HA RB SUI	 	
	12N11W11	  	C JENKINS ET AL 11 H	 	1	 	RED RIVER	 	17081213930000	 	244211	 	HA RB SU66	 	
	12N11W15	  	NABORS PROP 15	 	1	 	DESOTO	 	17031255200000	 	242400	 	HA RB SU89	 	
	12N11W21	  	LOWREY INVEST	 	1	 	DESOTO	 	17031257300000	 	243260	 	HA RB SU91	 	
	12N12W6	  	DON JONES GENERAL JOHNSTON CPF	 	1	 	DESOTO	 	17031248290000	 	239958	 	HA RC SUI	 	
	12N8W4	  	SUSTAINABLE FTS 4 H	 	1	 	RED RIVER	 	17081211910000	 	241352	 	HA RA SUN	 	
	12N9W13	  	SUSTAINABLE FTS 13 H	 	1	 	RED RIVER	 	17081211820000	 	241313	 	HA RA SUJ	 	
	12N9W24	  	RED RIVER 1 LP 24 H	 	1	 	RED RIVER	 	17081211640000	 	241178	 	HA RA SUM	 	
	12N9W34	  	EVELYN NELSON 34	 	1	 	RED RIVER	 	17081211470000	 	240978	 	HA RA SUEE	 	
	12N9W6	  	CANEY CREEK LAND 6	 	1	 	RED RIVER	 	17081211130000	 	240710	 	HA RA SUE	 	
	13N10W12	  	BLACK STONE MIN 12H	 	1	 	RED RIVER	 	17081209280000	 	238131	 	HA RB SUA	 	
	13N10W13	  	BLACK STONE MIN 13H	 	1	 	RED RIVER	 	17081209490000	 	238493	 	HA RB SUB	 	
	13N10W16	  	BROWN SW MIN 16 H	 	1	 	RED RIVER	 	17081210410000	 	240027	 	HA RA SUB	 	
	13N10W17	  	CECILE LAND 17 H	 	1	 	RED RIVER	 	17081211440000	 	240959	 	HA RB SUQQ	 	
	13N10W4	  	CRESWOOD LAND 4 H	 	1	 	RED RIVER	 	17081210710000	 	240298	 	HA RA SUV	 	
	13N1OW8	  	CECILE LAND 8 H	 	1	 	RED RIVER	 	17081210420000	 	240866	 	HA RB SUPP	 	
	13N10W9	  	BROWN SW MIN 9H	 	1	 	RED RIVER	 	17081210140000	 	239770	 	HA RA SUA	 	
	13N10W10	  	MARTIN TIMBER 1V	 	1	 	RED RIVER	 	17081208550000	 	232423	 	JUR RA SUA	 	ECA to P&A; PreAMI
	13N11W2	  	EDGAR CASON 2 H	 	2	 	RED RIVER	 	17081212210000	 	241662	 	HA RD SUK	 	
	13N11W3	  	EDGAR CASON 3 H	 	1	 	RED RIVER	 	17081212350000	 	241854	 	HA RD SUL	 	
	13N12W19	  	CARMEL LAKE LP 19	 	1	 	DESOTO	 	17031249460000	 	240418	 	JUR RB SUB	 	
	13N12W30	  	ROBERTSON ETAL 30 GENERAL JOHNSTON CPF	 	1	 	DESOTO	 	17031248060000	 	239880	 	JUR RB SUE	 	
	13N12W31	  	SUSTAINABLE 31 GENERAL JOHNSTON CPF	 	1	 	DESOTO	 	17031247620000	 	239715	 	JUR RB SUF	 	
	13N13W23	  	SUSTAINABLE 23	 	1	 	DESOTO	 	17031246240000	 	239246	 	HA RC SUM	 	
	13N13W24	  	SUSTAINABLE 24	 	1	 	DESOTO	 	17031246090000	 	239167	 	HA RC SUE	 	SWEPI Contract Operator and will P&A
	13N13W24	  	SUSTAINABLE 24	 	002-ALT	 	DESOTO	 	17031254050000	 	242037	 	HA RC SUE	 	
	13N13W33	  	LOWERY 33	 	1	 	DESOTO	 	17031253810000	 	241931	 	HA RA SULL	 	
	13N13W35	  	CALHOUN ONE LLC 35	 	1	 	DESOTO	 	17031250750000	 	240881	 	HA RC SUF	 	
	13N13W36	  	EL&T FOREST 36	 	1	 	DESOTO	 	17031248240000	 	240724	 	HA RC SUG	 	
	13N8W17	  	LEROY ADCOCK 17H	 	1	 	RED RIVER	 	17081210160000	 	239794	 	HA RA SUE	 	
	13N8W18	  	LEROY ADCOCK 18 H	 	1	 	RED RIVER	 	17081211870000	 	241341	 	HA RA SUS	 	
	13N8W19	  	CHARLES H GOBEN JR	 	1	 	RED RIVER	 	17081208650000	 	236929	 	JUR RA SUE	 	
	13N8W29	  	WILEY HUNTER 29 H	 	1	 	RED RIVER	 	17081211580000	 	241086	 	HA RA SUL	 	

  
 2 

															
	 GeolD
	  	 Well Name
	 	 Well

No.
	 	 Parish
	 	 API #
	 	 LA

Serial
	 	 Unit Name
	 	 Comments

	13N8W31	  	BUCK OF RRP 31 H	 	1	 	RED RIVER	 	17081211970000	 	241403	 	HA RA SUB	 	
	13N8W32	  	WILEY HUNTER 32 H	 	1	 	RED RIVER	 	17081211630000	 	241167	 	HA RA SUA	 	
	13N8W7	  	LEROY ADCOCK 7 H	 	1	 	RED RIVER	 	17081210890000	 	240484	 	HA RA SUR	 	
	13N8W8	  	SUSTAINABLE FTS 8 H	 	1	 	RED RIVER	 	17081211890000	 	241350	 	HA RA SUD	 	
	13N9W7	  	BLACK STONE 12/7 H4	 	4	 	RED RIVER	 	17081213980000	 	244267	 	HA RB SUA	 	
	13N9W10	  	INDIGO MIN LLC 10H	 	1	 	RED RIVER	 	17081209570000	 	238708	 	HA RA SUA	 	
	13N9W10	  	INDIGO MIN LLC 10H	 	002_ALT	 	RED RIVER	 	17081212680000	 	243390	 	HA RA SUA	 	
	13N9W11	  	THELMA LAWSON 11 H	 	1	 	RED RIVER	 	17081209780000	 	240237	 	HA RA SUB	 	
	13N9W13	  	WILL WOODS 13 H	 	1	 	RED RIVER	 	17081211520000	 	241032	 	HA RA SUF	 	
	13N9W14	  	PAVILLION LAND 14 H	 	1	 	RED RIVER	 	17081211880000	 	241348	 	HA RA SUG	 	
	13N9W15	  	J W ADCOCK INV ETAL	 	002-ALT	 	RED RIVER	 	17081208750000	 	235996	 	JUR RA SUA	 	
	13N9W15	  	J W ADCOCK INV ETAL	 	003-ALT	 	RED RIVER	 	17081208760000	 	235997	 	JUR RA SUA	 	
	13N9W15	  	T J L HAMM ETAL 15H	 	001-ALT	 	RED RIVER	 	17081212950000	 	243504	 	JUR RA SUA	 	
	13N9W15	  	T J LHAMM ETAL 15H	 	002-ALT	 	RED RIVER	 	17081212960000	 	243505	 	JUR RA SUA	 	
	13N9W15	  	BLACK STONE MINS CO ETAL 15H	 	2	 	RED RIVER	 	17081212980000	 	242712	 	JUR RA SUA	 	
	13N9W15	  	BLACK STONE CO 15 H	 	003-ALT	 	RED RIVER	 	17081212990000	 	242713	 	JUR RA SUA	 	
	13N9W15	  	BLACK STONE CO 15 H	 	004-ALT	 	RED RIVER	 	17081213000000	 	242714	 	JUR RA SUA	 	
	13N9W15	  	WILEY A SMITH 15 H	 	1	 	RED RIVER	 	17081213010000	 	243619	 	JUR RA SUA	 	
	13N9W15	  	WILEY A SMITH 15 H	 	002-ALT	 	RED RIVER	 	17081213020000	 	243656	 	JUR RA SUA	 	
	13N9W16	  	COLBERT LANDS 16 H	 	1	 	RED RIVER	 	17081209260000	 	238108	 	JUR RB SUK	 	
	13N9W16	  	COLBERT LANDSLLC16H	 	002-ALT	 	RED RIVER	 	17081209900000	 	239399	 	JUR RB SUK	 	
	13N9W17	  	EFGBCI 17H	 	1	 	RED RIVER	 	17081209630000	 	239902	 	JUR RB SUL	 	
	13N9W19	  	BLK STONE IVORY 19H	 	1	 	RED RIVER	 	17081212400000	 	242128	 	JUR RB SUD	 	
	13N9W20	  	BROWN SW MIN 20 H	 	1	 	RED RIVER	 	17081211250000	 	240814	 	JUR RB SUE	 	
	13N9W21	  	OW DRIGGERS 21 H	 	1	 	RED RIVER	 	17081210130000	 	239750	 	JUR RB SUF	 	
	13N9W22	  	ROBERT HESTER 22 H	 	1	 	RED RIVER	 	17081210900000	 	240505	 	HA RA SUFI	 	
	13N9W24	  	WILL WOODS 24 H	 	1	 	RED RIVER	 	17081211330000	 	240889	 	HA RA SUJ	 	
	13N9W27	  	ROBERT HESTER 27 H	 	1	 	RED RIVER	 	17081210920000	 	240519	 	HA RA SUH	 	
	13N9W28	  	WALKER LTD PRT ETAL	 	002-ALT	 	RED RIVER	 	17081210500000	 	240119	 	JUR RB SUA	 	
	13N9W28	  	NORENE DELP 28 H	 	001-ALT	 	RED RIVER	 	17081212020000	 	241439	 	JUR RB SUA	 	
	13N9W28	  	WALKER LTD PRT ETAL	 	1	 	RED RIVER	 	17081208540000	 	232267	 	JUR RB SUA	 	
	13N9W29	  	J W ADCOCK INV 29H	 	1	 	RED RIVER	 	17081209360000	 	238349	 	JUR RB SUB	 	
	13N9W3	  	MYRTLE M BASS 3 H	 	1	 	RED RIVER	 	17081211360000	 	240906	 	HA RA SUQ	 	
	13N9W31	  	SUSTAINABLE FST 31 H	 	1	 	RED RIVER	 	17081211510000	 	241000	 	HA RB SUD	 	
	13N9W32	  	ELMWOOD LAND 32 H	 	1	 	RED RIVER	 	17081209450000	 	238485	 	HA RB SUE	 	
	13N9W33	  	ELMWOOD LAND 33 H	 	1	 	RED RIVER	 	17081211590000	 	241100	 	HA RA SUP	 	
	13N9W34	  	SUSTAINABLE FTS 34 H	 	1	 	RED RIVER	 	17081211760000	 	241279	 	HA RA SUQ	 	
	13N9W36	  	SUSTAINABLE FST 36H	 	1	 	RED RIVER	 	17081212110000	 	241525	 	HA RA SUC	 	
	13N9W4	  	PEGGY SMITH RAY 4 H	 	1	 	RED RIVER	 	17081211170000	 	240742	 	HA RA SUP	 	
	13N9W5	  	BLACKSTONE IVORY 5	 	1	 	RED RIVER	 	17081210780000	 	240368	 	HA RA SUQ	 	
	13N9W6	  	BLACKSTONE IVORY 6 H	 	1	 	RED RIVER	 	17081211420000	 	240948	 	HA RA SUR	 	
	13N9W8	  	BLACKSTONE IVORY 8H	 	1	 	RED RIVER	 	17081211050000	 	240654	 	JUR RB SUI	 	
	13N9W9	  	CARROL S SMITH 9H	 	1	 	RED RIVER	 	17081209560000	 	238625	 	JUR RB SUJ	 	
	14N10W16	  	JIMMY GAY 16 H	 	1	 	RED RIVER	 	17081210100000	 	239728	 	HA RA SU58	 	
	14N10W17	  	JAMES MARSTON 17 H	 	1	 	RED RIVER	 	17081210660000	 	240264	 	HA RA SUW	 	
	14N10W18	  	OB MADDEN 18 H	 	1	 	RED RIVER	 	17081210320000	 	240718	 	HA RA SU57	 	
	14N10W19	  	JAMES MARSTON 19 H	 	1	 	RED RIVER	 	17081210190000	 	239845	 	HA RD SUP	 	
	14N10W28	  	MC TRUST B ETAL 28H	 	1	 	RED RIVER	 	17081212380000	 	241937	 	HA RA SUDD	 	
	14N10W29	  	MCLELLAND TRUST 29	 	1	 	RED RIVER	 	17081212290000	 	241700	 	HA RD SUCC	 	
	14N10W30	  	JAMES MARSTON 30 H	 	1	 	RED RIVER	 	17081210360000	 	240004	 	HA RD SUQ	 	
	14N10W31	  	EDGAR CASON 31 H	 	1	 	RED RIVER	 	17081210480000	 	240093	 	HA RD SUT	 	
	14N10W4	  	MARY LONG 4	 	1	 	RED RIVER	 	17081210510000	 	240124	 	HA RA SUZ	 	
	14N10W5	  	MARSHA LOFTIN 5	 	1	 	RED RIVER	 	17081210790000	 	240375	 	HA RA SU63	 	
	14N10W6	  	EDGAR CASON 6H	 	1	 	RED RIVER	 	17081210380000	 	240014	 	HA RA SU64	 	
	14N10W7	  	EDGAR CASON 7 H	 	1	 	RED RIVER	 	17081210620000	 	240248	 	HA RA SU55	 	
	14N10W7 and 18	  	OB MADDEN 7-18HC	 	1-ALT	 	RED RIVER	 	17081210352000	 	244377	 	HA RA SU55	 	

  
 3 

															
	 GeolD
	  	 Well Name
	 	 Well

No.
	 	 Parish
	 	 API #
	 	 LA

Serial
	 	 Unit Name
	 	 Comments

	14N10W7 and 18	  	OB MADDEN 7-18HC	 	2-ALT	 	RED RIVER	 	17081210353000	 	244378	 	HA RA SU55	 	
	14N10W7 and 18	  	OB MADDEN 7-18HC	 	3-ALT	 	RED RIVER	 	17081210374000	 	244379	 	HA RA SU55	 	
	14N10W7 and 18	  	EDGAR CASON 7-18HC	 	1-ALT	 	RED RIVER	 	17081210354000	 	244381	 	HA RA SU55	 	
	14N10W7 and 18	  	EDGAR CASON 7-18HC	 	2-ALT	 	RED RIVER	 	17081210355000	 	244382	 	HA RA SU55	 	
	14N10W7 and 18	  	EDGAR CASON 7-18HC	 	3-ALT	 	RED RIVER	 	17081210373000	 	244383	 	HA RA SU55	 	
	14N10W8	  	CONNIE GRZESIEK 8 H	 	1	 	RED RIVER	 	17081210060000	 	239667	 	HA RA SU56	 	
	14N10W9	  	ROWILSON TRUST 9	 	1	 	RED RIVER	 	17081210230000	 	239959	 	HA RA SUAA	 	
	14N11W15	  	CONWAY HARRIS 15 H	 	1	 	RED RIVER	 	17081210030000	 	239624	 	HA RA SUW	 	
	14N11W15	  	CONWAY HARRIS 15 H	 	004-ALT	 	RED RIVER	 	17081212630000	 	242490	 	HA RA SUW	 	
	14N11W15	  	CONWAY HARRIS 15 H	 	005-ALT	 	RED RIVER	 	17081212640000	 	242491	 	HA RA SUW	 	
	14N11W15	  	CONWAY HARRIS 15 H	 	006-ALT	 	RED RIVER	 	17081212650000	 	242492	 	HA RA SUW	 	
	14N11W15	  	KALVIN DOUGLAS 15 H	 	001-ALT	 	RED RIVER	 	17081212660000	 	242493	 	HA RA SUW	 	
	14N11W15	  	KALVIN DOUGLAS 15 H	 	002-ALT	 	RED RIVER	 	17081212670000	 	242494	 	HA RA SUW	 	
	14N11W15	  	CONWAY HARRIS 15 H	 	002-ALT	 	RED RIVER	 	17081212790000	 	242530	 	HA RA SUW	 	
	14N11W15	  	CONWAY HARRIS 15 H	 	003-ALT	 	RED RIVER	 	17081212800000	 	242531	 	HA RA SUW	 	
	14N11W21	  	REX YOUNG 21 H	 	1	 	RED RIVER	 	17081210120000	 	239748	 	HA RD SUB	 	
	14N11W21	  	COLBERT LANDS 21 H	 	001-ALT	 	RED RIVER	 	17081213580000	 	243740	 	HA RD SUB	 	
	14N11W21	  	COLBERT LANDS 21 H	 	002-ALT	 	RED RIVER	 	17081213590000	 	243741	 	HA RD SUB	 	
	14N11W21	  	COLBERT LANDS 21 H	 	003-ALT	 	RED RIVER	 	17081213600000	 	243742	 	HA RD SUB	 	
	14N11W21	  	REX YOUNG 21 H	 	002-ALT	 	RED RIVER	 	17081213680000	 	243828	 	HA RD SUB	 	
	14N11W21	  	REX YOUNG 21 H	 	003-ALT	 	RED RIVER	 	17081213690000	 	243829	 	HA RD SUB	 	
	14N11W22	  	CONWAY HARRIS 22 H	 	1	 	RED RIVER	 	17081209840000	 	239250	 	HA RD SUC	 	
	14N11W22	  	CONWAY HARRIS 22 H	 	002-ALT	 	RED RIVER	 	17081212710000	 	242515	 	HA RD SUC	 	
	14N11W22	  	CONWAY HARRIS 22 H	 	003-ALT	 	RED RIVER	 	17081212720000	 	242516	 	HA RD SUC	 	
	14N11W22	  	CONWAY HARRIS 22 H	 	004-ALT	 	RED RIVER	 	17081212730000	 	242517	 	HA RD SUC	 	
	14N11W22	  	KALVIN DOUGLAS 22 H	 	001-ALT	 	RED RIVER	 	17081212760000	 	242520	 	HA RD SUC	 	
	14N11W22	  	KALVIN DOUGLAS 22 H	 	002-ALT	 	RED RIVER	 	17081212840000	 	242560	 	HA RD SUC	 	
	14N11W25	  	BUNDRICK LD CORP 25H	 	1	 	RED RIVER	 	17081210200000	 	239877	 	HA RD SUR	 	
	14N11W26	  	JOSEPH BOLAN 26 H	 	1	 	RED RIVER	 	17081209910000	 	239467	 	HA RD SUD	 	
	14N11W27	  	J T BOLAN ETAL 27	 	1	 	RED RIVER	 	17081208940000	 	237121	 	JUR RA SUA	 	
	14N11W27	  	BUNDRICK LAND 27	 	001-ALT	 	RED RIVER	 	17081212240000	 	241665	 	JUR RA SUA	 	
	14N11W27	  	BUNDRICK LAND 27 H	 	002-ALT	 	RED RIVER	 	17081212250000	 	241666	 	JUR RA SUA	 	
	14N11W27	  	BUNDRICK LAND 27 H	 	003-ALT	 	RED RIVER	 	17081212260000	 	241667	 	JUR RA SUA	 	
	14N11W27	  	JOSEPH T BOLAN ETAL 27	 	3 PMW	 	RED RIVER	 	17081212320000	 	241735	 	JUR RA SUA	 	
	14N11W27	  	J T BOLAN ETAL 27	 	004-ALT	 	RED RIVER	 	17081212550000	 	242364	 	JUR RA SUA	 	
	14N11W27	  	J T BOLAN ETAL 27	 	005-ALT	 	RED RIVER	 	17081212560000	 	242365	 	JUR RA SUA	 	
	14N11W27	  	J T BOLAN ETAL 27	 	006-ALT	 	RED RIVER	 	17081212570000	 	242366	 	JUR RA SUA	 	
	14N11W27	  	J T BOLAN ETAL 27	 	007-ALT	 	RED RIVER	 	17081212580000	 	242367	 	JUR RA SUA	 	
	14N11W27	  	J T BOLAN ETAL 27	 	008-ALT	 	RED RIVER	 	17081212590000	 	242368	 	JUR RA SUA	 	
	14N11W27	  	J T BOLAN ETAL 27	 	009-ALT	 	RED RIVER	 	17081212600000	 	242370	 	JUR RA SUA	 	
	14N11W27	  	J T BOLAN ETAL 27	 	010-ALT	 	RED RIVER	 	17081212610000	 	242371	 	JUR RA SUA	 	
	14N11W28	  	REX YOUNG 28 H	 	1	 	RED RIVER	 	17081209940000	 	239479	 	HA RD SUE	 	
	14N11W28	  	REX YOUNG 28 H	 	002-ALT	 	RED RIVER	 	17081211780000	 	241296	 	HA RD SUE	 	
	14N11W28	  	REX YOUNG 28 H	 	003-ALT	 	RED RIVER	 	17081211810000	 	241311	 	HA RD SUE	 	
	14N11W28	  	REX YOUNG 28 H	 	004-ALT	 	RED RIVER	 	17081211850000	 	241327	 	HA RD SUE	 	
	14N11W28	  	JOSEPH BOLAN ETAL 28 H	 	1	 	RED RIVER	 	17081212050000	 	241494	 	HA RD SUE	 	
	14N11W28	  	J BOLAN ETAL 28 H	 	002-ALT	 	RED RIVER	 	17081212060000	 	241495	 	HA RD SUE	 	
	14N11W28	  	J BOLAN ETAL 28 H	 	003-ALT	 	RED RIVER	 	17081212070000	 	241496	 	HA RD SUE	 	
	14N11W28	  	J BOLAN ETAL 28 H	 	004-ALT	 	RED RIVER	 	17081212080000	 	241500	 	HA RD SUE	 	
	14N11 W34	  	J T BOLAN ETAL 34H	 	1	 	RED RIVER	 	17081209740000	 	239056	 	HA RD SUI	 	
	14N11W34	  	BUNDRICK LAND 34 H	 	001-ALT	 	RED RIVER	 	17081212220000	 	241663	 	HA RD SUi	 	
	14N11W34	  	BUNDRICK LAND 34 H	 	002-ALT	 	RED RIVER	 	17081212230000	 	241664	 	HA RD SUI	 	
	14N11W34	  	JOSEPH BOLAN 34 H	 	002-ALT	 	RED RIVER	 	17081212500000	 	242349	 	HA RD SUI	 	
	14N11W34	  	JOSEPH BOLAN 34 H	 	003-ALT	 	RED RIVER	 	17081212510000	 	242350	 	HA RD SUI	 	
	14N11W34	  	JOSEPH BOLAN 34 H	 	004-ALT	 	RED RIVER	 	17081212520000	 	242351	 	HA RD SUI	 	

  
 4 

															
	 GeolD
	  	 Well Name
	 	 Well

No.
	 	 Parish
	 	 API #
	 	 LA

Serial
	 	 Unit Name
	 	 Comments

	 14N11W34
	  	 JOSEPH BOLAN 34 H
	 	 005-ALT
	 	 RED RIVER
	 	17081212530000	 	242352	 	 HA RD SUI
	 	
	 14N11W34
	  	 JOSEPH BOLAN 34 H
	 	 006-ALT
	 	 RED RIVER
	 	17081212540000	 	243252	 	 HA RD SUI
	 	
	 14N11W35
	  	 BUNDRICK 35 H
	 	1	 	 RED RIVER
	 	17081209250000	 	238107	 	 HA RD SUJ
	 	
	 14N11W36
	  	 BUNDRICK LAND 36 H
	 	1	 	 RED RIVER
	 	17081210170000	 	239818	 	 HA RD SUS
	 	
	 14N9W33
	  	 EDGAR CASON 33 H
	 	1	 	 RED RIVER
	 	17081211660000	 	241181	 	 HA RA SUO
	 	
	 14N9W34
	  	 EDGAR CASON 34 H
	 	1	 	 RED RIVER
	 	17081211110000	 	240708	 	 HA RA SUEE
	 	

  
 5 

 Exhibit “B” 

Schedule of Developed Acreage to be operate by Shell upon completion of the Division of Operatorship 

 

															
	 GeolD
	  	 Well Name
	 	 Well

No.
	 	 Parish
	 	 API #
	 	 LA

Serial
	 	 Unit Name
	 	 Comments

	8N12W6	  	GARY LEE 6	 	1	 	SABINE	 	17085224090000	 	244567	 	HA RA SUO	 	
	8N12W7	  	GARY LEE 7	 	1	 	SABINE	 	17085223940000	 	244116	 	HA RA SUR	 	
	9N11W16	  	GODFREY L&T 16	 	1	 	SABINE	 	17085221600000	 	240845	 	HA RA SUA	 	
	9N11W17	  	JEAN LARSEN 17	 	1	 	SABINE	 	17085222500000	 	242201	 	HA RA SUG	 	
	9N11W17	  	JEAN LARSEN 17	 	002-ALT	 	SABINE	 	17085222840000	 	242716	 	HA RA SUG	 	
	9N11W17	  	JEAN LARSEN 17	 	003-ALT	 	SABINE	 	17085222850000	 	242717	 	HA RA SUG	 	
	9N11W17	  	JEAN LARSEN 17	 	004-ALT	 	SABINE	 	17085222860000	 	242718	 	HA RA SUG	 	
	9N11W17	  	DRURY STEVENS 17	 	001-ALT	 	SABINE	 	17085222890000	 	242748	 	HA RA SUG	 	
	9N11W17	  	DRURY STEVENS 17	 	002-ALT	 	SABINE	 	17085222900000	 	242749	 	HA RA SUG	 	
	9N11W17	  	DRURY STEVENS 17	 	003-ALT	 	SABINE	 	17085223690000	 	243560	 	HA RA SUG	 	
	9N11W17	  	DRURY STEVENS 17	 	004-ALT	 	SABINE	 	17085223700000	 	243552	 	HA RA SUG	 	
	9N11W18	  	HALLIE LITTON 18	 	1	 	SABINE	 	17085221530000	 	240702	 	HA RA SUF	 	
	9N11W20	  	ANNIE BURKETT 20	 	1	 	SABINE	 	17085221450000	 	240453	 	HA RA SUH	 	
	9N11W20	  	DRURY STEVENS 20	 	001-ALT	 	SABINE	 	17085222960000	 	242758	 	HA RA SUH	 	
	9N11W20	  	DRURY STEVENS 20	 	002-ALT	 	SABINE	 	17085222970000	 	242759	 	HA RA SUH	 	
	9N11W20	  	DRURY STEVENS 20	 	003-ALT	 	SABINE	 	17085223710000	 	243553	 	HA RA SUH	 	
	9N11W20	  	DRURY STEVENS 20	 	004-ALT	 	SABINE	 	17085223720000	 	243554	 	HA RA SUH	 	
	9N 11W21	  	ROYCE SALLEY 21	 	1	 	SABINE	 	17085222100000	 	241624	 	HA RA SUB	 	
	9N11W29	  	ROBERT BOZEMAN 29 H	 	1	 	SABINE	 	17085221570000	 	240815	 	HA RA SUA	 	
	9N11W4	  	RSD LLC ETAL 4H	 	1	 	SABINE	 	17085221340000	 	239985	 	JUR RA SUL	 	
	9N11W5	  	RANDALL RAINS 5	 	1	 	SABINE	 	17085221760000	 	241021	 	JUR RA SUB	 	
	9N11W6	  	LA MINERALS 6	 	1	 	SABINE	 	17085222260000	 	241778	 	JUR RA SUK	 	
	9N11W7	  	JAMES LANG 7	 	1	 	SABINE	 	17085221920000	 	241263	 	JUR RA SUN	 	
	9N11W8	  	JULIA SWAIN 8	 	1	 	SABINE	 	17085222300000	 	241844	 	JUR RA SUM	 	
	9N12W1	  	MARTIN TIMBER 1	 	1	 	SABINE	 	17085222700000	 	242592	 	JUR RA SUJ	 	
	9N12W11	  	HALLIE LITTON 11 H	 	1	 	SABINE	 	17085221420000	 	240354	 	HA RA SUO	 	
	9N12W12	  	COOK TAYLOR LAND 12	 	1	 	SABINE	 	17085221870000	 	241213	 	JUR RA SUO	 	
	9N12W13	  	GUFFY PATTISON 13H	 	1	 	SABINE	 	17085221350000	 	239992	 	HA RA SUE	 	
	9N12W14	  	COOK-TAYLOR LD 14 H	 	1	 	SABINE	 	1708522 690000	 	240924	 	HA RA SUD	 	
	9N12W2	  	LAS ORMIGAS 2	 	1	 	SABINE	 	17085223440000	 	243197	 	HA RA SUPP	 	
	9N12W22	  	WEYERHAEUSER 22 H	 	1	 	SABINE	 	17085221820000	 	241097	 	JUR RA SUC	 	
	9N12W27	  	OLYMPIA MINERALS 27	 	1	 	SABINE	 	17085221780000	 	241030	 	JUR RA SUI	 	
	9N12W28	  	OLYMPIA MINERALS 28	 	1	 	SABINE	 	17085221940000	 	241310	 	HA RA SUBB	 	
	9N12W29	  	WEYERHAEUSER 29 H	 	1	 	SABINE	 	17085223000000	 	242797	 	HA RA SUCC	 	
	9N12W31	  	MORITZ ETAL 31 H	 	1	 	SABINE	 	17085223640000	 	243499	 	HA RA SUK	 	
	9N12W32	  	OLYMPIA MIN 32	 	1	 	SABINE	 	17085223600000	 	243450	 	HA RA SUL	 	
	10N12W35	  	COOK TAYLOR LAND 35	 	2	 	SABINE	 	17085223540000	 	243362	 	HA RA SUI	 	
	10N12W36	  	MARTIN TIMBER 36	 	1	 	SABINE	 	17085223860000	 	243914	 	JUR RA SUI	 	
	10N12W5	  	ROBERT RUST ETAL 5 H	 	1	 	DE SOTO	 	17031254080000	 	242048	 	HA RA SUP	 	
	10N12W7	  	SAN PATRICIO 7 H	 	2	 	DE SOTO	 	17031249540000	 	240440	 	HA RA SUB	 	
	10N12W8	  	SAN PATRICIO 8 H	 	1	 	DE SOTO	 	17031250020000	 	240600	 	HA RA SUC	 	
	11N10W11	  	LYSANDER WEBB 11 H	 	1	 	RED RIVER	 	17081210740000	 	240321	 	HA RA SUD	 	
	11N10W13	  	VIRGINIA WEBB 13 H	 	1	 	RED RIVER	 	17081211030000	 	240624	 	HA RA SUG	 	
	11N10W14	  	ROGER BIERDEN 14H	 	1	 	DE SOTO	 	17031251490000	 	241146	 	HA RA SUGG	 	
	11N10W15	  	LOLA R BOONE 15 H	 	1	 	DE SOTO	 	17031249220000	 	240320	 	HA RB SUZZ	 	
	11N11W19	  	LA MINERALS 19	 	1	 	DE SOTO	 	17031250810000	 	240903	 	HA RA SUH	 	
	11N11W30	  	ROCKING G FARMS 30	 	1	 	DE SOTO	 	17031249990000	 	240586	 	HA RA SUD	 	
	11N11W33	  	HELEN BUTLER 33	 	1	 	DE SOTO	 	17031256490000	 	242854	 	HA RA SUHH	 	
	11N12W13	  	LOUISIANA MIN 13 H	 	1	 	DE SOTO	 	17031254420000	 	242133	 	HA RA SU74	 	
	11N12W14	  	IVORY WORKING 14 H	 	1	 	DE SOTO	 	17031255300000	 	242433	 	HA RA SUB	 	
	11N12W18	  	BLACKSTONE 18 H	 	1	 	DE SOTO	 	17031249900000	 	240554	 	JUR RA SUC	 	
	11N12W19	  	HARRIS 19	 	1	 	DE SOTO	 	17031243590000	 	237373	 	JUR RA SUA	 	
	11N12W19	  	B BERRY LLC 19	 	001-ALT	 	DE SOTO	 	17031255890000	 	242679	 	JUR RA SUA	 	

  
 1 

															
	 GeolD
	  	 Well Name
	 	 Well

No.
	 	 Parish
	 	 API #
	 	 LA

Serial
	 	 Unit Name
	 	 Comments

	11N12W19	  	B BERRY LLC 19	 	002-ALT	 	DE SOTO	 	17031256800000	 	242989	 	JUR RA SUA	 	
	11N12W19	  	B BERRY LLC 19	 	003-ALT	 	DE SOTO	 	17031256810000	 	242990	 	JUR RA SUA	 	
	11N12W23	  	ROCKING G FARMS 23	 	1	 	DE SOTO	 	17031249550000	 	240446	 	HA RA SUF	 	
	11N12W23	  	ROCKING G FARMS 23	 	2	 	DE SOTO	 	17031255180000	 	242393	 	HA RA SUF	 	
	11N12W25	  	SAN PATRICIO 25	 	1	 	DE SOTO	 	17031255340000	 	242443	 	HA RA SUC	 	
	11N12W30	  	ROCKING G FARMS 30H	 	1	 	DE SOTO	 	17031249570000	 	241592	 	JUR RA SUE	 	
	11N12W31	  	ROCKING G FARMS 31H	 	1	 	DE SOTO	 	17031252690000	 	241552	 	JUR RA SUG	 	
	11N13W13	  	DOUCIERE 13	 	1	 	DE SOTO	 	17031246190000	 	239225	 	JUR RA SUB	 	
	11N13W13	  	SUSTAINABLE FST 13	 	001-ALT	 	DE SOTO	 	17031255780000	 	242628	 	JUR RA SUB	 	
	11N 13W24	  	GUY FARMS 24	 	1	 	DE SOTO	 	17031245780000	 	238957	 	JUR RA SUD	 	
	11N13W25	  	HARLON BLACKMON 25H	 	1	 	DE SOTO	 	17031249310000	 	240352	 	JUR RA SUE	 	
	11N13W25	  	HARLON BLACKMON 25H	 	2	 	DE SOTO	 	17031250030000	 	240601	 	JUR RA SUE	 	
	11N13W36	  	F MUSTIFUL 36H	 	1	 	DE SOTO	 	17031252600000	 	241531	 	JUR RA SUH	 	
	11N13W4	  	BLACKSTONE 4	 	1	 	DE SOTO	 	17031248000000	 	239851	 	HA RA SUJ	 	
	11N13W9	  	BLACKSTONE 9	 	1	 	DE SOTO	 	17031248140000	 	239901	 	HA RA SUK	 	
	11N9W20	  	LEGRANDE 20	 	1	 	RED RIVER	 	17081213820000	 	244087	 	HA RA SUN	 	
	11N9W26	  	LEWIS INTERESTS 39 H	 	1	 	RED RIVER	 	17081211980000	 	241404	 	HA RA SUP	 	
	11N9W28	  	JOHN MONDELLO 51	 	1	 	RED RIVER	 	17081212000000	 	241428	 	HA RA SUR	 	
	11N9W29	  	JOHN MONDELLO 29H	 	1	 	RED RIVER	 	17081210640000	 	240253	 	HA RA SUE	 	
	12N1OVV1	  	BILL SHAW 1 H	 	1	 	RED RIVER	 	17081210970000	 	240552	 	HA RA SUH	 	
	12N10W1	  	BILL SHAW 1 H	 	002-ALT	 	RED RIVER	 	17081213460000	 	243575	 	HA RA SUH	 	
	12N10VV11	  	MAXIE ALMOND 11 H	 	1	 	RED RIVER	 	17081213710000	 	243966	 	HA RA SUJ	 	
	12N10W12	  	MAXIE ALMOND 12 H	 	1	 	RED RIVER	 	17081212360000	 	241903	 	HA RA SUI	 	
	12N10W19	  	BETTY RIVES 19	 	1	 	RED RIVER	 	17081212150000	 	241532	 	HA RA SUU	 	
	12N10W2	  	REX YOUNG ETAL 2 H	 	1	 	RED RIVER	 	17081209650000	 	240296	 	HA RA SUG	 	
	12N10VV23	  	EF LESTER ETAL 41 H	 	1	 	RED RIVER	 	17081213160000	 	243157	 	HA RA SUO	 	
	12N10VV25	  	JANELLE GIVENS 38 H	 	1	 	RED RIVER	 	17081212010000	 	241436	 	HA RA SULL	 	
	12N10W26	  	RALPH WEBB 26 H	 	2	 	RED RIVER	 	17081210720000	 	240306	 	HA RA SUC	 	
	12N10VV3	  	M&M ALMOND 3 H	 	1	 	RED RIVER	 	17081211390000	 	240921	 	HA RA SUF	 	
	12N13W1	  	CSJ MINERALS LLC 1	 	1	 	DE SOTO	 	17031248960000	 	240230	 	HA RC SUH	 	
	12N13W11	  	ADVANCED L&T 11	 	1	 	DE SOTO	 	17031251780000	 	241264	 	HA RA SUE	 	
	12N8W3	  	SUSTAINABLE FTS 3 H	 	1	 	RED RIVER	 	17081213990000	 	244374	 	HA RA SUO	 	
	12N8VV5	  	ANITA ROBINSON 5 H	 	1	 	RED RIVER	 	17081211450000	 	240963	 	HA RA SUF	 	
	12N8W7	  	RED RIVER 1 LP 7 H	 	1	 	RED RIVER	 	17081211280000	 	240843	 	HA RA SUH	 	
	12N9W10	  	MICHAEL JONES 10 H	 	1	 	RED RIVER	 	17081211430000	 	240955	 	HA RA SUK	 	
	12N9W12	  	WKP PROPERTIES 12 H	 	1	 	RED RIVER	 	17081213720000	 	244006	 	HA RA SUI	 	
	12N9W14	  	BROWN SW MIN 14 H	 	1	 	RED RIVER	 	17081211120000	 	240709	 	HA RA SUD	 	
	12N9W15	  	LEM JONES 15	 	1	 	RED RIVER	 	17081211830000	 	241314	 	HA RA SUL	 	
	12N9W16	  	BO JONES SR EST 16H	 	1	 	RED RIVER	 	17081211040000	 	240625	 	HA RA SUM	 	
	12N9W2	  	SUSTAINABLE FTS 2 H	 	1	 	RED RIVER	 	17081211960000	 	241397	 	HA RA SUB	 	
	12N9W3	  	SUSTAINABLE FTS 3 H	 	1	 	RED RIVER	 	17081211190000	 	240744	 	HA RA SUF	 	
	12N9W4	  	JOANNA CARSON 4 I-1	 	1	 	RED RIVER	 	17081210700000	 	240295	 	HA RA SUG	 	
	12N9W5	  	BROWN SW MINERALS 5H	 	1	 	RED RIVER	 	17081211270000	 	240829	 	HA RA SUH	 	
	12N9W8	  	C E MILNER 8 H	 	1	 	RED RIVER	 	17081211290000	 	240844	 	HA RA SUI	 	
	12N9W9	  	LEM JONES 9	 	1	 	RED RIVER	 	17081211320000	 	240886	 	HA RA SUJ	 	
	13N10W1	  	HENNIGAN 1	 	1	 	RED RIVER	 	17081213070000	 	242774	 	HA RA SUS	 	
	13N1OVV1	  	HENNIGAN 1	 	2-ALT	 	RED RIVER	 	17081213940000	 	244230	 	HA RA SUS	 	
	13N10VV1	  	OE MOORE 1H	 	1-ALT	 	RED RIVER	 	17081213900000	 	244173	 	HA RA SUS	 	
	13N1OW1	  	OE MOORE 2H	 	2-ALT	 	RED RIVER	 	17081213910000	 	244174	 	HA RA SUS	 	
	13N10W10	  	BROWN SW MIN 10H	 	001-ALT	 	RED RIVER	 	17081210080000	 	239707	 	JUR RA SUA	 	
	13N10W10	  	PAVILLION LAND 10 H	 	001-ALT	 	RED RIVER	 	17081212270000	 	241675	 	JUR RA SUA	 	
	13N 10W14	  	MARY MCCOY 14	 	1	 	RED RIVER	 	17081210760000	 	240330	 	HA RA SUG	 	
	13N10W15	  	BROWN SW MIN 15 H	 	1	 	RED RIVER	 	17081216400000	 	240026	 	HA RA SUC	 	
	13N10W15	  	L P WARE 15	 	001-ALT	 	RED RIVER	 	17081213490000	 	243609	 	HA RA SUC	 	
	13N10W15	  	L P WARE 15	 	002-ALT	 	RED RIVER	 	17081213500000	 	243610	 	HA RA SUC	 	
	13N10W15	  	L P WARE 15	 	003-ALT	 	RED RIVER	 	17081213510000	 	243611	 	HA RA SUC	 	
	13N10W15	  	LAKE CHARM 15	 	001-ALT	 	RED RIVER	 	17081213610000	 	243766	 	HA RA SUC	 	
	13N10VV15	  	LAKE CHARM 15	 	002-ALT	 	RED RIVER	 	17081213620000	 	243767	 	HA RA SUC	 	

  
 2 

															
	 GeolD
	  	 Well Name
	 	 Well

No.
	 	 Parish
	 	 API #
	 	 LA

Serial
	 	 Unit Name
	 	 Comments

	13N10W2	  	JACKSON DAVIS JR 2 H	 	1	 	RED RIVER	 	17081211740000	 	241252	 	HA RA SUT	 	
	13N10W22	  	L P WARE FARMS 22	 	1	 	RED RIVER	 	17081210020000	 	239622	 	HA RA SUH	 	
	13N10VV22	  	LAKE CHARM LLC 22	 	001-ALT	 	RED RIVER	 	17081213030000	 	242768	 	HA RA SUH	 	
	13N10W22	  	LAKE CHARM LLC 22	 	002-ALT	 	RED RIVER	 	17081213040000	 	242769	 	HA RA SUH	 	
	13N10W22	  	LAKE CHARM LLC 22	 	003-ALT	 	RED RIVER	 	17081213050000	 	242770	 	HA RA SUH	 	
	13N10W22	  	LAKE CHARM LLC 22	 	004-ALT	 	RED RIVER	 	17081213060000	 	242771	 	HA RA SUN	 	
	13N10W22	  	L P WARE FARMS 22	 	002-ALT	 	RED RIVER	 	17081213080000	 	242888	 	HA RA SUN	 	
	13N10W22	  	L P WARE FARMS 22	 	003-ALT	 	RED RIVER	 	17081213100000	 	242895	 	HA RA SUH	 	
	13N10W23	  	FRED WILLIS MD 23H	 	1	 	RED RIVER	 	17081211020000	 	240613	 	HA RA SUI	 	
	13N10W24	  	DIANE MILNER 24	 	1	 	RED RIVER	 	17081211080000	 	240703	 	HA RB SUC	 	
	13N10W24 and 25	  	DH MILNER 24/25 HC	 	1	 	RED RIVER	 	17081213850000	 	244136	 	HA RB SUC	 	
	13N10W24 and 25	  	DR MILNER 24/25 RC	 	2-ALT	 	RED RIVER	 	17081213860000	 	244136	 	HA RB SUC	 	
	13N10W25	  	JERRY GLOVER 25	 	1	 	RED RIVER	 	17081211840000	 	241318	 	HA RA SUC	 	
	13N10W26	  	DOUGLAS DICKSON 26	 	1	 	RED RIVER	 	17081211710000	 	241207	 	HA RA SUB	 	
	13N10W27	  	JOE K ORR 27 H	 	1	 	RED RIVER	 	17081211350000	 	240898	 	HA RA SUA	 	
	13N10W3	  	GETULIO BREWER 3 H	 	1	 	RED RIVER	 	17081210960000	 	240551	 	HA RA SUU	 	
	13N10W3	  	GETULIO BREWER 3 H	 	002-ALT	 	RED RIVER	 	17081213450000	 	243564	 	HA RA SUU	 	
	13N10W34	  	LAURI NORWOOD 34 H	 	1	 	RED RIVER	 	17081211610000	 	241139	 	HA RA SUV	 	
	13N10W35	  	PAULA HERRING 35H	 	1	 	RED RIVER	 	17081211900000	 	241351	 	HA RA SUE	 	
	13N10VV36	  	SUSTAINABLE FTS 3611	 	1	 	RED RIVER	 	17081211690000	 	241205	 	HA RA SUD	 	
	13N11W4	  	GEORGE LORMAND 4 H	 	1	 	RED RIVER	 	17081210250000	 	239966	 	HA RD SUM	 	
	13N11W4	  	JOSEPH DILL 4	 	001-ALT	 	RED RIVER	 	17081213170000	 	243198	 	HA RD SUM	 	
	13N11W4	  	JOSEPH DILL 4	 	002-ALT	 	RED RIVER	 	17081213180000	 	243200	 	HA RD SUM	 	
	13N11W4	  	JOSEPH DILL 4	 	003-ALT	 	RED RIVER	 	17081213190000	 	243201	 	HA RD SUM	 	
	13N11W4	  	JOSEPH DILL 4	 	004-ALT	 	RED RIVER	 	17081213200000	 	243202	 	HA RD SUM	 	
	13N11W4	  	JOSEPH DILL 4	 	005-ALT	 	RED RIVER	 	17081213210000	 	243203	 	HA RD SUM	 	
	13N11W4	  	JOSEPH DILL 4	 	006-ALT	 	RED RIVER	 	17081213220000	 	243204	 	HA RD SUM	 	
	13N11W4	  	JOSEPH DILL 4	 	007-ALT	 	RED RIVER	 	17081213230000	 	243205	 	HA RD SUM	 	
	13N11W5	  	GEORGE LORMAND 5H	 	1	 	RED RIVER	 	17081210310000	 	239991	 	HA RD SUN	 	
	13N12W14	  	CLAY ROBERTSON 14	 	1	 	DE SOTO	 	17031248880000	 	240206	 	HA RC SUJ	 	
	13N12W15	  	CLAY ROBERTSON 15	 	1	 	DE SOTO	 	17031247920000	 	239817	 	HA RC SUB	 	
	13N12W16	  	CARMEL LAKE 16	 	1	 	DE SOTO	 	17031247520000	 	239680	 	HA RC SUA	 	
	13N12W20	  	CARMEL TRUST 20	 	1	 	DE SOTO	 	17031247120000	 	239573	 	JUR RB SUC	 	
	13N12W21	  	CALHOUN 21	 	1	 	DE SOTO	 	17031245260000	 	238720	 	HA RC SUC	 	
	13N12VV21	  	DIOCESE OF SHVPRT 21	 	001-ALT	 	DE SOTO	 	17031245320000	 	238761	 	HA RC SUC	 	
	13N12W23	  	ROBERTSON ETAL 23	 	1	 	DE SOTO	 	17031248110000	 	239894	 	HA RC SUK	 	
	13N12W28	  	JAMES STANSELL 28	 	002-ALT	 	DE SOTO	 	17031254680000	 	242218	 	HA RC SUD	 	
	13N12W28	  	JAMES STANSELL 28	 	003-ALT	 	DE SOTO	 	17031254690000	 	242219	 	HA RC SUD	 	
	13N12W28	  	JAMES STANSELL 28	 	1	 	DE SOTO	 	17031255190000	 	242395	 	HA RC SUD	 	
	13N12W29	  	PIRKLE 29	 	1	 	DE SOTO	 	17031247470000	 	239665	 	JUR RB SUD	 	
	13N12W32	  	LAFFITTE 32	 	1	 	DE SOTO	 	17031243600000	 	238626	 	JUR RB SUA	 	
	13N12W36	  	JOE INABNETT36	 	1	 	DE SOTO	 	17031252780000	 	241600	 	HA RA SU68	 	
	14N10W11	  	MELBURN WOOD 11	 	1	 	RED RIVER	 	17081213150000	 	243150	 	HA RA SUE	 	
	14N10W21	  	RONALD GUIN 21 H	 	1	 	RED RIVER	 	17081210610000	 	240247	 	HA RA SUY	 	
	14N10W26	  	BROWN SW MIN 26 H	 	1	 	RED RIVER	 	17081210240000	 	239962	 	HA RA SUK	 	
	14N10W26	  	SUSTAINABLE FST 26	 	003-ALT	 	RED RIVER	 	17081213380000	 	243384	 	HA RA SUK	 	
	14N10W26	  	SUSTAINABLE FST 26	 	001-ALT	 	RED RIVER	 	17081213390000	 	243385	 	HA RA SUK	 	
	14N10W26	  	SUSTAINABLE FST 26	 	002-ALT	 	RED RIVER	 	17081213400000	 	243386	 	HA RA SUK	 	
	14N10VV26	  	SUSTAINABLE FST 26	 	004-ALT	 	RED RIVER	 	17081213410000	 	243426	 	HA RA SUK	 	
	14N10W26	  	SUSTAINABLE FST 26	 	005-ALT	 	RED RIVER	 	17081213420000	 	243427	 	HA RA SUK	 	
	14N10W26	  	SUSTAINABLE FST 26	 	006-ALT	 	RED RIVER	 	17081213430000	 	243428	 	HA RA SUK	 	
	14N10W27	  	PAVILLION LAND 27	 	1	 	RED RIVER	 	17081212300000	 	242670	 	HA RA SUY	 	
	14N10W27	  	SUSTAINABLE FST 27	 	001-ALT	 	RED RIVER	 	17081213110000	 	243113	 	HA RA SUY	 	
	14N10W27	  	SUSTAINABLE FST 27	 	002-ALT	 	RED RIVER	 	17081213120000	 	243114	 	HA RA SUY	 	
	14N10W27	  	SUSTAINABLE FST 27	 	003-ALT	 	RED RIVER	 	17081213130000	 	243115	 	HA RA SUY	 	
	14N10W27	  	PAVILLION LAND 27	 	002-ALT	 	RED RIVER	 	17081213750000	 	244016	 	HA RA SUY	 	
	14N10W27	  	PAVILLION LAND 27	 	003-ALT	 	RED RIVER	 	17081213760000	 	244017	 	HA RA SUY	 	

  
 3 

															
	 GeolD
	  	 Well Name
	 	 Well

No.
	 	 Parish
	 	 API #
	 	 LA

Serial
	 	 Unit Name
	 	 Comments

	14N10W3	  	L L GOLSON 3	 	1	 	RED RIVER	 	17081211140000	 	240722	 	HA RA SU74	 	
	14N10W34	  	GETULIO BREWER 34 H	 	1	 	RED RIVER	 	17081210270000	 	239977	 	HA RA SUZ	 	
	14N10W35	  	BLACK STONE MIN 35 H	 	2	 	RED RIVER	 	17081212490000	 	242322	 	HA RA SUD	 	
	14N11W12	  	EDGAR CASON 12 H	 	1	 	RED RIVER	 	17081210290000	 	239984	 	HA RA SUU	 	
	14N11W13	  	EDGAR CASON 13 H	 	1	 	RED RIVER	 	17081210390000	 	240015	 	HA RA SUN/	 	
	14N11W13	  	EDGAR CASON 13 H	 	002-ALT	 	RED RIVER	 	17081213640000	 	243820	 	HA RA SUV	 	
	14N11W13	  	EDGAR CASON 13 H	 	004-ALT	 	RED RIVER	 	17081213660000	 	243822	 	HA RA SUV	 	
	14N11W13	  	EDGAR CASON 13 H	 	005-ALT	 	RED RIVER	 	17081213670000	 	243823	 	HA RA SUV	 	
	14N11W17	  	BSTMA LLC 17H	 	1	 	RED RIVER	 	17081210150000	 	239790	 	HA RA SUT	 	
	14N11W20	  	REX YOUNG 20 H	 	1	 	RED RIVER	 	17081210110000	 	239747	 	HA RD SUA	 	ECA Contract Operator
	14N11W29	  	REX YOUNG 29H	 	1	 	RED RIVER	 	17081209980000	 	239574	 	HA RD SUE	 	ECA Contract Operator
	14N11W32	  	DONNIE SAVELL 32H	 	1	 	DE SOTO	 	17031247960000	 	239829	 	HA RD SUG	 	
	14N11W33	  	JOSEPH A DILL 33 H	 	1	 	RED RIVER	 	17081209710000	 	239038	 	HA RD SUH	 	
	14N11W33	  	LORMAND 33	 	001-ALT	 	RED RIVER	 	17081213280000	 	243268	 	HA RD SUH	 	
	14N11W33	  	LORMAND 33	 	002-ALT	 	RED RIVER	 	17081213290000	 	243269	 	HA RD SUH	 	.
	14N11W33	  	LORMAND 33	 	003-ALT	 	RED RIVER	 	17081213300000	 	243270	 	HA RD SUH	 	
	14N11W33	  	LORMAND 33	 	004-ALT	 	RED RIVER	 	17081213310000	 	243271	 	HA RD SUH	 	
	14N11W33	  	LORMAND 33	 	005-ALT	 	RED RIVER	 	17081213320000	 	243272	 	HA RD SUH	 	
	14N11W33	  	LORMAND 33	 	006-ALT	 	RED RIVER	 	17081213330000	 	243273	 	HA RD SUH	 	
	14N11W33	  	LORMAND 33	 	007-ALT	 	RED RIVER	 	17081213340000	 	243274	 	HA RD SUH	 	
	14N9W16	  	L L GOLSON 16 H	 	1	 	RED RIVER	 	17081211180000	 	240743	 	HA RA SU80	 	
	14N9W21	  	RUSSELL THOMAS 21H	 	1	 	RED RIVER	 	17081211560000	 	241072	 	HA RA SU81	 	
	14N9W23	  	PMG SWINT 23	 	1	 	RED RIVER	 	17081211950000	 	241391	 	CV RB SUSS	 	
	14N9W24	  	BATCHELOR ETAL 24 H	 	1	 	RED RIVER	 	17081211490000	 	240989	 	HA RA SUA	 	
	14N9W26	  	AZILE HENRY 26H	 	1	 	RED RIVER	 	17081211570000	 	241075	 	HA RA SU65	 	
	14N9W27	  	REGINA SWINT 27 H	 	1	 	RED RIVER	 	17081211540000	 	241046	 	HA RA SU54	 	
	14N9W5	  	BRENDA JONES 5	 	1	 	RED RIVER	 	17081210820000	 	240432	 	HA RA SUHH	 	
	14N9W6	  	HARRY LAWSON 6	 	1	 	RED RIVER	 	17081210830000	 	240434	 	HA RA SUD	 	
	14N9W7	  	MCLEMORE ET UX 7	 	1	 	RED RIVER	 	17081210630000	 	240249	 	HA RA SUG	 	
	14N9W8	  	GEORGE MCLEMORE 8 H	 	1	 	RED RIVER	 	17081210370000	 	240005	 	HA RA SU53	 	
	14N9W9	  	L L GOLSON 9 H	 	1	 	RED RIVER	 	17081211100000	 	240707	 	HA RA SU79	 	

  
 4 

 

 

 EXHIBIT “D” 

A.A.P.L. FORM 610-1982 

MODEL FORM OPERATING AGREEMENT 

OPERATING AGREEMENT 

DATED 
  

									
		 		 		 		  	
		 	  
	 		 	  
	  	

  

			
	 OPERATOR
	  	  

			
		
	 CONTRACT AREA
	  	  

	 	  	 
	 	  	 
	 	  	 

							
				
	 PARISH OF
	 	  
	  	STATE OF	  	  

 COPYRIGHT 1982 - ALL RIGHTS RESERVED AMERICAN ASSOCIATION OF PETROLEUM LANDMEN, 4100 FOSSIL
CREEK BLVD., FORT WORTH, TEXAS, 76137.2791, APPROVED FORM. A.A.P.L. NO 610 - 1982 REVISED 

 TABLE OF CONTENTS 

 

							
	 Article
	 	 	  	 Title
	  	Page
	 I.
	 	 DEFINITIONS
	  	1
			
	 II.
	 	 EXHIBITS
	  	2
			
	 III.
	 	 INTERESTS OF PARTIES
	  	3
				
		 	 A.
	  	 OIL AND GAS INTERESTS
	  	3
				
		 	 B.
	  	 INTERESTS OF PARTIES IN COSTS AND PRODUCTION
	  	3
				
		 	 C.
	  	 SUBSEQUENTLY CREATED INTERESTS
	  	3
			
	 IV.
	 	 TITLES
	  	4
				
		 	 A.
	  	 TITLE EXAMINATION
	  	4
				
		 	 B.
	  	 REDUCTION OR LOSS
	  	5-6
			
	 V.
	 	 OPERATOR
	  	6
				
		 	 A.
	  	 DESIGNATION AND RESPONSIBILITIES OF OPERATOR
	  	6
				
		 	 B.
	  	 RESIGNATION OR REMOVAL OF OPERATOR AND SELECTION OF SUCCESSOR
	  	6
				
		 		  	 1.      Resignation or Removal of Operator
	  	6
				
		 		  	 2.      Selection of Successor Operator
	  	7
				
		 	 C.
	  	 EMPLOYEES
	  	7
				
		 	 D.
	  	 DRILLING CONTRACTS
	  	7
			
	 VI.
	 	 DRILLING AND DEVELOPMENT
	  	7
				
		 	 A.
	  	 INITIAL WELL
	  	7
				
		 	 B.
	  	 SUBSEQUENT OPERATIONS
	  	7
				
		 		  	 1.      Proposed Operations
	  	7
				
		 		  	 2.      Operations by Less than All Parties
	  	8-11
				
		 		  	 3.      Stand-By
Time
	  	11
				
		 		  	 4.      Sidetracking
	  	11

							
				
		 	 C.
	  	 TAKING PRODUCTION IN KIND
	  	12
				
		 	 D.
	  	 ACCESS TO CONTRACT AREA AND INFORMATION
	  	13
				
		 	 E.
	  	 ABANDONMENT OF WELLS
	  	13
				
		 		  	 1.      Abandonment of Dry Holes
	  	13
				
		 		  	 2.      Abandonment of Wells that have Produced
	  	13
				
		 		  	 3.      Abandonment of
Non-Consent Operations
	  	14
			
	 VII.
	 	 EXPENDITURES AND LIABILITY OF PARTIES
	  	14
				
		 	 A.
	  	 LIABILITY OF PARTIES
	  	14
				
		 	 B.
	  	 LIENS AND PAYMENT DEFAULTS
	  	15
				
		 	 C.
	  	 PAYMENTS AND ACCOUNTING
	  	
				
		 	 D.
	  	 LIMITATION OF EXPENDITURES
	  	15
				
		 		  	 1.      Drill or Deepen
	  	15
				
		 		  	 2.      Rework, Recomplete or Plug Back
	  	16
				
		 		  	 3.      Other Operations
	  	16
				
		 	 E.
	  	 RENTALS, SHUT-IN WELL PAYMENTS AND MINIMUM
ROYALTIES
	  	16
				
		 	 F.
	  	 TAXES
	  	17
				
		 	 G.
	  	 INSURANCE
	  	17
			
	 VIII.
	 	 ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST
	  	18
				
		 	 A.
	  	 ACREAGE OR CASH CONTRIBUTIONS
	  	18
				
		 	 B.
	  	 MAINTENANCE OF UNIFORM INTEREST
	  	18
				
		 	 C.
	  	 WAIVER OF RIGHTS TO PARTITION
	  	18
			
	 IX.
	 	 INTERNAL REVENUE CODE ELECTION
	  	19
			
	 X.
	 	 CLAIMS AND LAWSUITS
	  	19
			
	 XI.
	 	 FORCE MAJEURE
	  	20
			
	 XII.
	 	 NOTICES
	  	20

							
			
	 XIII.
	 	 TERM OF AGREEMENT
	  	20
			
	 XIV.
	 	 COMPLIANCE WITH LAWS AND REGULATIONS
	  	21
				
		 	 A.
	  	 LAWS, REGULATIONS AND ORDERS
	  	21
				
		 	 B.
	  	 GOVERNING LAW
	  	21
				
		 	 C.
	  	 REGULATORY AGENCIES
	  	21
			
	 XV.
	 	 OTHER PROVISIONS
	  	22
				
		 	 A.
	  	 NON-OPERATOR’S CONSENT OR NON-CONSENT OF THE INITIAL WELL AS DEFINED IN ARTICLE VI.A
	  	22
				
		 	 B.
	  	 CONFLICTS
	  	23
				
		 	 C.
	  	 VERTICAL WELLS
	  	23
				
		 	 D.
	  	 HORIZONTAL WELLS
	  	23
				
		 	 E.
	  	 PRIORITY OF OPERATIONS — VERTICAL WELLS
	  	23
				
		 	 F.
	  	 PRIORITY OF OPERATIONS — HORIZONTAL WELLS
	  	24
				
		 	 G.
	  	 DEEPER DRILLING
	  	24
				
		 	 H.
	  	 SIDETRACKING
	  	25
				
		 	 I.
	  	 PARTIES TO OPERATIONS
	  	25
				
		 	 J.
	  	 MISCELLANEOUS COSTS
	  	25
				
		 	 K.
	  	 MULTIPLE BILLING
	  	26
				
		 	 L.
	  	 PAYMENTS AND ACCOUNTING
	  	26-27
				
		 	 M.
	  	 DISTRIBUTION OF REVENUE AND ROYALTIES
	  	27
				
		 	 N.
	  	 WELL COST ADJUSTMENTS
	  	27
				
		 	 O.
	  	 STANDARD OF CONDUCT OF OPERATIONS
	  	29
				
		 	 P.
	  	 BANKRUPTCY
	  	29
				
		 	 Q.
	  	 MUTUALITY
	  	29
				
		 	 R.
	  	 MEMORANDUM OF OPERATING AGREEMENT
	  	29
				
		 	 S.
	  	 HEADINGS
	  	29

							
				
		 	 T.
	  	 NEWS RELEASES
	  	30
				
		 	 U.
	  	 OVER-EXPENDITURE OF AFE
	  	30
				
		 	 V.
	  	 AND ASSIGNS
	  	31
				
		 	 W.
	  	 NON-PAYMENT
	  	32
				
		 		  	 1. Suspension of Rights
	  	32
				
		 		  	 2. Suit for Damages
	  	32
				
		 		  	 3. Deemed Non-Consent
	  	32
				
		 		  	 4. Good Faith Disputes
	  	33
				
		 		  	 5. Costs and Attorney’s Fees
	  	33
				
		 		  	 6. Financing Statement
	  	33
				
		 	 X.
	  	 DISPOSAL OF SURPLUS MATERIALS
	  	33
				
		 	 Y.
	  	 COUNTERPART RATIFICATION
	  	33
				
		 	 Z.
	  	 HOLIDAYS
	  	33
				
		 	 AA.
	  	 USE OF AFFILIATES
	  	33
				
		 	 BB.
	  	 ACKNOWLEDGEMENT OF OPERATIONS OUTSIDE THE CONTRACT AREA
	  	34
			
	 XVI.
	 	 MISCELLANEOUS
	  	35

 OPERATING AGREEMENT 

THIS AGREEMENT, entered into by and between, hereinafter designated and referred to as “Operator”, and the signatory party or
parties other than Operator, sometimes hereinafter referred to individually herein 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 and 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 “oil and gas” shall mean oil, gas, casinghead gas, gas condensate, and 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. 
 B. The terms
“oil and gas lease”, “lease” and “leasehold” shall mean the oil and gas leases covering tracts of land lying within the Contract Area which are owned by the parties to this agreement. 

C. The term “oil and gas interests” shall mean unleased fee and mineral interests in tracts of land lying within the Contract Area
which are owned by parties to this agreement. 
 D. The term “Contract Area” shall mean all of the lands, oil and gas leasehold
interests and oil and gas interests intended to be developed and operated for oil and gas purposes under this agreement. Such lands, oil and gas leasehold interests and oil and gas interests are described in Exhibit “A”. 

E. 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 or drilling in the Contract Area or as fixed by express agreement of the Drilling Parties. 

F. The term “drillsite shall mean the oil and gas lease or interest on which a proposed well is to be located. 

G. 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. 

  
 1 

 H. The terms “Non-Drilling Party” and “Non-Consenting Party” shall mean a party who elects not to participate in a proposed operation. 

I. The term “lateral” shall mean that portion of a well bore that deviates from approximate vertical orientation to approximate
horizontal orientation and all well bore beyond such deviation to total depth. 
 J. The term “horizontal well” is more
specifically defined under Article XV.D. 
 K. The term “multi-lateral well” shall mean a well which contains more than one
lateral and in which the well bores deviate from approximate vertical orientation to approximate 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 reentry of an existing well bore. 
 L. The term “total depth”, applied to all
multi-lateral or horizontal wells drilled pursuant to this Agreement, shall mean the distance from the surface of the ground to the terminus of the well bore. Each lateral taken together with the common vertical well bore shall be considered a
single well bore and shall have a corresponding total depth. When the proposed operation(s) is the drilling of, or operations on, well containing a lateral component, the term “depth” wherever used in the Agreement shall be deemed to read
“total measured depth” insofar as it applies to such well. 
 Unless the context otherwise clearly indicates, words used in the
singular include the plural, the plural includes the singular, and the neuter gender includes the masculine and the feminine. 
 ARTICLE
II. 
 EXHIBITS 
 The following
exhibits, as indicated below and attached hereto, are incorporated in and made a pan hereof: 
  

	☐	A. Exhibit “A” shall include the following information: 

  

	 	(1)	Identification of lands subject to this agreement, 

  

	 	(2)	Restrictions, if any, as to depths, formations, or substances, 

  

	 	(3)	Percentages or fractional interests of parties to this agreement, 

  

	 	(4)	Oil and gas leases and/or oil and gas interests subject to this agreement, 

  

	 	(5)	Addresses of parties for notice purposes. 

  

	☐	B. Exhibit “B” - Form of Lease. 

  

	☐	C. Exhibit “C” - Accounting Procedure. COPAS 

  
 2 

	☐	D. Exhibit “D” - Insurance. 

  

	☐	E. Exhibit “E” Gas Balancing Agreement. 

  

	☐	F. Exhibit “F” - Memorandum of Operating Agreement. 

 If any provision of any
exhibit, except Exhibit “F.”, is inconsistent with any provision contained in the body of this agreement, the provisions in the body of this agreement shall prevail. If any inconsistency exists between Exhibit “E” and the
provisions in the body of this agreement, then Exhibit “E” 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 the royalty interest reserved 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 to the payment of royalties, overriding royalties, net profits interests, production payments and other similar payments out of production (“burdens”). Any such burdens not common to the interest of the parties hereto
shall be borne by the party whose interest is burdened therewith. 
 Nothing contained in this Article III shall be deemed an assignment or
cross-assignment of interests covered hereby. 
 C. Subsequently Created Interests: 

If any party should hereafter create any burden payable out of production attributable to its working interest hereunder, or if such a burden
existed prior to this agreement and is not set forth in Exhibit “A”, or was not disclosed in writing to all other parties prior to the execution of this agreement by all parties, or is not a jointly acknowledged and accepted obligation of
all parties or does not appear of record in the records of the parish in which the Contract Area is located prior to the execution of this Agreement (any such interest being hereinafter referred to as “subsequently created interest”
irrespective of the timing of its creation and the party out of whose working interest the subsequently created interest is derived being hereinafter referred to as “burdened party”), and: 

  
 3 

 1. 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 and save said other party, or parties, harmless from any and all claims and demands for payment asserted by owners of the subsequently created interest; and, 

2. 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 mariner as they are enforceable against the working interest of the burdened party. 

ARTICLE IV. 
 TITLES

 A. Title Examination: 
 Title
examination shall be made on the Contract Area and will include the ownership of the working interest, minerals, royalty, overriding royalty and production payments under the applicable leases. At the time a well is proposed, each party contributing
leases and/or oil and gas interests to the drillsite, or to be included in such drilling unit, 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 be examined by attorneys, its
qualified Landmen or by outside attorneys. Copies of all title opinions shall be furnished to each party hereto. The cost incurred by Operator in this title program shall be borne as follows: 

☐ Option No. 1: Costs incurred by Operator in procuring abstracts and title examination (including preliminary,
supplemental shut-in gas royalty opinions and division order title opinions) shall be a part of the administrative overhead as provided in Exhibit “C”, and shall not be a direct charge, whether
performed by Operator’s staff attorneys or by outside attorneys. 
 ☐ Option No. 2: Costs incurred by Operator in procuring
abstracts and fees paid attorneys and lease brokers for title examination (including preliminary, supplemental, shut-in gas royalty opinions and division order title opinions) 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 without the prior consent of Non-Operators which shall be at prevailing market rates. 

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 as well as the conduct of hearings before governmental agencies for the securing of spacing or
pooling orders. This shall not prevent any party from appearing on its own behalf at any such hearing. Costs incurred by Operator in procuring spacing and pooling orders including fees paid outside attorneys 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”. 

  
 4 

 No well shall be drilled on the Contract Area until after (1) the title to the drill site or
drilling unit, including any backbuild, has been examined and approved by the Operator. 
 B. Reduction or Loss: 

For the purposes of this provision the following definitions shall apply: 

Reduction: A reduction of the party’s interest from that shown on Exhibit “A”, whether through failure of title,
operation of law, or the application of any lease provision of restriction, whether express or implied, in an oil and gas lease, or interests therein. 

Final Destination of the Reduction. The later of the date in which: (i) the lease provision resulting in the Reduction is
triggered; (ii) notice of a failure of title or disputed interest is received by the Party contributing the Interest; (iii) final resolution of any litigation concerning the Reduction; (iv) or, the date of the final order of any
governmental body or tribunal which results in a Reduction. 
 Should there be a Reduction of the party’s interest from that shown on
Exhibit “A”, the party contributing the affected lease or interest shall have ninety (90) days from Final Determination of the reduction to acquire a new lease or other instrument curing the entirety of the Reduction, and failing to
do so, this agreement, nevertheless, shall continue in force as to all remaining oil and gas leases and interests, Notwithstanding anything herein to the contrary, during such ninety (90) day right to cure, no party to this agreement shall
directly or indirectly attempt to lease, purchase or acquire the affected oil and gas lease or interest. In the event the Reduction is cured, this agreement shall continue in force as to said lease or interest. In the event the Reduction is not
timely cured, and a party to this agreement acquires the oil and gas lease or other interest, this agreement shall continue in force as to said lease or interest. 

(a) The party whose oil and gas lease or interest is affected by the Reduction 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 theretofore paid or incurred, but there shall be no additional liability on its part to the other parties hereto by reason of such Reduction; 

(b) There shall be no retroactive adjustment of expenses incurred or revenues received from the operation of the interest which has been lost,
but the interests of the parties shall be revised on an acreage basis, as of the time it is determined finally that Reduction has occurred, so that the interest of the party whose lease or interest is affected by the Reduction will thereafter be
reduced in the Contract Area by the amount of the interest lost; 
 (c) If the proportionate interest of the other parties hereto in any
producing well theretofore drilled on the Contract Area is increased by reason of the Reduction, the party who suffered the failure 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; 

  
 5 

 (d) Should any person not a party to this agreement, who is determined to be the owner of any
interest which has been reduced, pay in any manner any pan 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 third party for prior production of oil and gas which arises by reason of the Reduction shall be borne by the
party or parties who suffered the failure in the same proportions in which they shared in such prior production; and 
 (f) No charge shall
be made to the joint account for legal expenses, fees or salaries, in connection with the defense of the interest claimed by any party hereto, it being the intention of the parties hereto that each shall defend their own respective interests and
bear all expenses in connection therewith. 
 ARTICLE V. 

OPERATOR 
 A. Designation and
Responsibilities of Operator: 
 shall be the Operator of the Contract 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. It shall conduct all such operations in a good and workmanlike manner, but it shall have no liability as Operator to the other parties for losses
sustained or liabilities incurred, except such as may result from gross negligence or willful misconduct. Operator represents that it has established and shall maintain at all times while this Agreement remains in effect, a policy and management
system governing issues related to health, safety, security, and the environment (hereinafter referred to as “HSSE Policy-’). Operator shall conduct all operations on the Contract Area
in accordance with Operator’s HSSE Policy. 
 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 if it fails or refuses to carry out its duties hereunder, or becomes insolvent, bankrupt or is placed in receivership,
or by the affirmative vote of two (2) or more Non-Operators owning a majority interest based on ownership as shown on Exhibit “A” remaining after excluding tire voting interest of Operator.
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 affiliate, subsidiary, parent or successor corporation
shall not be the basis for removal of Operator. 

  
 6 

 2. Selection of Successor Operator: Upon the resignation or removal of Operator, 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 fails to vote or votes only to succeed itself, 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” remaining after excluding the voting interest of the Operator that was removed.

 C. Employees: 
 The number of
employees used by Operator in conducting operations hereunder, their selection, and the hours of labor and the compensation for services performed shall be determined by Operator, and all such employees shall be the employees of Operator.

 D, Drilling Contracts: 
 All wells
drilled and/or completed on the Contract Area shall be drilled and/or completed on a competitive contract basis at the usual rates prevailing in the area, if it so desires, Operator may employ its own tools, materials and equipment in the drilling
or completion of wells, but its charges therefore shall not exceed the prevailing rates in the area, 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. 
 ARTICLE VI. 

DRILLING AND DEVELOPMENT 
 A. Initial
Well: 
 The Initial Well was the HA
RA                ,                and it was spud
on                ,                at a bottom hole location of
approximately                 and                 and a proposed surface hole location of
approximately                 and                of
Section                -T                 
N-R                 W,                 Parish,
Louisiana with the perforation point for the bottom hole location to be no closer than 330’; from any adjacent line. 
 B. Subsequent Operations:

 1. Proposed Operations. Should any party hereto desire to drill any well on the Contract Area or to rework, deepen or plug back
a dry hole drilled at the joint expense of all parties or a well jointly owned by all the parties and not then producing in paying quantities, the party desiring to drill, rework, deepen or plug back such a well shall give the other parties written
notice of the proposed operation, specifying the work to be performed, the location, proposed depth, objective formation and the estimated cost of the operation. The parties receiving such a notice shall have thirty (30) days after receipt of
the notice within which to notify the party wishing 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, plug back or drill deeper may be given by
telephone and the response period shall be limited to twenty-four (24) hours, exclusive of 

  
 7 

 
Saturday, Sunday, and legal holidays. Failure of a 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 proposed operation. Any notice or response given by telephone shall be promptly confirmed in writing. 
 If all parties elect to
participate in such a proposed operation, Operator shall, within ninety (90) days after expiration of the notice period of thirty (30) days (or as promptly as possible after the expiration of the twenty-four (24) 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 at the risk and expense of all parties hereto: 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 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.
Notwithstanding the force majeure provisions of Article XI, if the actual operation has not been commenced within the time provided (including any extension thereof as specifically permitted herein) and if any party hereto still desires to conduct
said operation, written notice proposing same must be resubmitted to the other parties in accordance with the provisions hereof as if no prior proposal had been made. 

2. Operations by Less than All Parties: If any party receiving such notice as provided in Article VI.B.1. or VII (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, within ninety
(90) days after the expiration of the notice period of thirty (30) days (or as promptly as possible after the expiration of the twenty-four (24) hour period when a drilling rig is on location, as the case may be) actually commence the
proposed operation1 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: (a) request Operator to perform the work required by such proposed operation for the account of the Consenting
Parties, or (b) designate one of the Consenting Parties as Operator to perform such work. 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 the Consenting 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 twenty-four (24) hours (exclusive of Saturday. Sunday and legal holidays) after receipt of such notice, shall advise the proposing party of its desire to (a) limit participation to such party’s 

 

	1 	 Nothing contained herein shall prohibit Operator or the participating parties from actually commencing the
proposed operation before the expiration of the notice period nor shall the timing of such commencement affect in any way the validity of it party’s election or deemed election.

  
 8 

 
interest as shown on Exhibit “A” or (b) carry its proportionate part of Non-Consenting Parties’ interests, and failure to advise the
proposing party shall be deemed an election under (a). In the event a drilling rig is on location, the time permitted for such a response shall not exceed a total of twenty-four (24) hours (exclusive of Saturday, Sunday and legal holidays). The
proposing party, at its election, may withdraw such proposal if there is insufficient participation and shall promptly notify all parties of such decision. 

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, the Consenting Parties shall plug and abandon the well and restore the surface location at their sole cost, risk and expense. If any well drilled, reworked, deepened or plugged back under the
provisions of this Article results in a producer of 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 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, 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 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 production taxes, excise taxes, royalty, overriding royalty and other interests not excepted by Article III. C. payable out of or measured by the production front such well accruing with respect to such interest until it
reverts) shall equal the total of the following: 
 (a) 100% 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 cacti 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 

(b) 500% of that portion of the costs and expenses of drilling, reworking, deepening, plugging back, testing and completing, after deducting
any cash contributions received under Article XV.L., and 500% of 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 Wit had
participated therein. 
 An election not to participate in the drilling or the 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 account. Any such reworking or plugging back operation conducted during the recoupment 

  
 9 

 
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 three hundred percent (300%) of that portion of the
costs of the reworking or plugging hack operation which would have been chargeable to such Non-Consenting Party had it participated therein. If such a reworking 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. 
 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
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, plugging back or deeper drilling 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, plugging back or deeper drilling, 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 sixty
(60) 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, deepening, plugging hack, testing, completing, 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
shell 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 on the first day of the month following the month of payout, 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, reworking, deepening 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 in accordance with the terms of this agreement and the Accounting Procedure attached hereto. 

  
 10 

 Notwithstanding the provisions of this Article VI.B.2., it is agreed that without the mutual
consent of all parties, no wells shall be completed in or produced front a source of supply from which in well located elsewhere on the Contract Area is producing, unless such well conforms to the then-existing well spacing pattern for such source
of supply. 
 The provisions of this Article shall have no application whatsoever to the drilling of the initial well described in Article
VI.A except (a) as to Article VII.D.1. (Option No. 2), if selected, or (b) as to the reworking, deepening and plugging back of such initial well after it has been drilled to the depth specified in Article VI.A. if it shall thereafter
prove to be a dry hole or, if initially completed for production, ceases to produce in paying quantities. 
 3. Stand-by Time: 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,
stand-by costs incurred pending response to a party’s nonce proposing a reworking, deepening, plugging back or completing operation in such a well 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., 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. 
 4. Sidetracking: Except as hereinafter provided, those provisions of
this agreement applicable to it “deepening” operation shall also be applicable to any proposal to directionally control and intentionally deviate a well from vertical so as to change the bottom hole locations (herein call
“sidetracking”), unless done to straighten the hole or to drill around junk in the hole or because of other mechanical difficulties. Any party having the right to participate in a proposed sidetracking operation that does not own an
interest in the affected well bore at the time of the notice shall, upon electing to participate, tender to the well bore owners its proportionate share (equal to its interest in the sidetracking operation) of the value of that portion of the
existing well bore to be utilized as follows: 
 SEE ARTICLE XV.F(2). For additional provisions regarding sidetracking. 

(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 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 the well’s salvable materials and equipment down to the depth at which the sidetracking operation is initiated, determined in accordance with the provisions or Exhibit
“C”, less the estimated cost of salvaging and the estimated cost of plugging and abandoning. 

  
 11 

 (c) In the event that notice for a sidetracking operation is given while the drilling rig to be
utilized is on location, the response period shall be limited to twenty-four (24) hours, exclusive of Saturday, Sunday and legal holidays; provided, however, any party may request and receive up to eight (8) additional days after
expiration of the twenty-four (24) hours within which to respond by paying for all stand-by time incurred (during such extended response period. If more than one party elects to take such additional time
to respond to the notice, stand by 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. In all other instances the response period to a proposal for sidetracking shall be limited to thirty
(30) days. 
 C. Taking Production in Kind: 

Each Consenting Party shall have the right to 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. 

In the event any party shall fail 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 root the obligation to purchase such oil and/or gas or sell a to others at any time and from time to time,
for the account of the non-taking party at the best price reasonably obtainable in the area for such production. Any such purchase or sale by Operator shall be subject always to the right of the owner of the
production to exercise at any time its right to take in kind, or separately dispose of, its share of all oil and/or gas 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. 

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 respective accounts of 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. 

  
 12 

 D. Access to Contract Area and Information: 

Each party shall have access to the Contract Area at all reasonable times, at its sole cost and risk to inspect or observe operations, and
shall have access at reasonable times to information pertaining to the development or operation thereof, including Operator’s hooks and records relating thereto. Operator, upon request, shall furnish each of the other parties with copies of all
forms or reports filed with governmental agencies, daily drilling reports, well logs, and actual monthly oil and gas production and sales volumes, and shall make available samples of any cores or cuttings taken from any well drilled on the Contract
Area. The cost of gathering and furnishing information to Non-Operator, other than that specified above, shall be charged to the Non-Operator that requests the
Information. Non consenting parties shall be denied access to the well location and well information until the non consent period has expired. 
 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 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 twenty-four (24) hours (exclusive of Saturday, Sunday and legal holidays) after receipt 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 shall have the right to lake over the well and conduct further operations in search of oil and/or gas subject to the provisions of Article VI.B. 

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 who
participated in the cost of drilling the well. 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, if, within
thirty (30) days after receipt 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 interval(s) of the formation(s) then open to production
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. Failure of a party to make written election within thirty (30) days will be deemed to be a consent to the abandonment of the well. Each abandoning party shall assign 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 well and related equipment, together
with its interest in the leasehold estate as to, but only as to, the interval or intervals of the formation or formations then open to production. If 

  
 13 

 
the interest of the abandoning party is or includes an 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 interval or intervals of the formation or formations then open to production, for a term of one (1) year and so long thereafter as oil and/or gas is produced from the interval or intervals of the formation or
formations 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 portion 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 interval or intervals then open other than the royalties retained in any lease made under the terms of this Article. If the Operator is not an abandoning
party, the Operator shall continue to operate Else 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 interval(a) 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. If the Operator is an abandoning party, the non-abandoning parties shall elect an operator
from themselves by vote of a majority interest of the non-abandoning parties. 
 3. Abandonment
of Non-Consent Operations: The provisions of Article VI.E.1. or Article 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 consenting 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. 
 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. It is not the intention of the parties to create, nor shall this agreement be construed as creating, a mining or other partnership or association, or to render the parties liable as partners. 

  
 14 

 B. Liens and Payment Defaults: 

Each Non-Operator grants to Operator a lien upon its oil and gas rights in the Contract Area, and a
security interest in its share of oil and/or gas when extracted and its interest in all equipment, to secure payment of its share of expense, together with interest thereon at the rate provided in Exhibit “C”. To the extent that Operator
has a security interest under the Uniform Commercial Code of the state, Operator 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 Operator 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 Non-Operator in
the payment of its share of expense, Operator shall have the right, without prejudice to other rights or remedies, to collect from the purchaser the proceeds from the sale of such Non-Operator’s share of
oil and/or gas until the amount owed by such Non-Operator, plus interest, has been paid. Each purchaser shall be entitled to rely upon Operator’s written statement concerning the amount of any default.
Operator grants a like lien and security interest to the Non-Operators to secure payment of Operator’s proportionate share of expense. 

If any party fails or is unable to pay its share of expense within sixty (60) 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. Each
party so paying its share of the unpaid amount shall, to obtain reimbursement thereof, be subrogated to the security rights described in the foregoing paragraph. 

SEE ARTICLE XV.L. 
 ALSO SEE ARTICLE XV.J. 

D. Limitation of Expenditures: 
 1.
Drill or Deepen: Without the consent of all parties, no well shall be drilled or deepened, except any well drilled or deepened pursuant to the provisions of Article VI.B.2. of this agreement. Consent to the drilling or deepening shall
include: 
 ☐ Option No. 1: Subject to the provisions of Article XV.J. hereof, all necessary expenditures for
the drilling or deepening, testing, completing and equipping of any horizontal well, including necessary tankage and/or surface facilities. 

☐ Option No 2: All necessary expenditures for the drilling or deepening and testing of any vertical or directional vertical well.
When such well has reached its authorized depth, and all tests have been completed, and the results thereof furnished to the parties, Operator shall give immediate notice to the Non-Operators who have the
right to participate in the completion costs. The parties receiving such notice shall have twenty-four (24) hours (exclusive of Saturday, Sunday and legal holidays) in which to elect to participate in the setting of casing and the completion
attempt. Such election, when made, shall include consent to all necessary expenditures for the completing and equipping of such well, including necessary tankage and/or surface facilities. 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. If one or more, but less than all of the parties, elect to set pipe and to attempt a completion, the provisions of Article
VI.B.2 hereof (the phrase “reworking, deepening or plugging back” as contained in Article VI.F1.2. shall be deemed to include “completing”) shall apply to the operations thereafter conducted by less than all parties. 

  
 15 

 2. Rework, Recomplete or Plug Back: Without the consent of two or more parties with a
majority interest, no well shall be reworked, recompleted or plugged back except a well reworked, recompleted or plugged back pursuant to the provisions of Article VI.13.2. 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. 

3. Other Operations: Without the consent of all parties, Operator shall not
undertake any single project reasonably estimated to require an expenditure in excess of One Hundred Thousand Dollars ($100,000.00) except in connection with a well, the drilling, reworking, deepening, completing, recompleting, or plugging back of
which 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 arc 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 authority for expenditure (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) but less than the amount first set forth above in this paragraph. 
 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. 
 Operator shall notify Non-Operator of the anticipated completion of a shut-in gas well, or the shutting in or return to production of a producing gas well, at least five (5) days (excluding
Saturday, Sunday and legal holidays), or at the earliest opportunity permitted by circumstances, prior to taking such action, but assumes no liability for failure to do so. In the event of failure by Operator to so notify Non-Operator, the loss of any lease contributed hereto by Non-Operator 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. 

  
 16 

 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 leasehold estate 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 leasehold estate, 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”. 
 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, at 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/or gas produced under the terms of this agreement. 
 G. Insurance: 

At all times while operations are conducted hereunder, Operator shall comply with the workmen’s 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”
Unless otherwise specified on Exhibit D, Operator shall also carry or provide insurance for the benefit of the joint account of the parties as outlined in Exhibit “D”, attached to and made a part hereof. Operator shall require all
contractors engaged in work on or for the Contract Area to comply with the workmen’s 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 public 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. 

  
 17 

 ARTICLE VIII. 

ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST 

A. 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 a well drilled inside the Contract Area. 
 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. 

B. Maintenance of Uniform Interests: 

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. 
 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. 
 C. 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. 

  
 18 

 ARTICLE IX. 

INTERNAL REVENUE CODE ELECTION 

This agreement is not intended to create, and shall not be construed to create, a relationship of partnership or an association for profit
between or among the parties hereto. Notwithstanding any provision herein that the rights and liabilities hereunder are several and not joint or collective, or that this agreement and operations hereunder shall not constitute a partnership, if, for
federal income tax purposes, this agreement and the operations hereunder are regarded as a partnership, each party hereby 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 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 Federal Regulations I. 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 Internal Revenue Code of 1986, 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 at 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. 

  
 19 

 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 make money payments, that party shall give to all other parties prompt written notice of the force majeure
with reasonably lull particulars concerning it, thereupon, the obligations of the party giving the notice, so far as they are affected by the force majeure, shall be suspending during, but no longer than, the continuance of the force majeure. 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. 
 The tern “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, lightning, fire, storm, flood, 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. 

ARTICLE XII. 
 NOTICES

 All notices authorized or required between the parties and required by any of the provisions of this agreement, unless otherwise
specifically provided, shall be given in writing by U.S. mail or overnight courier or telegram, postage or charges prepaid, or by facsimile, or telecopier and addressed to the parties to whom the notice is given at the addresses listed on Exhibit
“A”. The originating notice given under any provision hereof shall be deemed given only when received by the party to whom such notice is directed, and the time for such party to give any notice in response thereto shall run from the date
the originating notice is received. The second or any responsive notice shall be deemed given when deposited in the US mail or overnight courier or with the telegraph company, with postage or charges prepaid, or sent by facsimile, or telecopier.
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. 

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 he construed as having 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. 
 ☐ 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. 

  
 20 

 ☐ 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 production of oil and/or gas in paying quantities, this agreement shall continue in force so long as any such well or wells produce, or are capable of production, and
for an additional period of ninety (90) days from cessation of all production: provided, however, if, prior to the expiration of such additional period, one or more of the parties hereto are engaged in drilling, reworking, deepening, plugging
back, testing or attempting to 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 VIA., or any subsequent well drilled hereunder, results in a dry hole, and no other well is producing, or capable of producing oil and/or gas from the Contract Area, this agreement shall terminate unless
drilling. deepening, plugging hack or reworking operations are commenced within ninety (90) days from the date of abandonment of said well. 

It is agreed, however, that the termination of this agreement shall not relieve any party hereto from any liability which has accrued or
attached prior to the date of such termination. 
 ARTICLE XIV. 

COMPLIANCE WITH LAWS AND REGULATIONS 

A. Laws, Regulations and Orders: 
 This
agreement shall be subject to the conservation 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. 

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. 

With respect to 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 or predecessor or
successor agencies to the extent such interpretation or application was made in good faith. Each Non-Operator further agrees to reimburse Operator for any amounts applicable to such Non-Operator’s share of production that Operator may be required to refund, rebate or 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. 

  
 21 

 Non-Operators authorize Operator to prepare and submit
such documents as may be required to be submitted to the purchaser of any crude oil told hereunder or to any other person or entity pursuant to the requirements of the “Crude Oil Windfall Profit Tax Act of 1980”, as same may be amended
from time to time (“Act”), and any valid regulations or rules which may be issued by the Treasury Department from time to time pursuant to said Act. Each party hereto agrees to furnish any and all certifications or other information which
is required to be furnished by said Act in a timely manner and in sufficient detail to permit compliance with said Act. 
 ARTICLE XV.

 OTHER PROVISIONS 
 A. Non-Operator’s Consent or Non-Consent of the Initial Well as defined in Article VI.A.: 

The parties acknowledge that: (i) the Effective Date of this agreement is
            ; (ii) according to the Strategic Online Natural Resources Information System (“SONRIS”) the Initial Well was spud
on             ; and (iii) Operator notified all Non-operators of the potential well in accordance with Louisiana RS 30:10 (the “Pre-Agreement Notice”). 
 From and after the Effective Date, this agreement will govern and
control the relationship of the parties: 
 (i) with respect to all operations in the Contract Area, RS to each party which timely elected to
participate in the Initial Well pursuant to the Pre-Agreement Notice; and 
 (ii) with respect to all
operations in the Contract Area other than the Initial Well, as to each party which did not elect to participate in the Initial Well (a “Non-Electing Party”). Each
Non-Electing Party will be subject to RS 30:10 with respect to the Initial Well until the Initial Well has paid out (including the risk fee) in accordance with RS 30:10. 

(iii) notwithstanding anything contained in this agreement to the contrary, each Non-Electing Party
shall continue to be subject to La. R.S. 30:10, in lieu of this agreement, with respect to the initial Well until the Initial Well has paid out (including the risk fee) in accordance with La. R.S. 30:10, at which point such Non-Electing Party’s interest in the Initial Well shall be subject to this agreement. For so long as each Non-Electing Party is subject to the provisions of La. R.S.
30:10, the parties acknowledge and agree that, without limitation, each respective Non-Electing Party shall be responsible for paying its own royalties and complying with all other contractual obligations in
accordance with La. R.S. 30:10. 
 Each Non-Electing Party will be denoted as such on Exhibit A to
this agreement. 

  
 22 

 B. Conflicts 

Notwithstanding anything herein contained to the contrary, it is understood and agreed that if there is any conflict between any part of or all
of the terms and provisions of Article XV and any other terms and provisions of this agreement, the terms and provisions of this Article XV shall prevail and control. 

C. Vertical Wells 
 For purposes of this
agreement, a “vertical well” is defined as any well drilled, completed or recompleted other than a horizontal well. 
 D. Horizontal Wells

 Notwithstanding anything contained herein to the contrary, (i) the provisions of Article VII.D.1 Option
No. 1 shall apply to any horizontal well” (hereinafter defined) proposed hereunder and (ii) the provisions of Article VII.D.1. Option No 2 shall apply to all other wells proposed hereunder that are not
expressly proposed as “horizontal wells”. To be effective as a “horizontal well proposal”, such proposal must include an AFE and other accompanying documents that clearly stipulate that the well being proposed is a horizontal
well. For purposes of this agreement, a “horizontal well” is defined as a well drilled, completed or recompleted in a manner in which the horizontal component of the completion interval in the objective formation(s) exceeds the vertical
component of the completion interval in the objective formation and which horizontal component exceeds a minimum of one hundred feet (100’) in the objective formation(s). As to any possible conflicts that may arise during the completion phase
of a horizontal well, priority shall be given first to a lateral drain hole of the authorized depth, and then to objective formations in ascending order above the authorized depth, and then to objective formations in descending order below the
authorized depth. 
 E. Priority of Operations — Vertical Wells 

If at any time there is more than one operation proposed in connection with any well subject to this agreement and if the Consenting Parties do
not agree on the sequence of proposed operations, such proposed operations shall be conducted in the following sequence: 
 First - testing,
coring or logging 
 Second - completion attempts without plugging buck in ascending order from deepest to shallowest depths; 

Third - sidetracking in the order of least deviation from the original bottomhole location to the greatest deviation; 

Fourth - deepening of a well below the authorized depth in descending order from shallowest to deepest depths; 

Fifth - plugging back and completion attempts in ascending order from deepest to shallowest depths. 

  
 23 

 F. Priority of Operations — Horizontal Wells 

If at anytime there is more than one operation proposed in connection with any horizontal well subject to this agreement, then unless all
participating parties agree on the sequence of such operations, such proposals shall be undertaken in the following order of priority: 
  

	 	(1)	Completion of drilling operations on all proposed laterals; 

  

	 	(2)	Extension or deepening of any lateral; 

  

	 	(3)	Kick out and drill an additional lateral in the same formation; 

  

	 	(4)	Attempt a completion in a lateral, including testing and logging; 

  

	 	(5)	Plug back the well to another formation in ascending order; 

  

	 	(6)	Abandon the well pursuant to Article VI.E. 

 It is provided, however, that if at the time said
participating parties are considering any of the above operations the hole is in such a condition that a reasonably prudent operator would not conduct an operation in the sequence above provided for fear of placing the hole in jeopardy or losing the
same prior to completing the well in the objective depth or objective formation, such operation shall not be given the priority hereinabove set forth. 

G. Deeper Drilling 
 In the event any
Consenting Party desires to drill or deepen a Non-Consent well to a depth below the initial proposed objective, such party shall give notice thereof, complying with the requirements of Article VI.B.1., to all
parties (including Non-Consenting Parties). Thereupon, Article VI.B. shall apply and all parties receiving such notice shall have the right to participate or not participate in the drilling or deepening of
such well pursuant to said Article VI.B. in the event, however, any Non-Consenting Party elects to participate in the deeper drilling operation, such Non-Consenting
Party shall pay or make reimbursement (as the case may be) of the following costs and expenses: 
 1. If the proposal to drill deeper is
made prior to the completion or proposed completion of such Non-Consent well as a dry hole or prior to completion of such well as a commercial well, such Non-Consenting
Party shall pay (or reimburse Consenting Parties for, as the case may be) that share of costs and expenses incurred in drilling said well from the surface to total depth, as deepened or proposed to be deepened, which
Non-Consenting Party would have paid if said well had initially been proposed to be drilled to said depth and Non-Consenting Party had agreed to participate therein:
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 drill deeper than the initial proposed objective shall be for the sole account of
Consenting Parties, and 
 2. If the proposal is made for a Non-Consent well that has been
previously completed as a commercial well but is no longer producing in paying quantities, such Non-Consenting Party shall, in addition to paying all costs of
re-entering said well and deepening the same below its total depth, also reimburse Consenting Parties for any unrecovered costs to drill, complete and equip such well. 

  
 24 

 The foregoing shall not imply a right of any Consenting Party to propose any deeper drilling
operation for a Non-Consent well prior to completion of the drilling of such well to casing point for its initial proposed objective without the consent of all other Consenting Parties. 

The provisions of this Article XV.G. shall not apply to the takeover of it well by Non-Consenting
Parties in the event all Consenting Parties elect to permanently plug and abandon the same, but such right of Non-Consenting Parties shall be governed by Article VI.E.3. 

H. Sidetracking 
 Notwithstanding the
provisions of Article VI.B(4), “Sidetracking”, such 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 arc conducted in a horizontal or multi-lateral well shall be considered as included in the original proposed drilling operations. 

I. Parties to Operations 
 Notwithstanding
anything to the contrary in Article VI.B.2. or Article VII.D.2., the share of production from a well which Non-Consenting Parties shall be deemed to have relinquished to Consenting Parties in any reworking,
deepening, plugging back or completing of a well (as such terms are defined and used in Article VI.B.2. and Article VII.D.2.) shall be the Non-Consenting Parties’ share of production only from the
interval or intervals of the formation or formations from which production is obtained or increased as a result of the operations in which the Non-Consenting Parties did not participate. In the event a
subsequent operation is proposed for such well by one or more Consenting Parties prior to recovery of all costs and penalties recoverable from the relinquished interest of Nott-Consenting Party in said interval or formation, Non-Consenting Party shall be entitled to participate therein to the extent of its interest prior to relinquishment. 

Only a party that participated in the Non-Consent well shall have the right to propose a deepening or
sidetracking operation for such well, but all parties (including parties which did not participate in such well) shall be entitled to receive notices and shall have the right to participate pursuant to Article VI.B. in such sidetracking or deepening
operations. However, those parties that did not participate in the Non-Consent well shall reimburse the Consenting Parties in accordance with Article VI.B.4. in the event of a sidetracking operation and in
accordance with Article XV.G. in the event of a deepening operation. 
 J. Miscellaneous Costs 

The following expenses shall be a direct charge, borne by the Joint Account as provided in Exhibit “C’’, and shall not be
included as administrative overhead as set forth in Part III of Exhibit “C”. 
 1. All reasonable costs incurred by Operator, and
necessary in its sole judgment, for outside engineers, geologists, consultants, landmen, attorney and other third party services in obtaining spacing, pooling or other orders or rulings from state regulatory bodies or courts regarding the Contract
Area. 

  
 25 

 2. All reasonable costs incurred by Operator for outside engineers, geologists, consultants,
landmen, attorney and oilier third party services in complying with the Natural Gas Policy Act of 1978, or in complying with federal, state or local law for the obtaining and monitoring of any well classifications required in the Natural Gas Policy
Act of 1978; or in complying with any laws administered by, or any rules or regulations promulgated by, through, or under the United States Department of Energy regarding the Contract Area. 

K. Multiple Billing 
 In no event shall
Operator be required to bill more than three co-owners of any Non-Operator for the entire interest credited to Non-Operator on
Exhibit “A”. if any Non-Operator to this Agreement disposes of any part or all of the interest credited to it on Exhibit “A’’, hereinafter referred to as “Selling Party”,
such Selling Party shall be solely responsible for billing its assignee or assignees and shall remain primarily liable to the other Parties for the interest or interests assigned until such time as Selling Party has (1) designated and qualified
the assignees to receive the billing for its interest, and (2) has furnished to Operator written notice of the conveyance and photocopy of the recorded assignments by which the transfer is made. 

L. Payments and Accounting 
 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. 

Notwithstanding any other provisions of this agreement, and without prejudice to any other rights of the Operator, when under an approved APE
an operation, on any well within the Contract Aim is proposed under the terms hereof, where the cost of such all operation is reasonably expected to be in excess of $100,000.00, Operator shall have the right to request and receive from each Non-Operator payment in advance, as provided in this Article XV. L. below, of its respective share of (i) the costs of any well to be drilled hereunder to which such
Non-Operator has consented, and (ii) the cost of any completion, reworking, recompletion, sidetracking, deepening, plugging back operation or any other operation hereunder to which such Non-Operator has consented (any such operation under clause (i) or (ii) being herein called a “Drilling Operation”). Such request for advance payment may be made on all
Non-Operators in writing and may be either mailed, hand-delivered or transmitted by facsimile machine. 

Any request by Operator for an advanced payment of a Drilling Operation, including any promoted well costs, shall be made no sooner than
thirty (30) days prior to such time as Operator in good faith reasonably expects to actually commence such Drilling Operation. A Non-Operator receiving a request for advance payment will within twenty
(20) days of the receipt of such request, pay to Operator in cash the fill amount of such request. Operator will credit the amount to the Non-Operator’s account for the payment of such Non-Operator’s share of costs of such Drilling Operation and, following the end of each month, Operator will charge such account with such Non-Operator’s share of
actual costs incurred during such month. 

  
 26 

 In the event that a Drilling Operation is not conducted within the ninety (90) day time
period, or as applicable the one-hundred twenty (120) day period, all as provided in Article VI.B.1., Operator shall immediately refund to Non-Operator any advanced
payment made by Non-Operator, it being understood that such refund shall be made no later than thirty (30) days after the expiration of said applicable period. Payment of an advance will not relieve a Non-Operator of the obligation to pay such Non-Operator’s share of the actual cost of a Drilling Operation and, when the actual costs have been determined, Operator will
adjust the accounts of the parties by refunding any net amounts due or invoicing the parties far additional sums owing, which additional sums shall be paid in accordance with the Accounting Procedure. 

In the event a Non-Operator to which a request for advance payment was made does not, within the time
and manner above provided, fully satisfy the request for advance payment as provided in this Article XV.L, then Operator may, in the Operator’s sole discretion at any time prior to actual payment, exercise any one or more of the
following rights and remedies: (a) if the advance was requested for any Drilling Operation, Operator may notify such Non-Operator that such Non-Operator is deemed
to have relinquished its interest in the well to which the Drilling Operation relates and to have elected to go non-consent on such Drilling Operation under Article VI.B.2.; or (b) exercise any and all
other rights and remedies available to the Operator under this agreement and applicable law. Each of the parties to this agreement hereby agrees to execute and deliver to the other parties hereto any and all documents, agreements and acknowledgments
necessary to evidence any actions taken by the Operator pursuant to the provisions of this Article XV.L. All remedies herein provided are cumulative and not alternative, and no failure to exercise or delay in exercising any such right will operate
as a waiver thereof. 
 M. Distribution of Revenue and Royalties 

In the event any purchaser of production from the Contract Area remits all of the proceeds therefore to the Operator for distribution,
Operator, notwithstanding anything to the contrary contained herein, and without prejudice to any other rights possessed by Operator, at its sole discretion, may receive the proceeds from all oil and/or gas production attributable to any Non-Operator’s ownership in the Contract Area and distribute those proceeds to said Non-Operator during the next calendar month ensuing following receipt of the proceeds
by Operator from the purchaser. Notwithstanding anything to the contrary herein, with regard to the payment of royalties and other burdens, Operator will remit to Non-Operator its full share of revenue
(8/8ths) and it shall be the sole responsibility of Non-Operator to account to its royalty owners and other interest owners who burden Non-Operator’s interest. Non-Operator hereby releases Operator from any obligation to make such payments and agrees to indemnify, hold harmless and defend Operator from and against any and all claims, demands, or suits (including those
seeking attorney fees and costs) arising out the payment or non-payment of Non-Operator’s royalties or other burdens. 

N. Well Cost Adjustments 
 If the parties
drill a well, either jointly or separately, and said well is completed in a zone or formation in which the working interests differ from those of the original objective, or the ownership in the wellbore differs from the interests on which Well Costs
were AFE’d or paid by the Parties, the Parties shall make a “Well Cost Adjustment” to reflect the actual working interest ownership of the Parties. 

  
 27 

 Well Cost Adjustments shall be made only in the event of a completion of a well which is capable
of producing oil and/or gas in paying quantities, and such adjustments shall be on a depreciated or non-depreciated basis as follows: 

1. A non-depreciated Well Cost Adjustment shall be made on the basis of actual total costs incurred in
the initial drilling and equipping of the well down to the base of the completed zone or formation should any of the following events occur: 

a should any single well subject to the terms of this Agreement be initially dry in the objective zone or formation but be subsequently
completed in a zone or formation in which the working interests differ from those of the original objective; 
 b. should the parties
disagree on the ownership of the original objective zone or formation and the information learned after the well has been drilled indicates that the working interests in such objective zone or formation differ from those of the Participating
Parties; or 
 c. should an unexpected zone or formation be found in the well and such zone or formation becomes the initial zone or
formation completed. 
 2. A depreciated Well Cost Adjustment shall be made if any single well subject to the terms of this agreement is
initially completed and produced in one or more zone or formations (as intended by both Parties), but is subsequently recompleted in a zone or formation in which the working interests differ from those of the zone or formation which produced
immediately prior to the new completion. The adjustment shall be made in accordance with the following: the total of the original well costs to the base of the newly completed zone or formation plus one hundred feet (100’) shall be depreciated
in that proportion to which the amount of oil and/or gas produced by the well from any zone or formation prior to the date of such new completion, bears to the total of the reserves obtained by adding the amount so produced and the estimated
recoverable reserves (as agreed upon by the parties) to be produced from the newly completed zone or formation, provided, however, that the recoverable controlled tangible investment shall not be depreciated in value below a condition of ten percent
(10%) of the original cost prevailing on the date of the now completion, as determined in accordance with the COPAS guidelines contained in Exhibit “C” to the Operating Agreement. 

The party whose working interest, as a result of a Well Cost Adjustment is increased by the new ownership or new completion shall owe to the
party whose interest has decreased, an amount espial to the increased portion of its working interest multiplied by the total depreciated or non-depreciated value of the particular well,
as the case may be. Thereafter, the well and associated equipment shall be owned by the party(s) in proportion to its respective working interest in the new completion. 

  
 28 

 O. Standard of Conduct of Operations 

The Operator of the Contract Area 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 Operating Agreement. In its performance of services hereunder for the Non-Operator(s), Operator shall be an independent contractor not subject to the control or
direction of the Non-Operators except as expressly set forth 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 vis-a-vis any third party. Operator shall conduct its activities under this
agreement as a reasonably prudent Operator, i.e., in a good and workmanlike manner, with due diligence and dispatch, in accordance with good oilfield practice, in compliance with the applicable lease(s) and agreements and in compliance with the
applicable law and regulation. It shall have no liability as Operator to the other Parties for losses sustained or liabilities incurred, except such as may result from gross negligence or willful misconduct. 

P. Bankruptcy 
 If, following the granting
of relief under the Bankruptcy Code to any party hereto as debtor thereunder, this agreement should be held to be an executory contract under the Bankruptcy Code, then any remaining party shall be entitled to a determination by debtor or any trustee
for debtor within thirty (30) days from the date an order for relief is entered under the Bankruptcy Code as to the rejection or assumption of this agreement. If the debtor or trustee determines to assume this agreement, the party seeking
determination shall be entitled to adequate assurances as to the future performance of debtor’s obligations hereunder and the protection of the interests of all parties. The debtor shall satisfy its obligation to provide adequate assurances by
either advancing payments or depositing the debtor’s proportionate share of expenses in escrow. 
 Q. Mutuality 

The parties hereto acknowledge and declare that this agreement is the result of extensive negotiations between themselves. Accordingly, in the
event of any ambiguity in this agreement, there shall be no presumption that this instrument was prepared solely by either party hereto. 
 R. Memorandum
of Operating Agreement 
 Parties agree to execute a memorandum of this agreement simultaneously with the execution of this agreement
which shall be recorded by Operator in each parish in which lands comprising all or any part of the Contract Area are situated. Operator will prepare the memorandum of this agreement and circulate same to the
Non-Operator for execution. Upon recording, Operator will provide recordation information to Non-Operator for its records. The form of said memorandum, which is attached
as Exhibit “F” hereto, shall include a reference to the pertinent substantive provisions of this agreement including the Gas Balancing Agreement. 

S. Headings 
 All headings in this
agreement are for reference purposes only and have no binding effect on the terms, conditions or provisions of this agreement. 

  
 29 

 T. News Releases 

Any party hereto or any related party desiring to issue a news release concerning operations conducted within the Contract Area shall provide
the other party(ies) that have it working interest greater than 25% with copies of the proposed release and no such news release shall be issued without first obtaining the written consent of those parties with a working interest greater than 25%,
which consent not be unreasonably be withheld. Failure of a party to make written election within twenty-four (24) hours will be deemed to be consent to the issue of the news release. Notwithstanding the immediately preceding sentences, no
prior consent shall be required for any news release required by law and/or the Securities and Exchange Commission. The only exception to the foregoing shall be that in the event of an emergency involving extensive property damage, operations
failure, loss of human life or other clear emergency, the Operator is authorized to furnish such minimum, strictly factual information as shall be necessary to satisfy the legitimate public interest on the part of the press and duly constituted
authorities is time does not permit obtaining of prior approval by the other parties hereto. The Operator shall promptly advise the other parties thereto of the information so furnished. Notwithstanding the foregoing, no party may be named in a
press release without that party’s express written consent. 
 U. Over-Expenditure of AFE 

In the event expenditures against an approved AFE exceed, or in Operator’s reasonable judgment, arc likely to exceed, by twenty percent
(20%) or more of the total AFE prior to finishing the approved operation (“AFE Excess Cost Overrun”), then Operator shall promptly furnish to each Non-Operator a summary description as to the cause
of the cost overrun and propose the continuation of the operation with a supplemental AFE. Each Non-Operator who wishes to consent to the continuation of the operation shall notify Operator of such election by
executing the supplemental AFE and returning it to Operator within forty-eight (48) hours following receipt of such notice. (FAILURE OF ANY NON-OPERATOR TO NOTIFY OPERATOR WITHIN SUCH TIME PERIOD SHALL
BE DEEMED AN ELECTION APPROVING THE CONTINUATION OF THE OPERATION.) Operator shall in turn notify each Non-Operator of the total interest of the Non-Operators
approving the continuation of the operation and shall provide Operators recommendation as to whether the consenting Non-Operators should continue with the operation. Each consenting Non-Operator shall, within twenty-four (24) hours after receipt of such notice, notify Operator of its election to (a) limit its participation to such Party’s original interest or (b) assume its
proportionate share of the non-consent interest. Failure to notify Operator within such time period shall be deemed an election under (a), The Operator, at its election, may withdraw such continuation proposal
and supplemental AFE if there is insufficient participation and shall promptly notify all each Non-Operator of such decision in which event the operation shall be terminated and each Non-Operator shall be responsible for its proportionate share of the costs and expenses incurred to date, including the cost of plugging and abandonment. Whenever such a proposal shall be made, any Non-Operator non-consenting to the continuation of the operation shall be subject to the applicable non-consent penalty only from that
point in time forward, or only as to the depths below total depth attained in the well on which the re-proposal is being made at the time it is made. Supplemental AFEs shall also be subject to the AFE Excess
Cost Overrun limitation and shall require additional proposals and supplementation whenever the costs of any continuation 

  
 30 

 
operation exceeds APE Excess Cost Overrun limitation, and shall be subject to the applicable non-consent penalty. (FAILURE OF OPERATOR TO PROMPTLY
NOTIFY ANY NON-OPERATOR OF THE OCCURRENCE OF AFE EXCESS COST OVERRUN AS PROVIDED HEREIN ABOVE, SHALL DEFER NON-OPERATOR’S RIGHT TO MAKE A NON-CONSENT ELECTION UNTIL IT RECEIVES SUCH SUPPLEMENT AFE, WHICH ELECTION SHALL BE RETROACTIVE TO THE DATE THE NOTICE SHOULD HAVE BEEN GIVEN.) Excessive costs occasioned by the explosion, fire, flood, blowout,
sidetracking in the lateral portion of a horizontal well or other sudden emergency, whether of the same or different nature, shall not be subject to the provisions of Article XV.W. 

V. Successors and Assigns 
 Each party
hereto covenants and agrees for itself, its successors and assigns, that any sale, assignment sublease, mortgage, pledge or other agreement affecting the leases and lands subject to this instrument (whether of an operating or non-operating interest or a mortgage, pledge or other security interest) will be made and accepted subject to this instrument. Should a party assign all or part at its interest in the Contract Area subject to this
agreement, at such time as the selling party has paid all of its share of joint interest billing costs in accordance with Exhibit “C” current to the effective date of such sale, it shall be deemed that the selling party shall be released
from any responsibility for costs thereafter incurred relative to the undivided interest sold. Provided however, to the extent a party retains an undivided interest such party shall continue to be bound by all of the terms and conditions of this
agreement applicable to the retained undivided interest. It is further agreed that the obligations set forth in this paragraph and in the balance of this agreement are covenants running with the lands described in the oil and gas leases in the
Contract Area. Therefore, upon sale, sub tease or assignment of the leases and lands subject to this agreement, as of the effective date of such sale, sub lease or assignment of the oil and gas leases in the Contract Area, the party acquiring such
rights subject to this agreement shall thereafter assume and be responsible for all of the rights and obligations of the party selling, sub leasing or assigning as to the undivided interest acquired by a party. The party acquiring the interest or
security shall be furnished a copy of this agreement and any amendments thereto, and shall expressly agree to be bound by all of its terms and provisions. It is provided, however, that a mortgagee, pledge or person holding only a security interest
shall not incur any obligations under this agreement although its rights may be affected or limited hereby. It is further agreed in the event of the foreclosure of the mortgage or security interest, any sale will be expressly made and accepted
subject to all of the terms and provisions of this Operating Agreement. Any party hereto (and any successor of a party hereto) who executed any instrument in favor of any party without complying with the provisions of this paragraph shall indemnify,
defend and hold the other Parties hereto harmless for and against any and all claims or causes of action by any person whomsoever or for any losses sustained as a result of the failure of such party to comply with these provisions. This indemnity
shall also include reimbursement for reasonable attorney’s fees incurred in connection with the assertion of the rights herein granted such Parties. 

  
 31 

 W. Non-Payment 

Subject to Article XV.L. hereof, if any party (including the Operator) fails to pay its share of any cost, including any advance which it is
obligated to make under Article XV.L. or any other provision of this Agreement, within the period required for such payment, then, in addition to the other remedies in this Agreement, the Operator (or any
Non-Operator if the Operator is the party in default) may pursue any of the following remedies: 
 1.
Suspension of Rights. Operator (or the Non-Operators if Operator is the party in default) may deliver to the party in default by certified mail, return receipt requested a Notice of Default, which shall
specify the default, and specify that 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 Agreement. If such default is not cured within
thirty (30) days after the receipt by the defaulting party of such Notice of Default, Operator (or the Non-Operator if Operator is the Party in default) may suspend any or all of the rights of the
defaulting party granted by this Agreement until the default is cured, without prejudice to the right of any non-defaulting party to continue to enforce the obligations of the defaulting party theretofore
accrued or thereafter accruing under this Agreement. If Operator is the party in default, the Non-operators shall in addition have the right, by vote of Non-Operators
owning a majority in interest in tile 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 operations conducted hereunder during the period of such default, and the right to elect to participate in an
operation proposed under Article VI.B. of this agreement. 
 2. Suit for Damages. Operator (or the
Non-Operators if Operator is the party in default) may sue to collect the amounts in default together with all documented, direct damages suffered by the non-defaulting
parties as a result of the default, plus interest accruing on the amounts recovered from the date of default until the date of collection at the rate specified in Section 1.(3) of the Accounting Procedure attached to this Operating Agreement
as Exhibit “C”. 
 3. Deemed Non-Consent. Operator (or any Non-Operator if the Operator is the party in default) may deliver a written Notice of Non-Consent Election by certified mail, return receipt requested or by overnight delivery
with tracking confirmation, 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 of a new well on 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 non-paying 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 VIII. or Article VII.D.I. (Option No. 2) 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 party may not elect to sue for the unpaid amount pursuant to Article
XV.D.2. Until the delivery of such notice of Non-Consent Election to the non-paying party, such party shall have the right to cure its default by paying the unpaid
billing plus interest at the rate set forth in Section 1.(3) of the attached Exhibit C Accounting Procedure plus any costs or damages incurred by the non-defaulting parties as a result of the default. Any
interest relinquished pursuant to this Article XV.D. shall be offered by Operator (or by the Non-Operators if Operator is the defaulting party) to the non-defaulting
parties in proportion to their interests. 

  
 32 

 4. Good Faith Disputes. In the event a party disputes in good faith the existence of a
default on his part that is the subject of a Notice of Default, such party may avoid the imposition of the remedies for such default contained in this agreement by paying the disputed amount into an account at a bank requiring the signatures of both
such party and the Operator (or, if the Operator is the party in default, a Non-Operator designated by the Non-Operators) in order to release such funds. Such Funds
shall be released to the party entitled thereto upon the resolution of the issue raised by the objecting party. 
 5. Costs and
Attorney’s Fees. In the event any party shall ever be required to bring legal proceedings in order to collect any sums due from any other party or any to enforce any other right under this agreement, then the prevailing party in such action
shall also 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. 

6. Financing Statement. Upon request of Operator, or any Non-Operator. the Non-Operators agree to execute a recordable financing statement sufficient and appropriate under the applicable state uniform codes or the Uniform Commercial Code, as applicable, to perfect a security interest by
and between the parties hereto to the same degree and covering the same properties and rights as set forth in Article VII.B. above. 
 X. Disposal of
Surplus Materials 
 Operator may dispose of any items of surplus or obsolete materials or equipment if the current price of new
materials or equipment similar thereto is less than Fifty Thousand Dollars ($50,000.00). 
 Y. Counterpart Ratification 

Failure of any party hereto to execute this Agreement shall not render it ineffective as to any party hereto which does execute same. If
counterparts of this Agreement are executed, the signatures and acknowledgements of the parties, as affixed thereto, may be combined by Operator in, and treated and given effective for all purposes as, a single instrument. This agreement also may be
ratified by separate instrument referring hereto, each of which shall have the affect of the original agreement and of adopting by reference all of the provisions herein contained. 

Z. Holidays 
 The word
“holidays” when used herein is defined as a State holiday observed by the Governing State’s Government and its agencies. 
 A.A. Use of
Affiliates 
 Operator has the right to provide materials and services, either directly or indirectly, or through Operator or an
affiliate of Operator, so long as the rates charged by Operator, or any such affiliate, does not exceed the current prevailing rates in the area for comparable services and/or equipment. 

  
 33 

 B.B. Acknowledgement of Operations outside the Contract Area 

Operator shall supply to Non-Operators, within thirty (30) days of such operation, a copy of the
Initial Well or subsequent well permit plat for any and all wells within the Contract Area for which the well bore traverses outside the Contract Area. 

  
 34 

 ARTICLE XVI. 

MISCELLANEOUS 
 This
agreement shall be binding upon and shall inure to the benefit of the parties hereto and to their respective heirs, devisees, legal representatives, successors and assigns. 

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

IN WITNESS WHEREOF, this agreement shall be effective as
of                    day of
                                    ,
(year)                        . 
  

							
	 WITNESSES:
	  		  	 OPERATOR:

				
		  		  	 By:
	  	  

	  

Signature
	  		  		  	
				
		  		  	 Name:
	  	  

				
	  

Printed Name
	  		  	 Its:
	  	  

				
	  

Signature
	  		  		  	
				
	  

Printed Name
	  		  		  	
			
	 WITNESSES:
	  		  	 NON-OPERATOR:

				
	  
	  		  	By:	  	  

	 Signature
	  		  		  	
		  		  	Name:	  	  

				
	  
	  		  		  	
	Printed Name	  		  	Its:	  	  

				
	  
	  		  		  	
	 Signature
	  		  		  	
				
	  
	  		  		  	
	Printed Name	  		  		  	

  
 35 

 Acknowledgements 

State of
                         x 

                          
                      ss. 
 County of
                         x 

BEFORE ME, the undersigned authority, on this day personally appeared
                , as Attorney-in-Fact,
of             known to me to be the person whose name is subscribed to the foregoing instrument, and acknowledged to me that he executed the same for purposes and consideration therein
expressed, individually and as the act and deed of said limited partnership and in the capacity therein stated. 
 GIVEN UNDER MY HAND AND
SEAL OF OFFICE this     day of     2012. 
 MY COMMISSION EXPIRES: 

 
  

State of
                         x 

                          
                      ss. 
 County of
                         x 
  

BEFORE ME, the undersigned authority, on this day personally appeared
                , as Attorney- in-Fact, of             known to me to
be the person whose name is subscribed to the foregoing instrument, and acknowledged to me that he executed the same for purposes and consideration therein expressed, individually and as the act and deed of said limited partnership and in the
capacity therein stated. 
 GIVEN UNDER MY HAND AND SEAL OF OFFICE this     day of     2012. 

MY COMMISSION EXPIRES: 
  

 

  
 36 

 EXHIBIT “A” 

Attached hereto and made a part of that certain 

Joint Operating Agreement dated            , 20    , by and 

between SWEPT LP, as Operator and Non-Operator(s). 

DESCRIPTION OF LANDS SUBJECT TO THIS AGREEMENT: 

Section         , Township     North, Range        
West,         Parish, Louisiana within the surface boundaries of the unit defined in the Louisiana Office of Conservation Order No.     (HARA     ),
    Field. 
 RESTRICTIONS AS TO DEPTH, FORMATION(S) AND/OR SUBSTANCE(S): 

Limited as to formation from the base of the Cotton Valley Formation to the base of the Haynesville Formation, and as may be further limited by the provisions
of the leases subject to this agreement. 
 WORKING INTERESTS & ADDRESSES OF THE PARTIES TO THE CONTRACT AREA* 

 
  

					
	 	  	WORKING INTEREST	 
	 SWEPI LP
	  	 		% 
		  	  
	  
	 
	 150 N. Dairy Ashford

Houston, Texas 77079

Attn: John Bentz

Ph: 281.544.3552

Fax: 281.544.5022

Email: John.Bentz@shell.com
	  			
	 Encana Oil & Gas USA, Inc.
	  	 		% 
		  	  
	  
	 
	 5851 Legacy Circle

Plano, TX 75024

Attn: Duane Gee

Ph: 469.304.6328

Fax:             

Email: Duane.Gee@encana.com
	  			
	 3rd Party Interests
	  	 		% 
		  	  
	  
	 
	 TOTAL
	  	 	100.000000	% 

  

	*	Working Interests subject to record title verification of leasehold interests and final unit survey 

 OIL
AND GAS LEASES AND INTEREST SUBJECT TO THIS AGREEMENT: 
 See attached Lease Schedule(s) for continuation of Exhibit “A”. 

 EXHIBIT “A” 

Attached hereto and made a part of that certain Joint Operating Agreement dated
                , 20    , by and between , as Operator and Non-Operator(s). 

 

																	
	 	  	 	  	 Contract Area:

Oil & Gas Lease Schedule
	  	 	  	 	  	 	  	 	  	 	  	 
	 Shell Lease No.
	  	Lessor	  	 Original Lease
	  	Effective Date	  	Parish	  	State	  	Book	  	Page	  	Entry No.

  

 EXHIBIT “B” 

Attached hereto and made a part of that certain 

Joint Operating Agreement dated     , 20    , by and 

between         , as Operator and Non-Operator(s). 

Bath Form Louisiana Spec. 14-BR1-2A-NL
Paid tip R2/99 
 OIL, GAS AND MINERAL LEASE 

THIS AGREEMENT made this
                     day of
                    ,                    
between 
 as LESSOR, 
 whose address for any purpose herein
is:                                       
                                         
                                         
         
 and
                                        
                                         
                                         
                                         
          Lessee, 
 whose address is:
                                        
                                         
                                         
                                         
    
 WITNESSETH 
 1. Lessor
in consideration of One Hundred Dollars and Other Valuable Considerations ($100.00 & OVC), In hand paid, of the royalties herein provided, and of the agreement of Lessee herein contained, hereby grants, leases and lets unto Lessee, the exclusive
right to enter upon and use the land hereinafter described for the exploration for and production of oil, gas, sulphur and all other minerals together with the use of the surface of the land for all purposes Incident to the exploration for and
production, ownership, possession and transportation of said minerals (either from said land or acreage pooled therewith), and the right to dispose of salt water, with the right of ingress and egress to and from said lands at all times for such
purposes, including for operations hereunder or in connection with similar operations on adjoining land: the and to which this lease applies and which is affected hereby being situated in     , and described as follows, to-wit: 
 This lease shall also extend and apply to any interest therein which Lessor may hereafter
acquire, including, but not limited to, outstanding mineral rights acquired by reversion, prescription or otherwise, and includes battures, accretions, roads, highways, easements,
right-of-ways and all land, if any, contiguous or adjacent to, or adjoining the land particularly described above. Lessor agrees to execute any supplemental Instrument
requested by Lessee for a more complete or accurate description of said land. For the purposes of determining the amount of bonus and the shut-in royalty payment hereunder, said land shall be deemed to
contained     acres, whether actually containing more or less, and the above recital of acreage in any tract shall be deemed to be the true acreage thereof. 

2. Subject to the other provisions herein contained, this lease shall be for a period of years from the effective date hereof (called
“primary term”) and long thereafter as (1) oil, gas, sulphur or other mineral is produced from said land hereunder or from land pooled therewith; or (2) it is maintained in force in any other manner herein provided. 

3. For the consideration hereinabove recited, this lease shall remain in full force and effect during the primary term, without any additional
payment and without Lessee being required to conduct any operations on the land (either before or after the discovery of minerals), except to drill such wells as might be necessary to protect the land from drainage, as hereinafter provided. 

 4. The royalties to be paid by Lessee are: (a) on oil, and other hydrocarbons which are
produced at the well in liquid form by ordinary production methods, one-eighth of that produced and saved from said land, same to be delivered at the wells or to the credit of Lessor in the pipe line to which
the wells may be connected; Lessor’s interest in either case to bear its proportion of any expenses for treating the oil to make it marketable as crude; Lessee may from time to time purchase any royalty oil or other liquid hydrocarbons in its
possession, paying the market price therefor prevailing for the field where produced on the date of purchase; (b) on gas, including casinghead gas, or other gaseous substance produced from said land and sold or used off the premises or for the
extraction of gasoline or other products therefrom, the market value at the well of one-eighth of the gas so sold or used, provided that on gas sold at the wells the royalty shall be one-eighth of the amount realized from such sale; such gas, casinghead gas, residue gas, or gas of any other nature or description whatsoever, as may be disposed of for no consideration to Lessee, either through
unavoidable waste or leakage, or in order to recover oil or other liquid hydrocarbons, or returned to the ground, shalt not be deemed to have been sold or used either on or off the premises within the meaning of this paragraph 4 hereof, (c )
on all other minerals mined and marketed, one-eighth, either in kind or value at the well or mine, at Lessee’s election except that on sulphur the royalty shall be one dollar ($ 1.00) per long ton. 

5. If Lessee during or after the primary term should drill a well capable of producing gas or gaseous substances in paying quantities, (or
which although previously produced Lessee is unable to continue to produce) and should Lessee be unable to operate said well because of lack of market or marketing facilities or governmental restrictions, then Lessee’s rights may be maintained
beyond or after the primary term without production of minerals or further drilling operations by paying Lessor as royalty a sum equal to one dollar ($1.00) per acre of land covered hereby per year, the first payment being due, if said well should
be completed or shut-in after the primary term, within ninety (90) days after the completion of such well or the cessation of production and such payment will extend Lessee’s rights for one year from
the date of such completion or cessation. If such a well should be completed during the primary term, the first payment, if made by Lessee, shall be due within 90 days after such well is shut-in, or before the
expiration date of the primary term herein fixed, whichever is the later date. Thereafter Lessee’s rights may be continued from year to year by making annual payments in the amount stated on or before the anniversary date beginning with the
date of completion of said well (if completed after the primary term) or the end of the primary term (if completed prior thereto) as the case may be; each of such payments to extend Lessees rights for one year. The annual payments herein provided
for may be deposited to Lessors credit in the     Bank of    , or paid direct to Lessor at the above address, which bank/address shall be and remain Lessor’s agent/address for such
purpose regardless of any change or changes in the ownership of the lend or mineral rights therein. The owners of the royalty as of the date of such payments shall be entitled thereto in proportion to their ownership of said royalty. The provisions
of this paragraph shall be recurring at all tunes during the life of this lease. Should any well producing gas or gaseous substances be completed on a drilling unit which includes any part of the land herein leased, the provisions of this paragraph
shall be subject to all other agreements herein contained allowing the pooling of the above described lands with other lands. 

  
 40 

 6. If within ninety (90) days prior to the end of the primary term, Lessee should complete
or abandon a well on the lands described above or on land pooled therewith, or if production previously secured should cease from any cause, this lease shall continue in force and effect for ninety (90) days from such completion or abandonment
or cessation of production. If at the expiration of the primary term or at the expiration of the ninety (90) day period provided for in the preceding sentence, oil, gas, sulphur or other mineral is not being produced on said land or on land
pooled therewith, but Lessee is then engaged in operations for drilling, completion or reworking thereon, or operations to achieve or restore production, or if production previously secured should cease from any cause after the expiration of the
primary term, this lease shall remain in force so long thereafter as Lessee either (a) is engaged in operations for drilling, completion or reworking, or operations to achieve or restore production, with no cessation between operations or
between such cessation of production and additional operations of more than ninety (90) consecutive days; or (b) Is producing oil, gas, sulphur or other mineral from said land hereunder or from land pooled therewith, if sulphur be
encountered on said premises or on land pooled therewith. this lease shall continue in force and effect so long as Lessee is engaged with due diligence in explorations for and/or erecting a plant for the production of sulphur and thereafter subject
to the foregoing provisions hereof so long as oil, gas, sulphur or other mineral is produced from said land hereunder or from land pooled therewith. 

7. Lessee is hereby granted the right as to all or any part of the land described herein, without Lessors joinder, to combine, poor or unitize
the acreage royalty or mineral interest covered by this lease, or any portion thereof, at any time during the life of this lease, with any other land, lease or leases, royalty or mineral interests in or under any other tract or tracts of land in the
vicinity thereof, whether owned by Lessee or some other person, or corporation so as to create, by the combination of such lands and leases, one or more operating units, as to any and all mineral horizons, provided that no one operating unit shall,
in the case of gas, including condensate, embrace more than six hundred forty (640) acres, and in the case of oil, including casinghead gas, embrace more than eighty (80) acres; and provided further, however, that if any spacing or other
rules and regulations of the State or Federal Commission, Agency, or regulatory body having or claiming jurisdiction has heretofore or shall at any time hereafter permit or prescribe a drilling or operating unit or spacing rule in the case of gas,
including condensate, greater than six hundred forty (640) acres, or in the case of oil or casinghead gas greater than eighty (80) acres, then the unit or units herein contemplated may have, or may be redesigned so as to have, as the case
may be, the same surface content as, but not more than, the unit or the acreage in the spacing rule so prescribed or permitted. However, it is further specifically understood and agreed, anything herein to the contrary notwithstanding, that the
Lessee shall have the right to, and the benefit of an acreage tolerance of ten per cent in excess of any drilling or operating unit authorized herein. The commencement of operations for the drilling of a well, or the completion of a well to
production of either oil, gas, casinghead gas, condensate or other minerals on any portion of an operating unit in which all or any part of the land described herein is embraced, or production of oil, gas, casinghead gas, condensate, or other
minerals therefrom shall have the same effect under the terms of this lease as if a well were commenced, completed or producing oil, gas, casinghead gas, condensate, or other minerals in paying quantities on the land embraced by this lease. Lessee
shall execute in writing and file for record in the records of the Parish in which the lands herein leased are located, an instrument identifying or describing the pooled acreage, or an instrument supplemental thereto redesignating same, as the case
may be. Either prior to the securing of production from any unit created under the authority hereinabove granted, or after cessation of production therefrom Lessee shall have the right to dissolve the

  
 41 

 
unit so created, without Lessor’s joinder or further consent, by executing in writing and placing of record in the Parish or Parishes in which the lands making up such unit may be located an
instrument identifying and dissolving such unit. The provisions hereof shall be construed as a covenant running with the land and shall inure to the benefit of and be binding upon the parties hereto, their heirs, representatives, successors and
assigns. In the event such operating unit or units is/are so created by Lessee, Lessor shall receive out of production or the proceeds from production from such operating unit or units or out of the shut-in
royally provided for above, such portion of the royalty or of the shut-in royalty specified herein as the number of acres (mineral acres) out of this lease placed in any such operating unit or units bears to
the total number of acres included in such operating unit or units. 
 8. If Lessor owns a less interest in the above described land than the
entire and undivided fee simple estate therein, then the payments herein provided shall be paid to Lessor only in the proportion which Lessors interest bears to the whole and undivided fee. 

9. Lessee shall have the exclusive right to explore the and herein described by geological, geophysical or other methods, whether similar to
those herein specified or not and whether now known or not, including the drilling of holes, use of torsion balance, seismograph explosions, magnetometer, or other geophysical or geological instruments, test or procedures, for the purpose of
securing geological and geophysical information. All Information obtained by Lessee as a result of such activity shall be the exclusive property of Lessee, and Lessee may disseminate or self such information without Lessor’s consent, in
exploring for, developing, producing and marketing oil, gas and other substances covered hereby on the leased premises or lands pooled or unitized therewith, in primary and/or enhanced recovery, Lessee shall have the right of ingress and egress
along with the right to conduct such operations on the leased premises, or on any adjacent or adjoining lands, as may be reasonably necessary for such purpose, including but not limited to the drilling of wells, construction and use of roads.
canals, pipelines, tanks, water wells, disposal wells, injection wells, pits, electric and telephone lines, power stations, and other facilities deemed necessary by Lessee to discover, produce, store, treat and/or transport oil, gas and other
substances Lessee shall have free use of oil, gas, casinghead gas, condensate, and water from said land, except water from Lessors wells, for all operations hereunder, including repressuring, pressure maintenance and recycling, and the royalty shall
be computed after deducting any so used. Lessee shall have the right at any time during or after the expiration of this lease to remove all property and fixtures placed by Lessee on said land, including the right to draw and remove all casing. When
required by Lessor, Lessee will bury all pipe lines below ordinary plow depth, and no well shall be drilled within two hundred feet of any residence or barn now on said land without Lessor’s consent. In the event a well or wells, producing oil,
gas, casinghead gas or condensate in paying quantities should be brought in on adjacent lands not owned by the Lessor and within one hundred fifty feet of and draining the leased premises, Lessee agrees to drill such offset well or wells as a
reasonably prudent operator would drill under the same or similar circumstances. 
 10. The rights of either party hereunder may be assigned
In whole or In part and the provisions hereof shall extend to the heirs, executors, administrators, successors and assigns, but no change or division in ownership of the land, or royalties, however accomplished shall operate to enlarge the
obligations or diminish the rights of Lessee. No such change or division in the ownership of the land, or royalties shall be binding upon Lessee for any purpose until 

  
 42 

 
such person acquiring any interest has furnished Lessee, at its principal place of business, with a certified copy of the instrument or instruments, constituting his chain of title from the
original Lessor, An assignment of this lease, in whole or in part, shall, to the extent of such assignment, relieve and discharge Lessee of any obligations hereunder to Lessor and, if Lessee or assignee of part or parts hereof shall fafl to Comply
with any other provisions of the lease, such default shall not affect this lease Insofar as it covers a part of said lands upon which Lessee or any assignee shall comply with the provisions of the lease. In addition, Lessee may at any time and from
time to time execute and deliver to lessor or file for record a release or releases of this lease as to any part or all of said land or of any mineral or horizon thereunder, and thereby be relieved of all obligations as to the released acreage or
interest. 
 11. In case of suit, adverse claim, dispute or question as to the ownership of the royalties (or some part thereof payable under
this lease, Lessee shall not be held In default in payment of such royalties (or the part thereof in dispute), until such suit, claim, dispute or question has been finally disposed of, and Lessee shall have thirty (30) days after being
furnished with a certified copy of the instrument or instruments disposing of such suit, claim or dispute, or after being furnished with proof sufficient, In Lessee’s opinion, to settle such question, within which to make payment. Should the
right or interest of Lessee hereunder be disputed by Lessor, or any other person, the time covered by the pendency of such dispute shall not be counted against Lessee either as affecting the term of the lease or for any other purpose, and Lessee may
suspend all payments without Interest until there is a final adjudication or other determination of such dispute. 
 12. In case of
cancellation or termination of this lease from any cause, Lessee shall have the right to retain. under the terms hereof, around each well producing, being worked on, or drilling hereunder, the number of acres in the form allocated to each such well
under spacing and proration rules issued by the Commissioner of Conservation of the State of Louisiana, or any other State or Federal authority having control of such matters; or any unit or units formed pursuant to paragraph 7 or, in the absence of
such rulings, unit or units, forty (40) acres around each such well in as near a square form as practicable, and in the event Lessor considers that operations are not being conducted in
compliance with this contract, Lessee shall be notified in writing of the facts relied upon as constituting a breach hereof and Lessee shall have sixty (60) days after receipt of such notice to comply with the obligations Imposed by virtue of
this Instrument. 
 13. When drilling, reworking, production or other operations are delayed or Interrupted by force majeure, that is, by
storm, flood or other acts of God, fire. war, rebellion. insurrection, riot, strikes, differences with workmen, or failure of carriers to transport or furnish facilities for transportation, or as a result of some law, order, rule, regulation.
requisition or necessity of government, Federal or State, or as a result of any cause whatsoever beyond the control of the Lessee, the time of such delay or Interruption shall not be counted against Lessee, anything in this lease to the contrary
notwithstanding, but this lease shall be extended for a period of time equal to that during which Lessee is so prevented from conducting such drilling or reworking operations on, or producing oil, gas, casinghead gas, condensate or other minerals
from, the premises: provided that during any period that this lease is continued in force after its primary term solely by force majeure as herein provided, Lessee shall pay to the owners of the royally hereunder the
shut-in royalty provided in paragraph 5 hereof, and in the manner /herein provided, without regard to whether or not there is a producing well shut in, located on said and or on land with which the lease
premises or any part thereof has been pooled. 

  
 43 

 14. Lessee shall pay for actual damages caused by its operations to growing crops and timber on
said land leased herein. 
 15. Notwithstanding the death of any party Lessor, or his successor in interest, the payment or tender of all
sums accruing hereunder in the manner provided above shall be binding on the heirs, executors and administrators of such person. 
 16.
Lessor hereby warrants and agrees to defend the title to the lands herein described, and agrees that the Lessee at its option shall have the right to redeem for Lessor, by payment, any mortgage, taxes or other liens on the above described lands, in
the event of default of payment by Lessor, and be subrogated to the rights of the holder thereof. In case of payment of any such mortgage, taxes or other liens by Lessee in addition to the right to subrogation herein granted. Lessee shall also have
the right to retain any royalties which become due Lessor hereunder and to repay itself therefrom, and the retention of such royalties by Lessee shall have the same effect as if paid to the Lessor in whose behalf payment of any mortgage, taxes or
other liens was made. 
 17. This lease shall be binding upon all who execute it, whether or not named in the body hereof as Lessor, and
without regard to whether this same Instrument, or any copy thereof, shall be executed by any other Lessor named above. 
 IN WITNESS
WHEREOF, this instrument is executed as of the date first above written: 
  

					
	WITNESSES:	  	LESSOR (WHETHER ONE OR MORE)
			
	[Print
Name:                                        
]	  	  
	  	  

	  
	  		  	SS. NO or Tax ID
			
	[Print
Name:                                        
]	  	  
	  	  

			
	STATE OF
                                        
	  		  	
			
	PARISH/COUNTY OF                     	  		  	

  
 44 

 On this         day of
        ,     before me, the undersigned authority, personally appeared                  to me known to be
the
 person(s) described in and who executed the foregoing instrument and acknowledged that they executed the same as their free act and deed. 
  

			
	 My Commission expires
                                        

	 	  

		 	NOTARY PUBLIC in and for     Parish, Louisiana
		
	STATE OF
                                         
           	 	
		
	PARISH/COUNTY OF                             	 	
	
	  
 Before me, the undersigned
authority, personally came and appeared              who being first duly sworn deposes and says that he/she was one of the subscribing witnesses to the execution of the foregoing
instrument by                         who signed the same in his/her presence and that of the other subscribing witness(es) to
such signature(s) whose name(s) (signatures) are affixed as such, and that he/she now recognizes all said signatures to be true and genuine.
  

		 	  
 Subscribing Witness

	
	Sworn to and subscribed before me, on this                      day
of                            .
		
	My Commission expires                                 	 	
		 	  
 NOTARY PUBLIC in and for
     Parish, Louisiana

  
 45 

 EXHIBIT “C” 

Attached to and made a part of that certain Operating Agreement dated     by and between
                , as Operator, and     , as Non Operator(s). 

ACCOUNTING PROCEDURE 

JOINT OPERATIONS 
 I.
GENERAL PROVISIONS 
 1. Definitions 

“Joint Property” shall mean the real and personal property subject to the agreement to which this Accounting Procedure is attached.

 “Joint Operations” shall mean all operations necessary or proper for the development, operation, protection and maintenance of
the Joint Property. 
 “Joint Account” shall mean the account showing the charges paid and credits received in the conduct of the
Joint Operations and which are to be shared by the Parties. 
 “Operator” shall mean the party designated to conduct the Joint
Operations. 
 “Non-Operators” shall mean the Parties to this agreement other than the
Operator. 
 “Parties” shall mean Operator and Non-Operators. 

‘First Level Supervisors” shall mean those employees whose primary function in Joint Operations is the direct supervision of other
employees and/or contract labor directly employed on the Joint Property in a field operating capacity. 
 “Technical Employees”
shall mean those employees having special and specific engineering, geological or other professional skills, and whose primary function in Joint Operations is the handling of specific operating conditions and problems for the benefit of the Joint
Property. 
 “Personal Expenses” shall mean travel and other reasonable reimbursable expenses of Operator’s employees. 

“Material” shall mean personal properly, equipment or supplies acquired or held for use on the Joint Property. 

“Controllable Material’ shall mean Material which at the time is so classified in the Material Classification Manual as most recently
recommended by the Council or Petroleum Accountants Societies. 

  
 1 

 2. Statement and Billings 

Operator shall bill Non-Operators on or before the last day of each month for their proportionate share
of the Joint Account for the preceding month. Such bills will be accompanied by statements which identify the authority for expenditure, lease or facility, and all charges and credits summarized by appropriate classifications of investment and
expense except that items of Controllable Material and unusual charges and credits shall be separately identified and fully described in detail. 
 3.
Advances and Payments by Non-Operators 
  

	 	A.	Unless otherwise provided for in the agreement, the Operator may require the Non-Operators to advance their sham of estimated cash outlay for the succeeding month’s operation
within fifteen (15) days after receipt of the billing or by the first day of the month for which the advance is required, whichever is later. Operator shall adjust each monthly billing to reflect advances received from the Non-Operators. 

  

	 	B.	Each Non-Operator shall pay its proportion of all bills within fifteen (15) days after receipt. If payment is not made within such time, the unpaid balance shall bear
interest monthly at the prime rate in effect at Bank One of Oklahoma, N.A. +2% on the first day of the month in which delinquency occurs plus 1% or the maximum contract rate permitted by the applicable usury laws in the state in which the
Joint Property is located, whichever is the lesser, plus attorney’s fees, court costs, and other costs in connection with the collection of unpaid amounts. 

4. Adjustments 
 Payment of any such bills shall
not prejudice the right of any Non-Operator to protest or question the correctness thereof; provided, however, all bills and statements rendered to Non-Operators
by Operator during any calendar year shall conclusively be presumed to be true and correct alter twenty-four (24) months following the end of any such calendar year, unless within the said twenty-four (24) month period a Non-Operator takes written exception thereto and makes claim on Operator for adjustment. No adjustment favorable to Operator shall be made unless it is made within the same prescribed period. The provisions of this
paragraph shall not prevent adjustments resulting from a physical inventory of Controllable Material as provided for in Section V. 
 5. Audits 

 

	 	C.	A Non-Operator, upon notice in writing to Operator and all other Non-Operators, shall have the right to audit Operator’s accounts and
records relating to the Joint Account for any calendar year within the twenty-four (24) month period following the end of such calendar year; provided, however, the making of an audit shall not extend the time for the taking of written
exception to and the adjustments of accounts as provided for in Paragraph 4 of this Section I. Where there are two or more Non-Operators, the Non-Operators shall make
every reasonable effort to conduct a Joint audit in a manner which will result in a minimum of inconvenience to the Operator. 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 Operator, except upon the resignation or removal of the Operator, and shall be made at the expense of those Non-Operators approving such audit. 

  
 2 

	 	D.	The Operator shall reply in writing to an audit report within 180 days after receipt of such report. Failure of the operator to file a timely written reply shall be handled in accordance with COPAS Bulletin 3. Audit
Proposal. 

 6. Approval By Non-Operators 

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. 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. 

II. DIRECT CHARGES 
 Operator shall charge the
Joint Account with the following items: 
 1. Ecological and Environmental 

Costs incurred for the benefit of the Joint Property as a result of governmental or regulatory requirements to satisfy environmental
considerations applicable to the Joint Operations. Such costs may include surveys of an ecological or archaeological nature and pollution control procedures as required by applicable laws and regulations. 

2. Rentals and Royalties 
 Lease rentals and
royalties paid by Operator for the Joint Operations. 
 3. Labor 

and/or consultants 
 A. 

 

	 	(1)	Salaries and wages of Operator’s field employees directly employed on the Joint Property in the conduct of Joint Operations. 

  

	 	(2)	Salaries of First level Supervisors in the field. 

 and/or consultants. 

 

	 	(3)	Salaries and wages of Technical Employees directly employed on the Joint Property if such charges are excluded from the overhead rates. 

and/or consultants 

  
 3 

	 	(4)	Salaries and wages of Technical Employees either temporarily or permanently assigned to and directly employed in the operation or the Joint Property if such charges are excluded from the overhead rates.

  

	 	B.	Operator’s cost of holiday, vacation, sickness and disability benefits and other customary allowances paid in employees whose salaries and wages are chargeable to the Joint Account under Paragraph 3A of this
Section II. Such costs under this Paragraph 3B 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 Paragraph 3A of this Section II.
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 which arc applicable to Operator’s Costs chargeable to the Joint Account under Paragraphs 3A and 3B of this
Section II. 

  

	 	D.	Personal Expenses or those employees whose salaries and wages are chargeable to the Joint Account tinder Paragraphs 3A arid 3D or thus Section II. 

4. Employee Benefits 
 Operators current costs or
established plans for employees’ group life insurance, hospitalization, pension, retirement, stock purchase, thrift, bonus, and other benefit plans of a like nature, applicable to Operators, labor cost chargeable to the Joint Account under
Paragraphs 3A and 3B of this Section II shall be Operator’s actual cost not to exceed the percent most recently recommended by the Council of Petroleum Accountants Societies. 

5. Material 
 Material purchased or furnished by
Operator for use on the Joint Property as provided under Section IV. Only such Material shall be purchased for or transferred to the Joint Property as may be required for immediate use and is reasonably practical and consistent with efficient and
economical operations. The accumulation of surplus stocks shall be avoided. 
 6. Transportation 

Transportation of employees and Material necessary for the Joint Operations but subject to the following limitations: 

 

	 	A.	If Material is moved to the Joint Property from the Operator’s warehouse or other properties, no charge shall be made to the Joint Account for a distance greater than the distance from the nearest reliable supply
store where like material is normally available or railway receiving point nearest the Joint Property unless agreed to by the Parties. 

  
 4 

	 	B.	If surplus Material is moved to Operator’s warehouse or other storage point, no charge shall be made to the Joint Account for a distance greater than the distance to the nearest reliable supply store where like
material is normally available, or railway receiving point nearest the Joint Property unless agreed to by the Parties. No charge shall be made to the Joint Account for moving Material to other properties belonging to Operator, unless agreed to by
the Parties. 

  

	 	C.	In the application of subparagraphs A and B above, the option to equalize or charge actual trucking cost is available when the actual charge is $400 or less excluding accessorial charges. The $400 will be
adjusted to the amount most recently recommended by the Council of Petroleum Accountants Societies. 

 7. Services 

The cost of contract services, equipment and utilities provided by outside sources, except services excluded by Paragraph 10 of Section II and
Paragraph i, ii, and iii, of Section III. The cost of professional consultant services and contract services of technical personnel directly engaged on the Joint Property if such charges are excluded from the overhead rates. The cost of professional
consultant services or contract services of technical personnel not directly engaged on the Joint Property shall not be charged to the Joint Account unless previously agreed to by the Parties. 

8. Equipment and Facilities Furnished By Operator 
  

	 	A.	Operator shall charge the Joint Account for use of Operator owned equipment and facilities at rates commensurate with costs of ownership and operation. Such rates shall include costs of maintenance, repairs, other
operating, expense, insurance, taxes, depreciation, and interest on gross investment less accumulated depreciation not to exceed ten percent (10%) per annum. Such rates shall not exceed average commercial rates currently prevailing in the
immediate area of the Joint Property. 

  

	 	B.	In lieu of charges in Paragraph 8A above, Operator may elect to use average commercial rates prevailing in the immediate area of the Joint Property. For automotive equipment, Operator may elect to use rates published by
the Petroleum Motor Transport Association. 

 9. Damages and Losses to Joint Property 

All costs or expenses necessary for the repair or replacement of Joint Property made necessary because of damages or losses incurred by fire,
flood, storm, theft, accident, or other cause, except those resulting from Operator’s gross negligence or willful misconduct. Operator shall furnish Non-Operator written notice of damages or losses
incurred as soon as practicable after a report thereof has been received by Operator. 

  
 5 

 10. Legal Expense, Title and Regulatory Work 

Expense of handling, investigating and settling litigation or claims, title and regulation work, discharging of liens, payment of judgments and
amounts paid for settlement of claims incurred in or resulting from operations under the agreement or necessary to protect or recover the Joint Property. All costs, whether legal, professional or otherwise, which are incurred in the investigation,
examination, preparation and curative of drill site title and those expenses incurred in order to comply with state and/or federal rules and regulations with respect to spacing, proration and production shall constitute a direct charge. 

11. Taxes and Permits 
 All taxes and permits of
every kind and nature assessed or levied upon or in connection with the Joint Property, the operation thereof, or the production there from, and which taxes have been paid by the Operator for the benefit of the Parties. 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. 
 12. Insurance 

Net premiums paid for insurance required to be carried for the Joint Operations for the protection of the Parties In the event Joint Operations
are conducted in a state in which Operator may act as self-insurer for Worker’s Compensation and/or Employers Liability under the respective states laws, Operator may, at its election, include the risk under its self-insurance program and in
that event, Operator shall include a charge at Operator’s cost not to exceed manual rates. 
 13. Abandonment and Reclamation 

Costs incurred for abandonment of the Joint Property, including costs required by governmental or other regulators authority. 

14. Communications 
 Cost of acquiring, leasing,
installing, operating, repairing and maintaining communication systems, including radio and microwave facilities directly serving the Joint Property. In the event communication facilities/systems serving the Joint Property are Operator owned,
charges to the Joint Account shall be made as provided in Paragraph 8 of this Section II. 
 15. Other Expenditures 

Any other expenditure not covered or dealt with in the foregoing provisions of this Section II, or in Section III 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. 

  
 6 

 III. OVERHEAD 

1. Overhead - Drilling and Producing Operations 
  

	 	i.	As compensation for administrative, supervision, office services and warehousing costs, Operator shall charge drilling and producing operations on either: 

( X ) Fixed Rate Basis, Paragraph 1A, or 

(    ) Percentage Basis, Paragraph 1B 

Unless otherwise agreed to by the Parties, such charge shall be in lieu of costs and expenses of all offices and salaries or wages plus
applicable burdens and expenses of all personnel, except those directly chargeable under Paragraph 3A, Section II. 
  

	 	ii.	The salaries, wages and Personal Expenses of Technical Employees and/or the cost of professional consultant services and contract services of technical personnel directly employed on the Joint Property:

 (    ) shall be covered by the overhead rates, or 

( X ) shall not be covered by the overhead rates. 
  

	 	iii.	The salaries, wages and Personal Expenses of Technical Employees and/or costs of professional consultant services and contract services of technical personnel either temporarily or permanently assigned to and directly
employed in the operation of the Joint Property. 

 (    ) shall be covered by the overhead rates, or 

( X ) shall not be covered by the overhead rites. 
  

	 	A.	Overhead - Fixed Rate Basis 

  

	 	(1)	Operator shall charge the Joint Account at the following rates per all per month-  

Drilling Well Rate $[***] 

(Prorated for less than a full month) 

Producing Well Rate $[***] 
  

	 	(2)	Application of Overhead - Fixed Rate Oasis shall be as follows: 

  

	 	(a)	Drilling Well Rate 

  

	 	(1)	Charges for drilling wells shall begin on the date the well is spudded and terminate on the date the drilling rig, completion rig, or other units used in completion of the well is released, whichever is later, except
that no charge shall be made during suspension of drilling or completion operations for fifteen (15) or more consecutive calendar days. 

  

	 	(2)	Charges for wells undergoing any type of workover or recompletion for a period of five (5) consecutive work days or more shall be made at the drilling well rate. Such charges shall be applied for the
period from date workover operations, with rig or other units used in workover, commence through date of rig or other unit release, except that no charge shall be made during suspension of operations for fifteen (15) or mere consecutive
calendar days. 

  
 7 

	 	(b)	Producing Welt Rates 

  

	 	(1)	An active well either produced or injected into for any portion of the month shalt be considered as a one-well charge for the entire month

  

	 	(2)	Each active completion in a multi-completed well in which production is not commingled down hole shall be considered as a one-well charge providing each completion is
considered a separate well by the governing regulatory authority. 

  

	 	(3)	An inactive gas well shut in because of overproduction or failure of purchaser to take the production shalt he considered as a one-well charge providing the gas welt
is directly connected to a permanent sales outlet. 

  

	 	(4)	A one-well charge shall be made for the month in which plugging and abandonment operations are completed on any well. This one-well charge shall be made whether or not the well
has produced except when drilling well rate applies. 

  

	 	(5)	All other inactive wells (including but not limited to inactive wells covered by unit allowable, lease allowable, transferred allowable, etc.) shall not qualify for an overhead charge. 

 

	 	(3)	The well rates shall be adjusted as of the first clay of April each year following the effective date of the agreement to which this Accounting Procedure is attached by the percent increase or decrease published by
COPAS. 

 2. Overhead - Major Construction 

To compensate Operator for overhead costs incurred in 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, Operator shall either negotiate a rate prior to the beginning of construction, or shall charge the Joint Account for overhead based
on the following rates for any Major Construction project in excess of $50,000.00. 
  

	 	A.	5.0% of first $100,000 or total cost if less, plus 

  

	 	B.	3.0% of costs in excess of $100,000 but less than $1,000,000, plus 

  

	 	C.	2.0% of costs in excess of $1,000,000. 

  
 8 

 Total cost shall mean the gross cost of any one project. For the purpose of this paragraph, the
component parts of a single project shall not be treated separately and the cost of drilling and workover wells and artificial lift equipment shall be excluded. 

3. Catastrophe Overhead 
 To compensate Operator
for overhead costs incurred in the event of expenditures resulting from a single occurrence due to oil spill, blowout, explosion, fire, storm), hurricane, or other catastrophes as agreed to by the Parties, which are necessary to restore the Joint
Property to the equivalent condition that existed prior to the event causing the expenditures. Operator shall either negotiate a rate prior to charging the Joint Account or shall charge the Joint Account for overhead based on the following rates.

  

	 	A.	5.0%, of total costs through $100,000; plus 

  

	 	B.	3.0% of total costs in excess of $100,000 but less than $1,000,000; plus 

  

	 	C.	2.0% of total costs in excess of $1,000,000 

 Expenditures subject to the overheads above will
net be reduced by insurance recoveries, and no other overhead provisions of this Section III shall apply. 
 4. Amendment of Rates 

The overhead rates provided for in this Section III may be amended from time to time only by mutual agreement between the Parties hereto if, in
practice, the rates are found to be insufficient or excessive. 
 IV. PRICING OF JOINT ACCOUNT MATERIAL PURCHASES, TRANSFERS AND DISPOSITIONS

 Operator is responsible for Joint Account Material and shall make proper and timely charges and credits and all Material movements affecting the Joint
Property. Operator shall provide all Material for use on the Joint Property; however, at Operator’s option, such Material may be supplied by the Non-Operator. Operator shall make timely disposition of
idle and/or surplus Material, such disposal being made either through sale to Operator or Non-Operator, division in kind, or sale to outsiders. Operator may purchase, but shall be under no obligation to
purchase, interest of Non-Operators in surplus condition A or B Material. The disposal of surplus Controllable Material not purchased by the Operator shall be agreed to by the Parties. 

1. Purchases 
 Material purchased shall be
charged at the price paid by Operator after deduction or all discounts received. In case of Material found to be defective or returned to vendor for any other reasons, credit shall be passed to the Joint Account when adjustment has been received by
the Operator. 

  
 9 

 2. Transfers and Dispositions 

Material furnished to the Joint Property and Material transferred from the Joint Property or disposed of by the Operator, unless
otherwise agreed to by the Parties, shall be priced on the following basis exclusive of cash discounts. 
  

	 	A.	New Material (Condition A) 

  

	 	(1)	Tubular Goods Other than Line Pipe 

  

	 	(a)	Tubular goods, sized 2 3/8 inches OD and larger, except line pipe, shall be priced at bastern mill published carload base prices effective as of date of movement plus transportation cost using the
80,000 pound carload weight basis to the railway receiving point nearest the Joint Property for which published rail rates for tubular goods exist if the 80,000 pound rail rate is not offered, the 70,000 pound or 90,000 pound rail rate may be used.
Freight charges for tubing will be calculated from Lorain, Ohio and casing from Youngstown, Ohio. 

  

	 	(b)	For grades which arc special to one mill only, prices shall be computed at the mill plus transportation cost from that mill to the railway receiving point nearest the Joint Property as above in Paragraph 2.A.(1)(a). For
transportation cost from points other than Eastern milts, the 30,000 pound Oil Field Haulers Association interstate truck rate shall be used. 

  

	 	(c)	Special end finish tubular goods shall be priced at the lowest published out-of-stock price, f.o.b. Houston, Texas, plus transportation
cost, using Oil Field Haulers Association interstate 30,000 pound truck, rate, to the railway receiving point nearest the Joint Property. 

  

	 	(d)	Macaroni tubing (size less than 2 3/8 inch OD) shall be priced at the lowest published out-of-stock prices f.o.b. the supplier plus
transportation costs, using the Oil Field Haulers Association interstate truck rate per weight of tubing transferred, to the railway receiving point nearest the Joint Property. 

 

	 	(2)	Line Pipe 

  

	 	(a)	Line pipe movements (except size 24 inch OD and larger with walls 3/4 inch and over) 30,000 pounds or more
shall be priced under provisions of tubular goods pricing in Paragraph A(1)(a) as provided above. Freight charges shall be calculated from Lorain, Ohio. 

  

	 	(b)	Line Pipe movements (except size 24 inch OD and larger with walls 3/4 inch and over) less than 30,000 pounds
shall be priced at Eastern mill published carload base prices effective as of date of shipment, / plus 20 percent, plus transportation costs based on freight rates as set forth under provisions of tubular goods pricing in Paragraph A(1)(a) as
provided above. Freight charges shall he calculated from Lorain. Ohio 

  
 10 

	 	(c)	Line pipe 24 inch OD and over and 3/4 inch wall and larger shall be priced f.o.b. the point of manufacture at current new published prices plus transportation cost to the railway reserving point nearest the Joint
Property. 

  

	 	(d)	Line pipe, including fabricated line pipe, drive pipe and conduit not listed on published price lists shall be priced at quoted prices plus freight to the railway receiving point nearest the Joint Property or at prices
agreed to by the Parties. 

  

	 	(3)	Other Material shall be priced at the current new price, in effect at date of movement, as listed by a reliable supply store nearest the Joint Property, or point of manufacture, plus transportation costs, if’
applicable, to the railway receiving point nearest the Joint Property. 

  

	 	(4)	Unused new Material, except tubular goods, moved from the Joint Property shall be paced at the current new price, in effect on date of movement, as listed by a reliable supply store nearest the Joint Property, or point
of manufacture, plus transportation costs, if applicable, to the railway receiving point nearest the Joint Property Unused new tubulars will be priced as provided above in Paragraph 2A.(l) and (2). 

 

	 	B.	Good Used Material (Condition B) 

 Material in sound and serviceable condition and suitable for
reuse without reconditioning: 
  

	 	(1)	Material moved to the Joint Property 

 At seventy-five percent (75%) of current
new price, as determined by Paragraph A. 
  

	 	(2)	Material used on and moved from the Joint Property 

  

	 	(a)	At seventy-five percent (75%) of current new price, as determined by Paragraph A, if Material was originally charged to the Joint Account as new Material or 

 

	 	(b)	At sixty-five percent (65%) of current new price, as determined by Paragraph A, Material was originally charged to the Joint Account as used Material 

 

	 	(3)	Material not used on and moved from the Joint Property 

 At seventy-five
percent (75%) of current new price as determined by Paragraph A 
 The cost of reconditioning, if any, shall be absorbed by the
transferring property. 
  

	 	C.	Other Used Material 

  
 11 

	 	(1)	Condition C 

 Material which is not in sound and serviceable condition and not suitable for its
original function unit after reconditioning shall be priced at fifty percent (50%) or current new price as determined by Paragraph A. The cost of reconditioning shall be charged to the receiving property, provided Condition C value plus cost of
reconditioning does not exceed Condition B value. 
  

	 	(2)	Condition D 

 Material, excluding junk, no longer suitable for its original purpose, but usable
for some other purpose shall be priced on a basin commensurate with its use. Operator may dispose of Condition D Material under procedures normally used by Operator without prior approval of Non-Operators 

 

	 	(a)	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 easing, tubing or drill pipe utilized as line pipe shall be priced at used line
pipe prices. 

  

	 	(b)	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. 

  

	 	(3)	Condition E 

 Junk shall be priced at prevailing prices. Operator may dispose of Condition E
Material under procedures normally utilized by Operator without prior approval of Non-Operators. 
  

	 	D.	Obsolete Material 

 Material which is serviceable and usable for its original function but
condition and/or value of such Material is not equivalent to that which would justify a price as provided above may be specially priced as agreed to by the Parties. Such price should result in the Joint Account being charged with the value of the
service rendered by such Material. 
  

	 	E.	Pricing Conditions 

  

	 	(1)	Loading or unloading costs may be charged to the Joint Account at the rate of twenty-five cents (25 cents) per hundred on all tubular goods movements, in lieu of actual loading or unloading costs sustained at the
stocking point. The above rate shall be adjusted as of the first day of April each year following January 1, 1985 by the same percentage increase or decrease used to adjust overhead rates in Section III, Paragraph I .A.(3). Each year, the rate
calculated shall be rounded to the nearest cent and shall be the rate in effect until the first day of April next year. Such rate shall be published each year by the Council of Petroleum Accountants Societies. 

  
 12 

	 	(2)	Material involving erection costs shall he charged at applicable percentage of the current knocked-down price of new Material. 

3. Premium Prices 
 Whenever Material is not
readily obtainable at published or listed prices because of national emergencies, strikes or thin unusual causes over which the Operator has no control, the Operator may charge the Joint Account for the required Material at the Operator’s
actual cost incurred in providing such Material, in making if suitable for use, and if moving to the Joint Property; provided notice in writing is furnished to Non-Operators of the proposed charge prior to
billing Non-Operators for such Material. 
 4. Warranty of Material Furnished By Operator 

Operator does not warrant the Material furnished. In case of defective Material, credit shall not be passed to the Joint Account until
adjustment has been received by Operator from the manufacturers or their agents. 
 V. INVENTORIES 

The Operator shall maintain detailed records of Controllable Material 

1. Periodic Inventories, Notice and Representation 

At reasonable intervals, inventories shall be taken by Operator of the Joint Account Controllable Material. Written notice of intention to take
inventory shall be given by Operator at least thirty (30) days before any inventory is to begin so that Non-Operators may be represented when any inventory is taken. Failure of Non-Operators to be represented at an inventory shall bind Non-Operators to accept the inventory taken by Operator. 

2. Reconciliation and Adjustment of Inventories 

Adjustments to the Joint Account resulting from the reconciliation of a physical inventory shall be made within six months following the taking
of the inventory. Inventory adjustments shall be made by Operator to the Joint Account for overages and shortages, but, Operator shall be held accountable only for shortages due to lack of reasonable diligence. 

3. Special Inventories 
 Special inventories may
be taken whenever there is any sale, change of interest, or change of Operator in the Joint Property. It shall be the duty of the party selling to notify all other Parties as quickly as possible after the transfer of interest takes place. In such
cases, both the seller and the purchaser shall be governed by such inventory. In cases involving a change of Operator, all Parties shall be governed by such inventory. 

  
 13 

 4. Expense of Conducting Inventories 
  

	 	A.	The expense of conducting periodic inventories shall not he charged to the Joint Account unless agreed to by the Parties. 

  

	 	B.	The expense of conducting special inventories shall be charged to the Parties requesting such inventories, except inventories required due to change of Operator shall be charged to the Joint Account. 

  
 14 

 EXHIBIT “D” 

Attached hereto and made a part of that certain 

Joint Operating Agreement dated                 ,
20        , by and 
 between
                , as Operator and Non-Operator(s). 

INSURANCE 
 Operator,
during the term of this Agreement, shall comply with the provisions of Article VII.G. hereof. No other insurance will be carried by Operator for the benefit of the Joint Account. 

All damage or injury to the Contract Area or the property thereon shall be borne by the parties hereto in proportion to their interests
therein. The liability, if any, of the parties hereto in damages for claims growing out of personal injury to or death from third parties or injury to or destruction of property of third parties resulting from the operations conducted hereunder
shall be borne in proportion to their interests in the Contract Area property, and each party individually shall acquire insurance, including general liability and umbrella liability of limits that are within industry norms, to protect itself
against such claims or provide self-insurance. Upon request any party shall furnish evidence of either self-insurance or insurance coverage to the requesting party. Operator shall require all contractors engaged in work on or for the Contract Area
to comply with the Worker’s Compensation Law of the State where the operations are being conducted and to maintain such other insurance as Operator may require. 

  
 1 

 EXHIBIT “E” 

GAS BALANCING AGREEMENT (“AGREEMENT’’) 

ATTACHED TO AND MADE PART OF THAT CERTAIN 

OPERATING AGREEMENT DATED                 , 20 BY AND
BETWEEN                , AS 
 OPERATOR, AND
                AS NON-OPERATORS (“OPERATING AGREEMENT”) 

 

	1.	DEFINITIONS 

 The following definitions shall apply to this Agreement: 

 

	 	1.1	“Arm’s Length Agreement” shall mean any gas sales agreement with an unaffiliated purchaser or any gas sales agreement with an affiliated purchaser where the sales price and delivery conditions under such
agreement are representative of prices and delivery conditions existing under other similar agreements in the area between unaffiliated parties at the same time for natural gas of comparable quality and quantity. 

 

	 	1.2	“Balancing Area” shall mean each well subject to the Operating Agreement that produces Gas or is allocated a share of Gas production. If a single well is completed in two or more producing intervals, each
producing interval from which the Gas production is not commingled in the wellbore shall be considered a separate well. 

  

	 	1.3	“Full Share of Current Production” shall mean the Percentage Interest of each Party in the Gas actually produced from the Balancing Area during each month. 

 

	 	1.4	“Gas” shall mean all hydrocarbons produced or producible from the Balancing Area, whether from a well classified as an oil well or gas well by the regulatory agency having jurisdiction in such matters, which
are or may be made available for sale or separate disposition by the Parties, excluding oil, condensate and other liquids recovered by field equipment operated for the joint account. “Gas” does not include gas used in joint operations,
such as for fuel, recycling or reinjection, or which is vented or lost prior to its sale or delivery from the Balancing Area. 

  

	 	1.5	“Makeup Gas” shall mean any Gas taken by an Underproduced Party from the Balancing Area in excess of its Full Share of Current Production, whether pursuant to Section 3.3 or Section 4.1 hereof.

  

	 	1.6	“Met’ shall mean one thousand cubic feet. A cubic foot of Gas shall mean the volume of gas contained in one cubic foot of space at a standard pressure base and at a standard temperature base.

  

	 	1.7	“MMBtu” shall mean one million British Thermal Units. A British thermal Unit shall mean the quantity of heat required to raise one pound avoirdupois of pure water from 58.5 degrees Fahrenheit to 59.5 degrees
Fahrenheit at a pressure of 14.73 pounds per square inch absolute. 

  
 1 

	 	1.8	“Operator” shall mean the individual or entity designated under the terms (of the Operating Agreement or, in the event this Agreement is not employed in connection with an operating agreement, the individual
or entity designated as the operator of the well(s) located in the Balancing Area. 

  

	 	1.9	“Overproduced Party” shall mean any Party having taken a greater quantity of Gas from the Balancing Area than the Percentage Interest of such Party in the cumulative quantity of all Gas produced from the
Balancing Area. 

  

	 	1.10	“Overproduction” shall mean the cumulative quantity of Gas taken by a Party in excess of its Percentage Interest in the cumulative quantity of all Gas produced from the Balancing Area. 

 

	 	1.11	“Party” shall mean those individuals or entities subject to this Agreement, and their respective heirs, successors, transferees and assigns. 

 

	 	1.12	“Percentage Interest” shall mean the percentage or decimal interest of each Party in the Gas produced from the Balancing Area pursuant to the Operating Agreement covering the Balancing Area. 

 

	 	1.13	‘Royalty” shall mean payments on production of Gas from the Balancing Area to all owners of royalties, overriding royalties, production payments or similar interests. 

 

	 	1.14	“Underproduced Party” shall mean any Party having taken a lesser quantity of Gas from the Balancing Area than the Percentage Interest of such Party in the cumulative quantity of all Gas produced from the
Balancing Area. 

  

	 	1.15	“Underproduction” shall mean the deficiency between the cumulative quantity of Gas taken by a Party and its Percentage Interest in the cumulative quantity of all Gas produced from the Balancing Area.

  

	 	1.16	“Winter Period” shall mean the month(s) of October. November and December in one calendar year and the month(s) of January, February and March in the succeeding calendar year. 

 

	2.	BALANCING AREA 

  

	 	2.1	If this Agreement covers more than one Balancing Area, it shall be applied as if each Balancing Area were covered by separate but identical agreements. All balancing hereunder shall be on the basis of Gas taken from the
Balancing Area measured in MMBtus. 

  

	 	2.2	In the event that all or part of the Gas deliverable from a Balancing Area is or becomes subject to one or more maximum lawful prices, any Gas not subject to price controls shall be considered as produced from a single
Balancing Area and Gas subject to each maximum lawful price category shall be considered produced from a separate Balancing Area. 

  
 2 

	3.	RIGHT OF PARTIES TO TAKE GAS 

  

	 	3.1	Each Party desiring to take Gas will notify the Operator, or cause the Operator to be notified, of the volumes nominated, the name of the transporting pipeline and the pipeline contract number (if available) and meter
station relating to such delivery, sufficiently in advance for the Operator, acting with reasonable diligence, to meet all nomination and other requirements. Operator is authorized to deliver the volumes so nominated and confirmed (if confirmation
is required) to the transporting pipeline in accordance with the terms of this Agreement. 

  

	 	3.2	Each Party shall make a reasonable, good faith effort to take its Full Share of Current Production each month, to the extent that such production is required to maintain leases in effect, to protect the producing
capacity of a well or reservoir, to, preserve correlative rights, or to maintain oil production. 

  

	 	3.3	When a Party fails for any reason to take its Full Share or Current Production (as such Share may be reduced by the right of the other Parties to make up for Underproduction as provided herein), the other Parties shall
be entitled but not obligated to take any Gas which such Party fails to take. To the extent practicable, such Gas shall be made available initially to each Underproduced Party in the proportion that its Percentage Interest in the Balancing Area
bears to the total Percentage Interests of all Underproduced Parties desiring to take such Gas. If all such Gas is not taken by the Underproduced Parties, the portion not taken shall then be made available to the other Parties in the proportion that
their respective Percentage Interests in the Balancing Area bear to the total Percentage Interests of such Parties. 

  

	 	3.4	All Gas taken by a Party in accordance with the provisions of this Agreement, regardless of whether such Party is underproduced or overproduced, shall be regarded as Gas taken for its own account with title thereto
being in such taking Party. 

  

	 	3.5	Notwithstanding the provisions of Section 3.3 hereof, no Overproduced Party shall be entitled in any month to take any Gas in excess of three hundred percent (300%) of its Percentage Interest of the Balancing
Area’s then-current Maximum Monthly Availability; provided, however, that this limitation shall not apply to the extent that it would preclude production that is required to maintain leases in effect, to protect the producing capacity of a well
or reservoir, to preserve correlative rights, or to maintain oil production. “Maximum Monthly Availability” shall mean the maximum average monthly rate of production at which Gas can be delivered from the Balancing Area, as determined by
the Operator, considering the maximum efficient well rate for each well within the Balancing Area, the maximum allowable(s) set by the appropriate regulatory agency, mode of operation, production facility capabilities and pipeline pressures.

  
 3 

	 	3.6	In the event that a Party fails to make arrangements to take its Full Share of Current Production required to be produced to maintain leases in effect, to protect the producing capacity of a well or reservoir, to
preserve correlative rights, or to maintain oil production, the Operator may sell but is not obligated to sell any part of such Party’s Full Share of Current Production that such Party fails to take for the account of such Party and render to
such Party, on a current basis, the full proceeds of the sale, less any reasonable marketing, compression, treating, gathering or transportation costs incurred directly in connection with the sale of such Full Share of Current Production. In making
the sale contemplated herein, the Operator shall be obligated only to obtain such price and conditions for the sale as are reasonable under the circumstances and shall not be obligated to share any of its markets. Any such sale by Operator under the
terms hereof 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 year. Notwithstanding the provisions of Article
3.4 hereof, Gas sold by Operator for a Party under the provisions hereof shall be deemed to be Gas taken for the account of such Party. Notwithstanding anything contained herein to the contrary, no agency relationship or other relationship of trust
and confidence shall be created by such sale and Operator’s sale of production under the terms hereof shall be subject to the terms of Section 12.3 hereof. 

 

	4.	IN-KIND BALANCING 

  

	 	4.1	Effective the first day of any calendar month following at least thirty (30) days’ prior written notice to the Operator, any Underproduced Party may begin taking, in addition to its Full Share of Current
Production and any Makeup Gas taken pursuant to Section 3.3 of this Agreement, a share of current production determined by multiplying twenty-five percent (25%) during all seasons of the Full Shares of Current Production of all Overproduced
Parties by a fraction, the numerator of which is the Percentage interest of such Underproduced Party and the denominator of which is the total of the Percentage Interests or all Underproduced Parties desiring to take Makeup Gas. In no event will an
Overproduced Party be required to provide more than twenty-five percent (25%) during the winter months and flay percent (50%) the remaining months of its Full Share of Current Production for Makeup Gas. The Operator will promptly notify all
Overproduced Parties of the election of an Underproduced Party to begin taking Makeup Gas. 

  

	 	4.2	Notwithstanding any other provision of this Agreement, at such time and for so long as Operator, or (insofar as concerns production by the Operator) any Underproduced Party, determines in good faith that an Overproduced
Party has produced all of its share of the ultimately recoverable reserves, as determined by an independent reservoir engineering consulting firm mutually agreed to by the Parties, in the Balancing, Area, such Overproduced Parry may be required to
make available for Makeup Gas, upon the demand of the Operator or any Underproduced Party, up to one hundred percent (100%) of such Overproduced Party’s Full Share of Current Production. 

  
 4 

	5.	STATEMENT OF GAS BALANCES 

  

	 	5.1	The Operator will maintain appropriate accounting on a monthly and cumulative basis of the volumes of Gas that each Party is entitled to receive and the volumes of Gas actually taken or sold for each Party’s
account. Within forty-five (45) days after the month of production, the Operator will furnish a statement for such month showing (1) each Party’s Full Share of Current Production, (2) the total volume of Gas actually taken or
sold for each Party’s account, (3) the difference between the volume taken by each Party and that Party’s Full Share of Current Production, (4) the Overproduction or Underproduction of each Party, and (5) other data as
recommended by the provisions of the Council of Petroleum Accountants Societies Bulletin No.24, as amended or supplemented hereafter. Each Party taking Gas will promptly provide to the Operator any data required by the Operator for preparation of
the statements required hereunder. 

  

	 	5.2	If any Party fails to provide the data required herein for four (4) consecutive production months, the Operator, or where the Operator has failed to provide data, another Party, may audit the production and Gas
sales and transportation volumes of the non-reporting Party to provide the required data. Such audit shall be conducted only after reasonable notice and during normal business hours in the office of the Party
whose records are being audited. All costs associated with such audit will be charged to the account of the Party failing to provide the required data. 

  

	6.	PAYMENTS ON PRODUCTION 

  

	 	6.1	Each Party taking Gas shall pay or cause to be paid all production and severance taxes due on all volumes of Gas actually taken by such Party. 

 

	 	6.2	At all times while gas is produced from the Contract Area, each Party shall pay or cause to be paid all royalties, overriding royalties or other payments due with respect to Royalty owners to whom it is accountable as
if such party were taking its Full Share of Current Production and only its Full Share of Current Production, exclusive of gas used in operations, vented or lost, and each party shall protect, indemnify and hold harmless all other parties from any
and all claims relating thereto. 

  

	 	6.3	In the event that any governmental authority requires that Royalty payments be made on any other basis than that provided for in this Section 6.2, each Party agrees to make such Royalty payments accordingly,
commencing on the effective date required by such governmental authority, and the method provided for herein shall be thereby superseded. 

  

	7.	CASH SETTLEMENTS 

  

	 	7.1	Upon the earlier of the plugging and abandonment of the last producing interval in the Balancing Area, the termination of the Operating Agreement or any pooling or unit agreement covering the Balancing Area, or at any
time no Gas is taken from the Balancing Area for a period of twelve (12) consecutive months, any 

  
 5 

	 	
Party may give written notice calling for cash settlement of the Gas production imbalances among the Parties. Such notice shall be given to all Parties in the Balancing Area. 

 

	 	7.2	Within sixty (60) days after receipt of the notice calling for cash settlement under Section 7.1, the Operator will distribute to each Party a Final Gas Settlement Statement detailing the quantity of
Overproduction owed by each Overproduced Party to each Underproduced Party and identifying the month to which such Overproduction is attributed, pursuant to the methodology set out in Section 7.4. 

 

	 	7.3	Within sixty (60) days idler receipt of the Final Gas Settlement Statement, each Overproduced Party will pay to each Underproduced Party entitled to settlement the appropriate cash settlement, accompanied by
appropriate accounting detail. At the time of payment, the Overproduced Party will notify the Operator of the Gas imbalance settled by the Overproduced Party’s payment. 

 

	 	7.4	The amount of the cash settlement will be based on the proceeds received by the Overproduced Party under an Arm’s Length Agreement for the Gas taken from time to time by the Overproduced Party in excess of the
Overproduced Party’s Full Share of Current Production. Any Makeup Gas taken by the Underproduced Party prior to cash settlement hereunder will be applied to offset Overproduction chronologically in the order of accrual. 

 

	 	7.5	The values used for calculating the cash settlement under Section 7.4 will include all proceeds received for the sale of the Gas by the Overproduced Party calculated at the Balancing Area, after deducting any
production or severance taxes paid, as well as any reasonable marketing, compression, treating, gathering or transportation costs incurred directly in connection with the sale of the Overproduction. 

 

	 	7.5.1 	For Overproduction sold under a gas purchase contract providing for payment based on a percentage of the proceeds obtained by the purchaser upon resale of residue gas and liquid hydrocarbons extracted at a gas
processing plant, the values used for calculating cash settlement will include proceeds received by the Overproduced Party for both the liquid hydrocarbons and the residue gas attributable to the Overproduction. 

 

	 	7.5.2 	For Overproduction processed for the account of the Overproduced Party at a gas processing plant for the extraction of liquid hydrocarbons, the full quantity of the Overproduction will be valued for purposes of cash
settlement at the prices received by the Overproduced Party for the sale of the residue gas attributable to the Overproduction without regard to proceeds attributable to liquid hydrocarbons which may have been extracted from the Overproduction.

  
 6 

	 	7.6	To the extent the Overproduced Party did not sell all Overproduction under an Arm’s Length Agreement, the cash settlement will be based on the weighted average price received by the Overproduced Party for any gas
sold from the Balancing Area under Arm’s Length Agreements during the months to which such Overproduction is attributed. In the event that no sales under Ann’s Length Agreements were made during any such month, the cash settlement for such
month will be based on the simple average of the spot sales prices published for the applicable geographic area in the first issue of inside F. E. R. C.’s Gas Market report, Natural Gas Week and Natural Gas Intelligence for such month. Should
these publications cease to exist, a mutually acceptable pricing bulletin shall be used. 

  

	 	7.7	Interest compounded at the “Prime Rate” as published in the Wall Street Journal “Money Rates” table on the first date of publication for the calendar month in which payment is due, plus 3% per annum
or the maximum lawful rate of interest applicable to the Balancing Area, whichever is less, will accrue for all amounts due under Section 7.1 beginning the first day following the date payment is due pursuant to Section 7.3. Such interest
shall be borne by the Operator or any Overproduced Party in the proportion that their respective delays beyond the deadlines set out in Sections 7.2 and 7.3 contributed to the accrual of the interest. 

 

	 	7.8	In lieu of the cash settlement required by Section 7.3, an Overproduced Party may deliver to the Underproduced Party an offer to settle its Overproduction in-kind and at such
rates, quantities, times and sources as may be agreed upon by the Underproduced Party. If the Parties are unable to agree upon the manner in which such in-kind settlement gas will be furnished within sixty
(60) days after the Overproduced Party’s offer to settle in kind, which period may be extended by agreement of said Parties, the Overproduced Party shall make a cash settlement as provided in Section 7.3. The making of an in-kind settlement offer under this Section 7.8 will not delay the accrual of interest on the cash settlement should the Parties fail to reach agreement on an in-kind
settlement. 

  

	 	7.9	That portion of any monies collected by an Overproduced Party for Overproduction which is subject to refund by orders of the Federal Energy Regulatory Commission or other governmental authority may be withheld by the
Overproduced Party until such prices are fully approved by such governmental authority, unless the Underproduced Party furnishes a corporate undertaking, acceptable to the Overproduced Party, agreeing to hold the Overproduced Party harmless from
financial loss due to refund orders by such governmental authority. 

  

	8.	TESTING 

 Notwithstanding any provision of this Agreement to the contrary, any Party
shall have the right, from time to time, to produce and take up to one hundred percent (100%) of a well’s entire Gas stream to meet the reasonable deliverability test(s) required by such Party’s Gas purchaser, and the right to take any
Makeup Gas shall be subordinate to the right of any Party to conduct such tests; provided, however, that such tests shall be conducted in accordance with prudent operating practices only after thirty (30) days’ prior written notice to the
Operator and shall 

  
 7 

 
last no longer than seventy-two (72) hours. Consent of Parties then taking all or any part of their share of gas shall be required to conduct testing
during Winter Period. Notwithstanding anything contained herein to the contrary, the Operator shall be required to only perform one (1) reasonable deliverability test per calendar year if requested by a Party to this agreement. 

 

	9.	OPERATING COSTS 

 Nothing in this Agreement shall change or affect any Party’s
obligation to pay its proportionate share of all costs and liabilities incurred in operations on or in connection with the Balancing Area, as its share thereof is set forth in the Operating Agreement, irrespective of whether any Party is at any time
selling and using Gas or whether such sales or use are in proportion to its Percentage Interest in the Balancing Area. 
  

	10.	LIQUIDS 

 The Parties shall share proportionately in and own all liquid hydrocarbons
recovered with Gas by field equipment operated for the joint account in accordance with their Percentage Interests in the Balancing Area. 
  

	11.	AUDIT RIGHTS 

 Notwithstanding any provision in this Agreement or any other agreement
between the Parties hereto, and further notwithstanding any termination or cancellation of this Agreement, for a period of two (2) years from the end of the calendar year in which any information to be furnished under Section 5 or 7 hereof
is supplied, any Party shall have the right to audit the records of any other Party regarding quantity, including but not limited to information regarding Btu-content. Any Underproduced Party shall have the
right for a period of two (2) years from the end of the calendar year in which any cash settlement is received pursuant to Section 7 to audit the records of any Overproduced Party as to all matters concerning values, including but not
limited to information regarding prices and disposition of Gas from the Balancing Area. Any such audit shall be conducted at the expense of the Party or Parties desiring such audit, and shall be conducted, after reasonable notice, during normal
business hours in the office of the Party whose records are being audited. Each Party hereto agrees to maintain for a period of two (2) years the records as to the volumes and prices of Gas sold each month and the volumes of Gas used in its own
operations, along with the Royalty paid on any such Gas used by a Party in its own operations. The audit rights provided for in this Section 11 shall be in addition to those provided for in Section 5.2 of this Agreement. 

 

	12.	MISCELLANEOUS 

  

	 	12.1	As between the Parties, in the event of any conflict between the provisions of this Agreement and the provisions of any gas sales contract or in the event of any conflict between the provisions of this Agreement and the
provisions of the Operating Agreement, the provisions of this Agreement shall govern. 

  
 8 

	 	12.2	Each Party agrees to defend, indemnify and hold harmless all other Parties from and against any and all liability for any claims, which may be asserted by any third party which now or hereafter stands in a contractual
relationship with such indemnifying Party and which arise out of the operation of this Agreement or any activities of such indemnifying Party under the provisions of this Agreement, and does further agree to save the other Parties harmless from all
judgments or damages sustained and costs incurred in connection therewith. 

  

	 	12.3	Except as otherwise provided in this Agreement, Operator is authorized to administer the provisions of this Agreement, but shall have no liability to the other Parties for losses sustained or liability incurred which
arise out of or in connection with the performance of Operator’s duties hereunder, except such as may result from Operator’s gross negligence or willful misconduct. Operator shall not be liable to any Underproduced Party for the failure of
any Overproduced Party (other than Operator) to pay any amounts owed pursuant to the terms hereof 

  

	 	12.4	This Agreement shall remain in full force and effect for as long as the Operating Agreement shall remain in force and effect as to the Balancing Area, and thereafter until the Gas accounts between the Parties are
settled in full, and shall inure to the benefit of and be binding upon the Parties hereto, and their respective heirs, successors, legal representatives and assigns, if any. The Parties hereto agree to give notice of the existence of this Agreement
to any successor in interest of any such Party and to provide that any such successor shall be bound by this Agreement, and shall further make any transfer of any interest subject to the Operating Agreement, or any part thereof, also subject to the
terms of this Agreement. 

  

	 	12.5	Unless the context clearly indicates otherwise, words used in the singular include the plural, the plural includes the singular, and the neuter gender includes the masculine and the feminine. 

 

	 	12.6	This Agreement shall bind the Parties in accordance with the provisions hereof, and nothing herein shall be construed or interpreted as creating any rights in any person or entity not a signatory hereto, or as being a
stipulation in favor of any such person or entity. 

  

	 	12.7	If contemporaneously with this Agreement becoming effective. or thereafter, any Party requests that any other Party execute an appropriate memorandum or notice of this Agreement in order to give third parties notice of
record of same and submits same for execution in recordable form, such memorandum or notice shall be duly executed by the Party to which such request is made and delivered promptly thereafter to the Party making the request. Upon receipt, the Party
making the request shall cause the memorandum or notice to be duly recorded in the appropriate real property or other records affecting the Balancing Area. 

  
 9 

	 	12.8	In the event federal tax regulations require a uniform method of computing taxable income by all Parties, the Parties agree to negotiate in good faith to develop such a uniform method that is in accordance with the
requirement of said tax regulations. 

  

	13.	ASSIGNMENT AND RIGHTS UPON ASSIGNMENT 

  

	 	13.1	Subject to the provisions of Sections 13.2 and 13.3 hereof, and notwithstanding anything in this Agreement or in the Operating Agreement to the contrary, if any Party assigns (including any sale, exchange or other
transfer) any of its working interest in the Balancing Area when such Party is an Underproduced or Overproduced Party, the assignment or other act of transfer shall, insofar as the Parties hereto are concerned, include all interest of the assigning
or transferring Party in the Gas, all rights to receive or obligations to provide or take Makeup Gas and all rights to receive or obligations to make any monetary payment which may ultimately be due hereunder, as applicable. Operator and each of the
other Parties hereto shall thereafter treat the assignment accordingly, and the assigning or transferring Party shall look solely to its assignee or other transferee for any interest in the Gas or monetary payment that such Party may have or to
which it may be entitled, and shall cause its assignee or other transferee to assume its obligations hereunder. 

  

	 	13.2	 Notwithstanding anything in this Agreement (including but not limited to the provisions of Section 13.1
hereof) or in the Operating Agreement to the contrary, and subject to the provisions of Section 13.3 hereof, in the event an Overproduced Party intends to sell, assign, exchange or otherwise transfer any of its interest in a Balancing Area,
such Overproduced Party shall notify in writing the other working interest owners who are Parties hereto in such Balancing Area of such fact at least sixty (60) days prior to closing the transaction. Such notice shall contain a preliminary gas
settlement statement detailing the quantity of Overproduction owed by the Overproduced Party to each Underproduced Party and the value of such Overproduction, calculated in accordance with Section 7.4 and 7.6 hereof. Thereafter, any
Underproduced Party may demand from such Overproduced Party in writing, within thirty (30) days after receipt of the Overproduced Party’s notice, a cash settlement of its Underproduction from the Balancing Area. The Operator shall be
notified of any such demand and of any cash settlement pursuant to this Section 13.2, and the Overproduction and Underproduction of each Party shall be adjusted accordingly. Any cash settlement pursuant to this Section 13.2 shall be paid
by the Overproduced Party before the closing of the transaction in which the Overproduced Party sells, assigns, exchanges or otherwise transfers its interest in a Balancing Area on the same basis as otherwise set forth in Sections 7.3 through 7.6
hereof, and shall bear interest at the rate set forth in Section 7.7 hereof, beginning the first day following the close of the Overproduced Parry’s sale, assignment, exchange or transfer of its interest in the Balancing Area for any
amounts not paid. Provided, however, if any Underproduced Party does not so demand such cash settlement of its Underproduction from the Balancing Area, such Underproduced Party shall look

  
 10 

	 	
exclusively to the assignee or other successor in interest of the Overproduced Party giving notice hereunder for the satisfaction of such Underproduced Party’s Underproduction in accordance
with the provisions of Section 13.1 hereof. Notwithstanding anything contained herein to the contrary, it is understood and agreed that any Party may call for a cash settlement as provided in Section 7: (i) at such time as the Balancing
Area is included in a unit which causes the change in the Percentage Interest of some or all of the Parties, and (ii) in the event that this Agreement covers a Federal Exploratory Unit, upon the expansion or revision of the participating area
which constitutes the Balancing Area. The right to call for a cash settlement hereunder shall be in addition to the rights provided for in Section 7.1. 

  

	 	13.3	The provisions of this Section 13 shall not be applicable in the event any Party mortgages its interest or disposes of its interest by merger, reorganization, consolidation or sale of substantially all of its
assets to a subsidiary or parent company, or to any company in which any parent or subsidiary of such Party owns a majority of the stock of such company. 

By signing the Operating Agreement to which this Exhibit “E” is attached, it is the intent of each signatory party to be bound by the terms and
conditions of this Gas Balancing Agreement. 

  
 11 

 EXHIBIT “F” 

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

                , 20    , between
                , as Operator, and 

                        
    , as Non-Operator(s) 
 MEMORANDUM OF JOINT OPERATING AGREEMENT 

 

											
	 STATE OF ______________
	  	 	        	) 	 				  	
		  	 	        	) 	 	 	    §:	 	  	
	 PARISH OF _____________
	  	 	        	) 	 				  	

 WHEREAS, SWEPI LP, as Operator, having a notice address of 200 N. Dairy Ashford, Houston, TX 77079, and
                        , having a notice address of
                    , as Non-Operator have entered into that certain Operating Agreement dated effective on
                    , covering oil and gas operations being conducted on those certain lands described in Exhibit “A” (the “Contract
Area”), attached hereto and made a part hereof, as said Exhibit may be amended from time to time; and 
 WHEREAS, Operator and Non-Operators desire to give third parties record notice of the existence of said Operating Agreement and of the rights and obligations of Operator and Non-Operators
thereunder. 
 NOW, THEREFORE, for and in consideration of One Dollar ($1.00) and other good and valuable consideration, the receipt and
sufficiency of which are hereby acknowledged, Operator and Non-Operators hereby stipulate and agree as follows: 

I. 
 The Operating
Agreement is on an A.A.P.L. form 610-1982 Model Form Operating Agreement, as amended by the parties, plus attachments. 

II. 
 Article VIC. grants
each party to the Operating Agreement the right to take in kind its proportionate share of all oil and gas produced from the Contract Area. Additionally, the parties have agreed to be bound by a volumetric Gas Balancing Agreement which is attached
as Exhibit “E” to the Operating Agreement. 
 III. 

Pursuant to Article VII.B., each Non-Operator mortgages to Operator, and grants to Operator a lien
upon, its oil and gas leasehold estates and “oil and gas interests”, as that term is defined in Article I.C. thereof, in the Contract Area, and grants to Operator a security interest in its share of oil or gas when extracted from the
Contract Area and its interest in all equipment located thereon to secure payment of its share of expense under the Operating Agreement (including costs of investigation, defenses and payment of any final judgment or settlement for

  
 1 

 
damages arising out of operations thereunder), together with interest thereon in accordance with the Operating Agreement, in addition to any other remedies available to Operator in law or
pursuant to the Operating Agreement. Upon default by a Non-Operator in the payment of its share of expense, without prejudice to any other rights and remedies, Operator shall have the right to collect from the
purchaser of production from the Contract Area the proceeds from the sale of such Non-Operator’s share of oil or gas produced and sold from the Contract Area until the amount owed by Non-Operator, including interest, has been paid. Each purchaser of oil and gas produced from the Contract Area shall be entitled to rely upon Operator’s written statement concerning the amount of any default.
Operator grants a like mortgage, lien and security interest to the Non-Operators to secure payment of Operator’s proportionate share of expense. 

If Operator pays a defaulting party’s share of any costs or expenses pursuant to Article VII. B. of the Operating Agreement, all other
parties to the Operating Agreement, including Non-Operators shall, upon being billed by Operator, contribute their proportionate share of all sums advanced by Operator for and on behalf of the defaulting
party. Such contributing parties shall in addition to any other right they may have hereunder receive a share of any interest in the Contract Area forfeited by the defaulting party as well as any percentage penalty recoupment from such defaulting
party. The share for each such contributing party shall be in proportion to its contribution. 
 IV. 

This Memorandum shall constitute a Financing Statement covering oil and gas extracted from the Contract Area to the extent that such oil and
gas is owned by a defaulting party under the Operating Agreement. This Mortgage and Financing Statement shall be filed for record in the real estate records of any county or parish in which the contract Area is situated and/or the Secretary of State
and shall be filed by Operator upon its own motion or upon the request of any Non-Operator. Each of the undersigned Non-Operators shall be considered as both a debtor,
to the extent that such party has failed to pay his or its share of expense, and as a secured party mortgagee. 
 V. 

In addition to the lien contained in Article VII.B. of the Operating Agreement, the Gas Balancing Agreement attached as Exhibit “E”
to the Operating Agreement provides that each overproduced party grants a lien to each Underproduced Party upon its leasehold interest and upon its interest in gas production and the proceeds therefrom, and upon its interest in material and
equipment, to the extent and so long as the Overproduced Party is overproduced, to secure its balancing obligations, both in kind and in cash, which lien shall be inferior and subject to the Operator’s lien as provided in Article VII.B. of the
parties Operating Agreement. 
 VI. 

Operator may, on behalf of all parties, terminate the effect of this Memorandum as to all or any portion of the Contract Area by recording a
full or partial release hereof. 

  
 2 

 VII. 

Any party requiring additional information concerning the rights and obligations of the parties under the Operating Agreement may contact the
Operator at the following address: 
 OPERATOR:  SWEPI LP 

                200 N. Dairy Ashford 

                Houston, TX 77079 

VIII. 
 This Memorandum
may be executed in any number of counterparts, each of which shall be considered an original for all purposes and shall be binding upon the heirs, successors and assigns of the parties. The Operator is hereby authorized to compile the signature and
notary pages from each of the counterparts in order to have one instrument containing signature and notarial acknowledgments for all parties for recording purposes. 
  

					
	 WITNESSES:
	  	 OPERATOR:

			
		  	 By:
	  	  

	  

Signature
	  	 Name:
	  	  

		  	 Its:
	  	  

			
	  

Printed Name
	  		  	
			
	  

Signature
	  		  	
			
	  

Printed Name
	  		  	
		
	 WITNESSES:
	  	 NON-OPERATOR:

			
		  	 By:
	  	  

	  

Signature
	  	  
 Name:
	  	  

		  	  
 Its:
	  	  

			
	  

Printed Name
	  		  	
			
	  

Signature
	  		  	
			
	  

Printed Name
	  		  	

  
 3 

 ACKNOWLEDGMENT 
  

											
	 STATE OF ______________
	  	 	        	)( 	 				 	
		  				 	 	    	)(ss. 	 	
	 COUNTY OF _____________
	  	 	        	)( 	 				 	

 BEFORE ME, the undersigned authority, on this day personally appeared
                    , as Attorney-in-Fact, of
                 known to me to be the person whose name is subscribed to the foregoing instrument, and acknowledged to me that he executed the same for purposes and
consideration therein expressed, individually and as the act and deed of said limited partnership and in the capacity therein stated. 

GIVEN UNDER MY HAND AND SEAL OF OFFICE this              day of
            , 2012. 
 MY COMMISSION EXPIRES: 

 
  

 

											
	 STATE OF ______________
	  	 	        	)( 	 				 	
		  				 	 	    	)(ss. 	 	
	 COUNTY OF _____________
	  	 	        	)( 	 				 	

 BEFORE ME, the undersigned authority, on this day personally appeared
                , as Attorney-in-Fact, of
                     known to me to be the person whose name is subscribed to the foregoing instrument, and acknowledged to me that he executed the
same for purposes and consideration therein expressed, individually and as the act and deed of said corporation and in the capacity therein stated. 

GIVEN UNDER MY HAND AND SEAL OF OFFICE this          day of
                    , 2012. 
 MY COMMISSION EXPIRES:

  
  

  
 4 

 FIRST AMENDMENT TO ARTICLE 10.1 OF THE DEFINITIVE AGREEMENT 

FOR THE DIVISION OF OPERATORSHIP 

FOR 
 BLACKSMITH —
MAGNOLIA AREA OF MUTUAL INTEREST 
 This amendment to Article 10.1 of the Definitive Agreement for the Division of Operatorship for
Blacksmith — Magnolia Area of Mutual Interest (the “Definitive Agreement”), dated effective for all purposes as of November 1, 2012, is by and between Encana Oil & Gas (USA) Inc. (“Encana”) a Delaware
corporation, whose address is 5851 Legacy Circle, Plano, Texas 75024, and SWEPT LP (“Shell”), a Delaware limited partnership whose address is P.O. Box 576, Houston, Texas 77001. Encana and Shell may hereinafter be referred to individually
as a “Party” and collectively as the “Parties”. 
 WHEREAS, the Parties entered into that certain Definitive Agreement
dated effective for all purposes as of November 1, 2012; 
 WHEREAS, the Parties desire to reduce the effective termination date of the
confidentiality provisions specified in Article 6 of the Definitive Agreement; and 
 WHEREAS, the Parties desire to amend Article 10.1 of
the Definitive Agreement to change the date of termination for Article 6 of the Definitive Agreement from July 26, 2014 to the earlier date of January 16, 2014. 

NOW, THEREFORE, in consideration of the premises and the mutual obligations and conditions contained herein, the receipt and sufficiency of
which is hereby acknowledged, the Parties agree as follows: 
 Article 10.1 of the Definitive Agreement is deleted in its entirety and
replaced with the following: 
 “10.1 Term of Definitive Agreement. Upon execution by both Parties, this Definitive Agreement shall be
effective for a “Term” beginning on the Effective Date and continuing until the earlier of (a) the point in time at which the Parties, or their respective successors or permitted assigns no longer have a joint interest in any
Leases; or (b) the point in time at which all Leases become Developed Acreage; provided that Article 6 shall continue in force and effect until January 16, 2014, after which date Article 6 shall terminate and shall be of no further force
or effect.” 
 [Signature Pages to Follow] 

  
 Page 1 of 2 

 IN WITNESS WHEREOF, this Amendment to Article 10.1 of the Definitive Agreement is executed on the
date(s) indicated below, but effective for all purposes as of January 16, 2014. 
  

							
	 ENCANA OIL & GAS (USA) INC.

 
	  	 SWEPI LP

 

	 By:
	 	  
	  	 By:
	  	  

	 Linda N. Featherstone
	  	 John D. Bentz

	
Attorney-in-Fact
	  	
Attorney-in-Fact

				
	 Date:
	 	  
	  	 Date:
	  	  

  
 Page 2 of 2EX-10.27

 Exhibit 10.27 

FORM OF 
 TAX RECEIVABLE
AGREEMENT 
 between 

VINE RESOURCES INC. 

and 
 THE PERSONS NAMED
HEREIN 
 Dated as of [            ], 2017 

 

 TABLE OF CONTENTS 

 

							
	 	 	 	  	Page	 
	 ARTICLE I DEFINITIONS
	  	 	1	 
	 Section 1.1
	 	 Definitions
	  	 	1	 
		
	 ARTICLE II DETERMINATION OF CERTAIN REALIZED TAX BENEFIT
	  	 	8	 
	 Section 2.1
	 	 Basis Adjustment
	  	 	8	 
	 Section 2.2
	 	 Tax Benefit Schedule
	  	 	9	 
	 Section 2.3
	 	 Procedures, Amendments
	  	 	9	 
		
	 ARTICLE III TAX BENEFIT PAYMENTS
	  	 	10	 
	 Section 3.1
	 	 Payments
	  	 	10	 
	 Section 3.2
	 	 No Duplicative Payments
	  	 	11	 
	 Section 3.3
	 	 Pro Rata Payments
	  	 	11	 
		
	 ARTICLE IV TERMINATION
	  	 	11	 
	 Section 4.1
	 	 Early Termination of Agreement; Breach of Agreement
	  	 	11	 
	 Section 4.2
	 	 Early Termination Notice
	  	 	13	 
	 Section 4.3
	 	 Payment upon Early Termination
	  	 	13	 
		
	 ARTICLE V SUBORDINATION AND LATE PAYMENTS
	  	 	14	 
	 Section 5.1
	 	 Subordination
	  	 	14	 
	 Section 5.2
	 	 Late Payments by the Corporate Taxpayer
	  	 	14	 
		
	 ARTICLE VI NO DISPUTES; CONSISTENCY; COOPERATION
	  	 	14	 
	 Section 6.1
	 	 Participation in the Corporate Taxpayer’s and OpCo’s Tax Matters
	  	 	14	 
	 Section 6.2
	 	 Consistency
	  	 	15	 
	 Section 6.3
	 	 Cooperation
	  	 	15	 
		
	 ARTICLE VII MISCELLANEOUS
	  	 	15	 
	 Section 7.1
	 	 Notices
	  	 	15	 
	 Section 7.2
	 	 Counterparts
	  	 	16	 
	 Section 7.3
	 	 Entire Agreement; No Third Party Beneficiaries
	  	 	16	 
	 Section 7.4
	 	 Governing Law
	  	 	16	 
	 Section 7.5
	 	 Severability
	  	 	16	 
	 Section 7.6
	 	 Successors; Assignment; Amendments; Waivers
	  	 	17	 
	 Section 7.7
	 	 Titles and Subtitles
	  	 	17	 
	 Section 7.8
	 	 Resolution of Disputes
	  	 	18	 
	 Section 7.9
	 	 Reconciliation
	  	 	18	 
	 Section 7.10
	 	 Withholding
	  	 	19	 
	 Section 7.11
	 	 Admission of the Corporate Taxpayer into a Consolidated Group; Transfers of Corporate
Assets
	  	 	19	 
	 Section 7.12
	 	 Confidentiality
	  	 	20	 
	 Section 7.13
	 	 Change in Law
	  	 	21	 

 TAX RECEIVABLE AGREEMENT 

This TAX RECEIVABLE AGREEMENT (this “Agreement”), is dated as of
[            ], 2017, and is between Vine Resources Inc., a Delaware corporation (including any successor corporation, the “Corporate Taxpayer”), Vine Investment LLC, a
Delaware limited liability company (“Vine Investment”), and each of the other persons from time to time party hereto (each a “TRA Party” and together the “TRA Parties”). 

RECITALS 
 WHEREAS,
the TRA Parties directly or indirectly hold membership interests (the “Units”) in Vine Resources Holdings LLC, a Delaware limited liability company (“OpCo”), which is classified as a partnership for United States
federal income tax purposes; 
 WHEREAS, the Units held by the TRA Parties may be exchanged for Class A common stock (the
“Class A Shares”) of the Corporate Taxpayer or other consideration, in accordance with and subject to the provisions of the LLC Agreement (as defined below) and the Exchange Agreement (as defined below); 

WHEREAS, OpCo and each of its direct and indirect Subsidiaries (as defined below), which are treated as a partnership for United States
federal income tax purposes, currently have and will have in effect an election under Section 754 of the United States Internal Revenue Code of 1986, as amended (the “Code”), for each Taxable Year (as defined below) in which a
taxable acquisition (including a deemed taxable acquisition under Section 707(a) of the Code) of Units by the Corporate Taxpayer from any of the TRA Parties for Class A Shares or other consideration pursuant to the Exchange Agreement (an
“Exchange”) occurs; and 
 WHEREAS, Exchanges by the TRA Parties and payments in respect of Tax savings related
to such Exchanges are expected to result in Tax savings for the Corporate Taxpayer, and the parties to this Agreement desire to enter into certain arrangements regarding the sharing of any such Tax savings realized by the Corporate Taxpayer as the
result of such Exchanges. 
 NOW, THEREFORE, in consideration of the foregoing and the respective covenants and agreements set forth
herein, and intending to be legally bound hereby, the parties hereto agree as follows: 
 ARTICLE I 

DEFINITIONS 

Section 1.1    Definitions. As used in this Agreement, the terms set forth in this Article I
shall have the following meanings (such meanings to be equally applicable to both the singular and plural forms of the terms defined). 

“Advisory Firm” means any law or accounting firm that is (i) nationally recognized as being an expert in Tax matters and
(ii) reasonably agreed to by the Corporate Taxpayer and Vine Investment. 

 “Advisory Firm Letter” shall mean (i) an attestation letter from an
Advisory Firm expressing an opinion on management’s assertion as to whether the Tax Benefit Schedule has been prepared, in all material respects, in accordance with this Agreement or (ii) another type of letter or report from the Advisory
Firm related to whether the information in the Tax Benefit Schedule, Early Termination Schedule and/or Exchange Basis Schedule has been prepared in a manner consistent with the terms of this Agreement. 

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly, through one or more
intermediaries, Controls, is Controlled by, or is under common Control with, such first Person.
 “Agreed Rate” means LIBOR
plus 100 basis points. 
 “Agreement” is defined in the Preamble to this Agreement. 

“Amended Schedule” is defined in Section 2.3(b) of this Agreement. 

“Basis Adjustment” means the adjustment to the tax basis of a Reference Asset under Sections 732, 734(b) and 1012 of the Code
(in situations where, as a result of one or more Exchanges, OpCo becomes an entity that is disregarded as separate from its owner for United States federal income tax purposes) or under Sections 734(b), 743(b) and 754 of the Code (in situations
where, following an Exchange, OpCo remains in existence as an entity treated as a partnership for United States federal income tax purposes) and, in each case, comparable sections of state and local tax laws, as a result of an Exchange and the
payments made pursuant to this Agreement. For the avoidance of doubt, the amount of any Basis Adjustment resulting from an Exchange of one or more Units (i) shall be determined without regard to any
Pre-Exchange Transfer of such Units and as if any such Pre-Exchange Transfer had not occurred and (ii) shall not include the portion of any Tax Benefit Payment
representing Imputed Interest. 
 “Beneficial Owner” of a security is a Person who directly or indirectly, through any
contract, arrangement, understanding, relationship or otherwise, has or shares: (i) voting power, which includes the power to vote, or to direct the voting of, such security; and/or (ii) investment power, which includes the power to
dispose of, or to direct the disposition of, such security. The terms “Beneficially Own” and “Beneficial Ownership” shall have correlative meanings. 

“Board” means the Board of Directors of the Corporate Taxpayer.

“Business Day” means any day other than a Saturday, Sunday or other day on which commercial banks are authorized or required
by applicable law to be closed in New York, New York or Houston, Texas. 
 “Change of Control” means the occurrence of any
of the following events after the IPO Date: 
 (i)    any Person (other than a Permitted Investor) or any
group of Persons acting together that would constitute a “group” for purposes of Section 13(d) of the Securities and Exchange Act of 1934, or any successor provisions thereto (excluding (a) a corporation or other entity owned,
directly or indirectly, by the stockholders of the 

  
 2 

 
Corporate Taxpayer in substantially the same proportions as their ownership of stock of the Corporate Taxpayer or (b) a group of Persons in which one or more Permitted Investors or
Affiliates of Permitted Investors, directly or indirectly hold Beneficial Ownership of securities representing more than 50% of the total voting power held by such group) is or becomes the Beneficial Owner, directly or indirectly, of securities of
the Corporate Taxpayer representing more than 50% of the combined voting power of the Corporate Taxpayer’s then outstanding voting securities; 

(ii)    the following individuals cease for any reason to constitute a majority of the number of directors
of the Corporate Taxpayer then serving: individuals who, on the IPO Date, constitute the Board and any new director whose appointment or election by the Board or nomination for election by the Corporate Taxpayer’s shareholders was approved or
recommended by a vote of at least two-thirds (2/3) of the directors then still in office who either were directors on the IPO Date or whose appointment, election or nomination for election was previously
so approved or recommended by the directors referred to in this clause (ii); 
 (iii)    there is
consummated a merger or consolidation of the Corporate Taxpayer with any other corporation or other entity, and, immediately after the consummation of such merger or consolidation, either (x) the members of the Board immediately prior to the
merger or consolidation do not constitute at least a majority of the members of the board of directors of the company surviving the merger or, if the surviving company is a Subsidiary, the ultimate parent thereof, or (y) the voting securities
of the Corporate Taxpayer immediately prior to such merger or consolidation do not continue to represent or are not converted into more than 50% of the combined voting power of the then outstanding voting securities of the Person resulting from such
merger or consolidation or, if the surviving company is a Subsidiary, the ultimate parent thereof; or 

(iv)    the shareholders of the Corporate Taxpayer approve a plan of complete liquidation or dissolution of
the Corporate Taxpayer or there is consummated an agreement or series of related agreements for the sale or other disposition, directly or indirectly, by the Corporate Taxpayer of all or substantially all of the Corporate Taxpayer’s assets,
other than such sale or other disposition by the Corporate Taxpayer of all or substantially all of the Corporate Taxpayer’s assets to an entity at least 50% of the combined voting power of the voting securities of which are owned by
shareholders of the Corporate Taxpayer in substantially the same proportions as their ownership of the Corporate Taxpayer immediately prior to such sale. 

Notwithstanding the foregoing, except with respect to clause (ii) and clause (iii)(x) above, a “Change of
Control” shall not be deemed to have occurred by virtue of the consummation of any transaction or series of integrated transactions immediately following which the record holders of the shares of the Corporate Taxpayer immediately prior to such
transaction or series of transactions continue to have substantially the same proportionate ownership in, and own substantially all of the shares of, an entity which owns, either directly or through a Subsidiary, all or substantially all of the
assets of the Corporate Taxpayer immediately following such transaction or series of transactions. 

  
 3 

 “Class A Shares” is defined in the Recitals of this
Agreement. 
 “Code” is defined in the Recitals of this Agreement. 

“Control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and
policies of a Person, whether through ownership of voting securities, by contract or otherwise. 
 “Corporate Taxpayer” is
defined in the Preamble to this Agreement; provided that the term “Corporate Taxpayer” shall include any company that is a member of any consolidated tax return of which Vine Resources Inc. is the common parent, where appropriate.

 “Corporate Taxpayer Return” means the federal and/or state and/or local Tax Return, as applicable, of the Corporate
Taxpayer filed with respect to Taxes of any Taxable Year. 
 “Cumulative Net Realized Tax Benefit” for a Taxable Year means
the cumulative amount of Realized Tax Benefits for all Taxable Years of the Corporate Taxpayer, up to and including such Taxable Year, net of the cumulative amount of Realized Tax Detriments for the same period. The Realized Tax Benefit and Realized
Tax Detriment for each Taxable Year shall be determined based on the most recent Tax Benefit Schedules or Amended Schedules, if any, in existence at the time of such determination. 

“Default Rate” means LIBOR plus 500 basis points. 

“Determination” shall have the meaning ascribed to such term in Section 1313(a) of the Code or similar provision of
state, foreign or local tax law, as applicable, or any other event (including the execution of IRS Form 870-AD) that finally and conclusively establishes the amount of any liability for Tax. 

“Dispute” has the meaning set forth in Section 7.8(a) of this Agreement. 

“Early Termination Date” means the date of an Early Termination Notice for purposes of determining the Early Termination
Payment. 
 “Early Termination Effective Date” means the date on which an Early Termination Schedule becomes binding
pursuant to Section 4.2. 
 “Early Termination Notice” is defined in
Section 4.2 of this Agreement. 
 “Early Termination Schedule” is defined in
Section 4.2 of this Agreement. 
 “Early Termination Schedule Objection Notice” has the meaning
set forth in Section 4.2 of this Agreement.
 “Early Termination Payment” is defined in
Section 4.3(b) of this Agreement. 
 “Early Termination Rate” means LIBOR plus 100 basis points. 

“Exchange” is defined in the Recitals of this Agreement. 

  
 4 

 “Exchange Agreement” means the Exchange Agreement, dated on or about the date
hereof, between the Corporate Taxpayer, OpCo and the holders of Units from time to time party thereto, as amended from time to time. 

“Exchange Basis Schedule” is defined in Section 2.1 of this Agreement. 

“Exchange Date” means the date of any Exchange. 

“Expert” is defined in Section 7.9 of this Agreement. 

“Hypothetical Tax Liability” means, with respect to any Taxable Year, the liability for Taxes of (i) the Corporate
Taxpayer and (ii) without duplication, OpCo, but only with respect to Taxes imposed on OpCo and allocable to the Corporate Taxpayer, in each case using the same methods, elections, conventions and similar practices used on the relevant
Corporate Taxpayer Return, but (a) using the Non-Stepped Up Tax Basis as reflected on the Exchange Basis Schedule including amendments thereto for the Taxable Year and (b) excluding any deduction
attributable to Imputed Interest in respect of an Exchange for the Taxable Year. For the avoidance of doubt, Hypothetical Tax Liability shall be determined without taking into account the carryover or carryback of any Tax item (or portions thereof)
that is attributable to a Basis Adjustment or Imputed Interest, as applicable. 
 “Imputed Interest” in respect of a TRA
Party shall mean any interest imputed under Section 1272, 1274 or 483 or other provision of the Code and any similar provision of state and local tax law with respect to the Corporate Taxpayer’s payment obligations in respect of such TRA
Party under this Agreement. 
 “Interest Amount” is defined in Section 3.1(b) of this Agreement. 

“IPO” means the initial public offering of Class A Shares by the Corporate Taxpayer. 

“IPO Date” means the closing date of the IPO. 

“IRS” means the United States Internal Revenue Service. 

“LIBOR” means during any period, an interest rate per annum equal to the one-year
LIBOR reported, on the date two days prior to the first day of such period, on the Telerate Page 3750 (or if such screen shall cease to be publicly available, as reported on Reuters Screen page “LIBOR01” or by any other publicly available
source of such market rate) for London interbank offered rates for United States dollar deposits for such period. 
 “LLC
Agreement” means, with respect to OpCo, the Amended and Restated Limited Liability Company Agreement of OpCo, dated as of [            ], 2017. 

“Market Value” shall mean the closing price of the Class A Shares on the applicable Exchange Date on the national
securities exchange or interdealer quotation system on which such Class A Shares are then traded or listed, as reported by the Wall Street Journal; provided, that if the closing price is not reported by the Wall Street
Journal for the applicable Exchange Date, then the Market Value shall mean the closing price of the Class A Shares on the Business 

  
 5 

 
Day immediately preceding such Exchange Date on the national securities exchange or interdealer quotation system on which such Class A Shares are then traded or listed, as reported by the
Wall Street Journal; provided, further, that if the Class A Shares are not then listed on a national securities exchange or interdealer quotation system, “Market Value” shall mean the cash consideration paid for
Class A Shares, or the fair market value of the other property delivered for Class A Shares, as determined by the Board in good faith. 

“Net Tax Benefit” is defined in Section 3.1(b) of this Agreement. 

“Non-Stepped Up Tax Basis” means, with respect to any Reference Asset at any time,
the Tax basis that such asset would have had at such time if no Basis Adjustments had been made. 
 “Payment Date” means
any date on which a payment is required to be made pursuant to this Agreement. 
 “Permitted Investors” means investment
funds managed by The Blackstone Group L.P. and any of their Affiliates and any TRA Party and any of its permitted transferees. 

“Person” means any individual, corporation, firm, partnership, joint venture, limited liability company, estate, trust,
business association, organization, governmental entity or other entity. 
 “Pre-Exchange
Transfer” means any transfer (including upon the death of a member) or distribution in respect of one or more Units (i) that occurs prior to an Exchange of such Units, and (ii) to which Section 743(b) or 734(b) of the Code
applies. 
 “Realized Tax Benefit” means, for a Taxable Year, the excess, if any, of the Hypothetical Tax Liability over
the actual liability for Taxes of (i) the Corporate Taxpayer and (ii) without duplication, OpCo, but only with respect to Taxes imposed on OpCo and allocable to the Corporate Taxpayer. If all or a portion of the actual liability for
such Taxes for the Taxable Year arises as a result of an audit by a Taxing Authority of any Taxable Year, such liability shall not be included in determining the Realized Tax Benefit unless and until there has been a Determination. 

“Realized Tax Detriment” means, for a Taxable Year, the excess, if any, of the actual liability for Taxes of (i) the
Corporate Taxpayer and (ii) without duplication, OpCo, but only with respect to Taxes imposed on OpCo and allocable to the Corporate Taxpayer, over the Hypothetical Tax Liability. If all or a portion of the actual liability for such Taxes for
the Taxable Year arises as a result of an audit by a Taxing Authority of any Taxable Year, such liability shall not be included in determining the Realized Tax Detriment unless and until there has been a Determination. 

“Reconciliation Dispute” is defined in Section 7.9 of this Agreement. 

“Reconciliation Procedures” is defined in Section 2.3(a) of this Agreement. 

“Reference Asset” means an asset that is held by OpCo, or by any of its direct or indirect Subsidiaries treated as a
partnership or disregarded entity (but only if such indirect Subsidiaries 

  
 6 

 
are held only through Subsidiaries treated as partnerships or disregarded entities) for purposes of the applicable Tax, at the time of an Exchange. A Reference Asset also includes any asset that
is “substituted basis property” under Section 7701(a)(42) of the Code with respect to a Reference Asset. 

“Schedule” means any of the following: (i) an Exchange Basis Schedule; (ii) a Tax Benefit Schedule; or
(iii) the Early Termination Schedule. 
 “Schedule Objection Notice” has the meaning set forth in Section
2.3(a) of this Agreement. 
 “Senior Obligations” is defined in Section 5.1 of this
Agreement. 
 “Subsidiaries” means, with respect to any Person, as of any date of determination, any other Person as to
which such Person, owns, directly or indirectly, or otherwise controls more than 50% of the voting power or other similar interests or the sole general partner interest or managing member or similar interest of such Person. 

“Tax Benefit Payment” is defined in Section 3.1(b) of this Agreement. 

“Tax Benefit Schedule” is defined in Section 2.2 of this Agreement. 

“Tax Return” means any return, declaration, report or similar statement required to be filed with respect to Taxes (including
any attached schedules), including, without limitation, any information return, claim for refund, amended return and declaration of estimated Tax. 

“Taxable Year” means a taxable year of the Corporate Taxpayer as defined in Section 441(b) of the Code or comparable
section of state or local tax law, as applicable (and, therefore, for the avoidance of doubt, may include a period of less than 12 months for which a Tax Return is made), ending on or after the IPO Date. 

“Taxes” means any and all United States federal, state, and local and foreign taxes, assessments or similar charges that are
based on or measured with respect to net income or profits, and any interest related to such Tax. 
 “Taxing Authority”
shall mean any domestic, federal, national, state, county or municipal or other local government, any subdivision, agency, commission or authority thereof, or any quasi-governmental body exercising any taxing authority or any other authority
exercising Tax regulatory authority. 
 “TRA Party” is defined in the Preamble to this Agreement. 

“TRA Party Representative” means, initially, Vine Investment, and thereafter, that TRA Party or committee of TRA Parties
determined from time to time by a plurality vote of the TRA Parties ratably in accordance with their right to receive Early Termination Payments hereunder if all TRA Parties had fully Exchanged their Units for Class A Shares or other
consideration and the Corporate Taxpayer had exercised its right of early termination on the date of the most recent Exchange. 

  
 7 

 “Treasury Regulations” means the final, temporary and proposed regulations under
the Code promulgated from time to time (including corresponding provisions and succeeding provisions) as in effect for the relevant taxable period. 

“Units” is defined in the Recitals of this Agreement. 

“Valuation Assumptions” shall mean, as of an Early Termination Date, the assumptions that in each Taxable Year ending on or
after such Early Termination Date, (1) the Corporate Taxpayer will have taxable income sufficient to fully utilize the deductions arising from the Basis Adjustments and the Imputed Interest during such Taxable Year or future Taxable Years
(including, for the avoidance of doubt, Basis Adjustments and Imputed Interest that would result from future Tax Benefit Payments that would be paid in accordance with the Valuation Assumptions) in which such deductions would become available,
(2) any loss carryovers generated by deductions arising from Basis Adjustments or Imputed Interest that are available as of the date of such Early Termination Date will be used by the Corporate Taxpayer on a pro rata basis from the date of such
Early Termination Date through the scheduled expiration date under applicable Tax law of such loss carryovers, (3) the United States federal, state and local income tax rates that will be in effect for each such Taxable Year will be those
specified for each such Taxable Year by the Code and other law as in effect on the Early Termination Date, (4) any non-amortizable assets will be disposed of on the fifteenth (15th) anniversary of
the applicable Basis Adjustment and any cash equivalents will be disposed of twelve (12) months following the Early Termination Date; provided, that in the event of a Change of Control, such
non-amortizable assets shall be deemed disposed of at the time of sale (if applicable) of the relevant asset in the Change of Control (if earlier than such fifteenth (15th) anniversary) and (5) if,
at the Early Termination Date, there are Units that have not been Exchanged, then each such Unit shall be deemed Exchanged for the Market Value of the Class A Shares and the amount of cash that would be transferred if the Exchange occurred on
the Early Termination Date. 
 “Vine Investment” is defined in the Preamble to this Agreement. 

ARTICLE II 

DETERMINATION OF CERTAIN REALIZED TAX BENEFIT 

Section 2.1    Basis Adjustment. Within ninety (90) calendar days after the filing
of the United States federal income tax return of the Corporate Taxpayer for each Taxable Year in which an Exchange has been effected by any TRA Party, the Corporate Taxpayer shall deliver to such TRA Party a schedule (the “Exchange Basis
Schedule”) that shows, in reasonable detail necessary to perform the calculations required by this Agreement (i) the Non-Stepped Up Tax Basis of the Reference Assets in respect of such TRA Party as of each applicable Exchange
Date, (ii) the Basis Adjustment with respect to the Reference Assets in respect of such TRA Party as a result of the Exchanges effected in such Taxable Year by such TRA Party, calculated in the aggregate, (iii) the period (or
periods) over which the Reference Assets in respect of such TRA Party are amortizable and/or depreciable and (iv) the period (or periods) over which each Basis Adjustment in respect of such TRA Party is amortizable and/or depreciable.

  
 8 

 Section 2.2    Tax Benefit Schedule. 

(a)    Tax Benefit Schedule. Within ninety (90) calendar days after the filing of the United States federal
income tax return of the Corporate Taxpayer for any Taxable Year in which there is a Realized Tax Benefit or a Realized Tax Detriment in respect of such TRA Party, the Corporate Taxpayer shall provide to such TRA Party a schedule showing, in
reasonable detail, the calculation of the Tax Benefit Payment in respect of such TRA Party for such Taxable Year (a “Tax Benefit Schedule”). Each Tax Benefit Schedule will become final as provided in Section 2.3(a) and may be
amended as provided in Section 2.3(b) (subject to the procedures set forth in Section 2.3(b)). 

(b)    Applicable Principles. Subject to Section 3.3(a), the Realized Tax Benefit or Realized Tax Detriment
for each Taxable Year is intended to measure the decrease or increase in the actual liability for Taxes of the Corporate Taxpayer for such Taxable Year attributable to the Basis Adjustments and Imputed Interest, determined using a “with and
without” methodology. Carryovers or carrybacks of any Tax item attributable to the Basis Adjustments and Imputed Interest shall be considered to be subject to the rules of the Code and the Treasury Regulations or the appropriate provisions of
U.S. state and local income and franchise tax law, as applicable, governing the use, limitation and expiration of carryovers or carrybacks of the relevant type. If a carryover or carryback of any Tax item includes a portion that is attributable to
any Basis Adjustments or Imputed Interest and another portion that is not, such portions shall be considered to be used in accordance with the “with and without” methodology. The parties agree that (i) all Tax Benefit Payments
attributable to the Basis Adjustments (other than Imputed Interest) will be treated as subsequent upward purchase price adjustments that have the effect of creating additional Basis Adjustments to Reference Assets for the Corporate Taxpayer in the
year of payment, (ii) as a result, such additional Basis Adjustments will be incorporated into the current year calculation and into future year calculations, as appropriate, and (iii) the actual liability for Taxes will take into account
the deduction of the portion of the Tax Benefit Payment that must be accounted for as Imputed Interest. 

Section 2.3    Procedures, Amendments. 

(a)    Procedure. Every time the Corporate Taxpayer delivers to a TRA Party an applicable Schedule under this
Agreement, including any Amended Schedule delivered pursuant to Section 2.3(b), and any Early Termination Schedule or amended Early Termination Schedule, the Corporate Taxpayer shall also (x) deliver to such TRA Party supporting
schedules and work papers, as determined by the Corporate Taxpayer or as reasonably requested by such TRA Party, providing reasonable detail regarding data and calculations that were relevant for purposes of preparing the Schedule and an Advisory
Firm Letter related to such Schedule and (y) allow such TRA Party reasonable access at no cost to the appropriate representatives at the Corporate Taxpayer and the Advisory Firm, as determined by the Corporate Taxpayer or as reasonably
requested by such TRA Party, in connection with a review of such Schedule. Without limiting the generality of the preceding sentence, the Corporate Taxpayer shall ensure that any Tax Benefit Schedule that is delivered to a TRA Party, along with any
supporting schedules and work papers, provides a reasonably detailed presentation of the calculation of the actual liability of the Corporate Taxpayer for Taxes and the Hypothetical Tax Liability, and identifies any material assumptions or operating
procedures or principles that were used for purposes of such calculations. An applicable Schedule or amendment thereto shall become final and binding on all parties thirty (30) calendar days from the date on which all relevant TRA Parties are
treated as 

  
 9 

 
having received the applicable Schedule or amendment thereto under Section 7.1 unless the TRA Party Representative (i) within thirty (30) calendar days from
such date provides the Corporate Taxpayer with notice of objection to such Schedule (“Schedule Objection Notice”) made in good faith or (ii) provides a written waiver of such right of any Objection Notice within the period
described in clause (i) above, in which case such Schedule or amendment thereto becomes binding on the date the waiver is received by the Corporate Taxpayer. If the Corporate Taxpayer and the TRA Party Representative, for any reason, are unable
to successfully resolve the issues raised in the Objection Notice within thirty (30) calendar days after receipt by the Corporate Taxpayer of an Objection Notice, the Corporate Taxpayer and the TRA Party Representative shall employ the
reconciliation procedures as described in Section 7.9 of this Agreement (the “Reconciliation Procedures”). The TRA Party Representative will fairly represent the interests of each of the TRA Parties and
shall timely raise and pursue, in accordance with this Section 2.3(a), any reasonable objection to a Schedule or amendment thereto timely communicated in writing to the TRA Party Representative by a TRA Party. 

(b)    Amended Schedule. The applicable Schedule for any Taxable Year may be amended from time to time by the
Corporate Taxpayer (i) in connection with a Determination affecting such Schedule, (ii) to correct inaccuracies in the Schedule identified as a result of the receipt of additional factual information relating to a Taxable Year after the
date the Schedule was provided to a TRA Party, (iii) to comply with the Expert’s determination under the Reconciliation Procedures, (iv) to reflect a change in the Realized Tax Benefit or Realized Tax Detriment for such Taxable Year
attributable to a carryback or carryforward of a loss or other tax item to such Taxable Year, (v) to reflect a change in the Realized Tax Benefit or Realized Tax Detriment for such Taxable Year attributable to an amended Tax Return filed for
such Taxable Year, or (vi) to adjust an applicable Exchange Basis Schedule to take into account payments made pursuant to this Agreement (any such Schedule, an “Amended Schedule”). The Corporate Taxpayer shall provide an
Amended Schedule to each TRA Party within thirty (30) calendar days of the occurrence of an event referenced in clauses (i) through (vi) of the preceding sentence. 

ARTICLE III 
 TAX
BENEFIT PAYMENTS 
 Section 3.1    Payments. 

(a)    Payments. Within thirty (30) calendar days after a Tax Benefit Schedule delivered to a TRA Party becomes
final in accordance with Section 2.3(a), the Corporate Taxpayer shall pay such TRA Party the Tax Benefit Payment determined pursuant to Section 3.1(b) that is allocable to such TRA Party. Each such Tax Benefit Payment shall be
made by wire transfer or ACH to the bank account previously designated by such TRA Party to the Corporate Taxpayer or as otherwise agreed by the Corporate Taxpayer and such TRA Party. For the avoidance of doubt, no Tax Benefit Payment shall be
made in respect of estimated tax payments, including, without limitation, federal estimated income tax payments. 

(b)    A “Tax Benefit Payment” in respect of a TRA Party for a Taxable Year means an amount, not less
than zero, equal to the sum of the portion of the Net Tax Benefit that 

  
 10 

 
is allocable to such TRA Party and the Interest Amount with respect thereto. For the avoidance of doubt, for Tax purposes, the Interest Amount shall not be treated as interest but instead shall
be treated as additional consideration for the acquisition of Units in Exchanges, unless otherwise required by law. Subject to Section 3.3(a), the “Net Tax Benefit” for a Taxable Year shall be an amount equal to the excess,
if any, of 85% of the Cumulative Net Realized Tax Benefit as of the end of such Taxable Year, over the total amount of payments previously made under clause (i) of the first sentence of Section 3.1(a) (excluding payments attributable to
Interest Amounts); provided, for the avoidance of doubt, that no such recipient shall be required to return any portion of any previously made Tax Benefit Payment. The “Interest Amount” shall equal the interest on the Net Tax
Benefit calculated at the Agreed Rate from the due date (without extensions) for filing the Corporate Taxpayer Return with respect to Taxes for such Taxable Year until the Payment Date under Section 3.1(a). The Net Tax Benefit and the
Interest Amount shall be determined separately with respect to each Exchange, on a Unit-by-Unit basis by reference to the resulting Basis Adjustment to the Corporate
Taxpayer. 
 Section 3.2    No Duplicative Payments. It is intended that the provisions of this
Agreement will not result in duplicative payment of any amount (including interest) required under this Agreement. The provisions of this Agreement shall be construed in the appropriate manner to ensure such intentions are realized. 

Section 3.3    Pro Rata Payments. 

(a)    Notwithstanding anything in Section 3.1 to the contrary, to the extent that the aggregate
Tax benefit of the Corporate Taxpayer with respect to the Basis Adjustments or Imputed Interest, as such terms are defined in this Agreement, is limited in a particular Taxable Year because the Corporate Taxpayer does not have sufficient taxable
income, the Net Tax Benefit for the Corporate Taxpayer shall be allocated among all parties eligible for a Tax Benefit Payment under this Agreement in proportion to the amounts of Net Tax Benefit that would have been allocated to each party if the
Corporate Taxpayer had sufficient taxable income so that there were no such limitation. 
 (b)    After taking into
account Section 3.3(a), if for any reason the Corporate Taxpayer does not fully satisfy its payment obligations to make all Tax Benefit Payments due under this Agreement in respect of a particular Taxable Year, then the Corporate Taxpayer and
the TRA Parties agree that no Tax Benefit Payment shall be made in respect of any Taxable Year until all Tax Benefit Payments in respect of prior Taxable Years have been made in full. 

ARTICLE IV 

TERMINATION 

Section 4.1    Early Termination of Agreement; Breach of Agreement. 

(a)    The Corporate Taxpayer may terminate this Agreement with respect to all amounts payable to the TRA Parties and with
respect to all of the Units held by the TRA Parties at any time by paying to each TRA Party the Early Termination Payment in respect of such TRA Party; provided, however, that this Agreement shall only terminate upon the receipt of the
Early Termination Payment by all TRA Parties, and provided, further, that the Corporate Taxpayer 

  
 11 

 
may withdraw any notice to execute its termination rights under this Section 4.1(a) prior to the time at which any Early Termination Payment has been paid. Upon payment of the Early
Termination Payment by the Corporate Taxpayer, none of the TRA Parties or the Corporate Taxpayer shall have any further payment obligations under this Agreement, other than for any (a) Tax Benefit Payment due and payable and that remains unpaid
as of the Early Termination Notice and (b) Tax Benefit Payment due for the Taxable Year ending with or including the date of the Early Termination Notice (except to the extent that the amount described in clause (b) is included in the
Early Termination Payment). If an Exchange occurs after the Corporate Taxpayer makes all of the required Early Termination Payments, the Corporate Taxpayer shall have no obligations under this Agreement with respect to such Exchange. 

(b)    In the event that the Corporate Taxpayer (1) breaches any of its material obligations under this Agreement,
whether as a result of failure to make any payment when due, failure to honor any other material obligation required hereunder or by operation of law as a result of the rejection of this Agreement in a case commenced under the Bankruptcy Code or
otherwise or (2) (A) shall commence any case, proceeding or other action (i) under any existing or future law of any jurisdiction, domestic or foreign, relating to bankruptcy, insolvency, reorganization or relief of debtors, seeking
to have an order for relief entered with respect to it, or seeking to adjudicate it a bankrupt or insolvent, or seeking reorganization, arrangement, adjustment, winding-up, liquidation, dissolution,
composition or other relief with respect to it or its debts or (ii) seeking an appointment of a receiver, trustee, custodian, conservator or other similar official for it or for all or any substantial part of its assets, or it shall make a
general assignment for the benefit of creditors or (B) there shall be commenced against Corporate Taxpayer any case, proceeding or other action of the nature referred to in clause (A) above that remains undismissed or undischarged for a
period of 60 days, all obligations hereunder shall be automatically accelerated and shall be immediately due and payable, and such obligations shall be calculated as if an Early Termination Notice had been delivered on the date of such breach and
shall include, but not be limited to, (1) the Early Termination Payment calculated as if an Early Termination Notice had been delivered on the date of a breach, (2) any Tax Benefit Payment due and payable and that remains unpaid as of the
date of a breach, and (3) except to the extent included in the Early Termination Payment, any Tax Benefit Payment in respect of any TRA Party due for the Taxable Year ending with or including the date of a breach; provided that procedures
similar to the procedures of Section 4.2 shall apply with respect to the determination of the amount payable by the Corporate Taxpayer pursuant to this sentence. Notwithstanding the foregoing, in the event that the
Corporate Taxpayer breaches this Agreement, each TRA Party shall be entitled to elect to receive the amounts set forth in clauses (1), (2) and (3) above or to seek specific performance of the terms hereof. The parties agree that the
failure to make any payment due pursuant to this Agreement within three months of the date such payment is due shall be deemed to be a breach of a material obligation under this Agreement for all purposes of this Agreement, and that it will not be
considered to be a breach of a material obligation under this Agreement to make a payment due pursuant to this Agreement within three months of the date such payment is due. Notwithstanding anything in this Agreement to the contrary, it shall not be
a breach of this Agreement if the Corporate Taxpayer fails to make any Tax Benefit Payment when due to the extent that the Corporate Taxpayer has insufficient funds to make such payment in the Corporate Taxpayer’s sole judgment exercised in
good faith; provided that the interest provisions of Section 5.2 shall apply to such late payment (unless the Corporate Taxpayer does not have sufficient cash to make such payment as a result of limitations imposed
by existing credit agreements to which OpCo or any of its Subsidiaries is a party, in which case Section 5.2 shall apply, but the Default Rate shall be replaced by the Agreed Rate). 

  
 12 

 (c)    In the event of a Change of Control, all obligations hereunder shall
be accelerated and such obligations shall be calculated as if an Early Termination Notice had been delivered on the date of such Change of Control and shall include, but not be limited to, (1) the Early Termination Payment calculated as if an
Early Termination Notice had been delivered on the effective date of such Change of Control, (2) any Tax Benefit Payment agreed to by the Corporate Taxpayer and the TRA Parties as due and payable but unpaid as of the Early Termination Notice,
and (3) except to the extent included in the Early Termination Payment, any Tax Benefit Payment in respect of any TRA Party due for the Taxable Year ending with or including the effective date of such Change of Control. In the event of a Change
of Control, any Early Termination Payment described in the preceding sentence shall be calculated utilizing the Valuation Assumptions and by substituting in each case the terms “date of a Change of Control” for an “Early Termination
Date.” 
 Section 4.2    Early Termination Notice. If the Corporate Taxpayer chooses to
exercise its right of early termination under Section 4.1 above, the Corporate Taxpayer shall deliver to each TRA Party notice of such intention to exercise such right (“Early Termination Notice”) and a schedule (the
“Early Termination Schedule”) specifying the Corporate Taxpayer’s intention to exercise such right and showing in reasonable detail the calculation of the Early Termination Payment(s) due for each TRA Party. Each Early
Termination Schedule shall become final and binding on all parties thirty (30) calendar days from the first date on which all TRA Parties are treated as having received such Schedule or amendment thereto under Section 7.1 unless the
TRA Party Representative (i) within thirty (30) calendar days after such date provides the Corporate Taxpayer with notice of objection to such Schedule made in good faith (“Early Termination Schedule Objection Notice”) or
(ii) provides a written waiver of such right of a Early Termination Schedule Objection Notice within the period described in clause (i) above, in which case such Schedule becomes binding on the date the waiver is received by the
Corporate Taxpayer. If the Corporate Taxpayer and the TRA Party Representative, for any reason, are unable to successfully resolve the issues raised in such notice within thirty (30) calendar days after receipt by the Corporate Taxpayer
of the Early Termination Schedule Objection Notice, the Corporate Taxpayer and the TRA Party Representative shall employ the Reconciliation Procedures, in which case such Schedule becomes binding ten (10) days after the conclusion of the
Reconciliation Procedures. The TRA Party Representative will fairly represent the interests of each of the TRA Parties and shall timely raise and pursue, in accordance with this Section 4.2, any reasonable objection to an Early
Termination Schedule or amendment thereto timely communicated in writing to the TRA Party Representative by a TRA Party. 

Section 4.3    Payment upon Early Termination. 

(a)    Subject to its right to withdraw any notice of Early Termination pursuant to Section 4.1(a), within three
(3) calendar days after an Early Termination Effective Date, the Corporate Taxpayer shall pay to each TRA Party an amount equal to the Early Termination Payment in respect of such TRA Party. Such payment shall be made by wire transfer or ACH to
the bank account previously designated by the TRA Party or as otherwise agreed by the Corporate Taxpayer and such TRA Party. 

  
 13 

 (b)    The “Early Termination Payment” in respect of a TRA
Party shall equal the present value, discounted at the Early Termination Rate as of the applicable Early Termination Effective Date, of all Tax Benefit Payments in respect of such TRA Party that would be required to be paid by the Corporate Taxpayer
beginning from the Early Termination Date and assuming that the Valuation Assumptions in respect of such TRA Party are applied. For the avoidance of doubt, no TRA Party shall be required to return any portion of any previously received Early
Termination Payment in the event of a later determination occurring after the date on which such Early Termination Payment was made. 

ARTICLE V 

SUBORDINATION AND LATE PAYMENTS 

Section 5.1    Subordination. Notwithstanding any other provision of this Agreement to the
contrary, any Tax Benefit Payment or Early Termination Payment required to be made by the Corporate Taxpayer to the TRA Parties under this Agreement shall rank subordinate and junior in right of payment to any principal, interest or other amounts
due and payable in respect of any obligations in respect of indebtedness for borrowed money of the Corporate Taxpayer and its Subsidiaries (“Senior Obligations”) and shall rank pari passu in right of payment
with all current or future unsecured obligations of the Corporate Taxpayer that are not Senior Obligations. To the extent that any payment under this Agreement is not permitted to be made at the time payment is due as a result of this Section
5.1 and the terms of agreements governing Senior Obligations, such payment obligation nevertheless shall accrue for the benefit of TRA Parties and the Corporate Taxpayer shall make such payments at the first opportunity that such payments are
permitted to be made in accordance with the terms of the Senior Obligations.
 Section 5.2    Late
Payments by the Corporate Taxpayer. The amount of all or any portion of any Tax Benefit Payment or Early Termination Payment not made to the TRA Parties when due under the terms of this Agreement, whether as a result of
Section 5.1 or otherwise, shall be payable together with any interest thereon, computed at the Default Rate (or, if so provided in Section 4.1(b), at the Agreed Rate) and commencing from the date on which such Tax Benefit Payment
or Early Termination Payment was first due and payable to the date of actual payment. 
 ARTICLE VI 

NO DISPUTES; CONSISTENCY; COOPERATION 

Section 6.1    Participation in the Corporate Taxpayer’s and OpCo’s Tax
Matters. Except as otherwise provided herein, and except as provided in the LLC Agreement, the Corporate Taxpayer shall have full responsibility for, and sole discretion over, all Tax matters concerning the Corporate Taxpayer and
OpCo, including without limitation the preparation, filing or amending of any Tax Return and defending, contesting or settling any issue pertaining to Taxes. Notwithstanding the foregoing, the Corporate Taxpayer shall notify the TRA Party
Representative of, and keep the TRA Party Representative reasonably informed with respect to, the portion of any audit of the Corporate Taxpayer and OpCo by a Taxing Authority the outcome 

  
 14 

 
of which is reasonably expected to materially affect the rights and obligations of a TRA Party under this Agreement, and shall provide to the TRA Party Representative reasonable opportunity to
provide information and other input to the Corporate Taxpayer, OpCo and their respective advisors concerning the conduct of any such portion of such audit; provided, however, that the Corporate Taxpayer and OpCo shall not be required
to take any action that is inconsistent with any provision of the LLC Agreement. 

Section 6.2    Consistency. The Corporate Taxpayer and the TRA Parties agree to report and cause to be
reported for all purposes, including federal, state and local Tax purposes, all Tax-related items (including, without limitation, the Basis Adjustments and each Tax Benefit Payment) in a manner consistent with
that contemplated by this Agreement or specified by the Corporate Taxpayer in any Schedule required to be provided by or on behalf of the Corporate Taxpayer under this Agreement unless otherwise required by law. The Corporate Taxpayer shall (and
shall cause OpCo and its other Subsidiaries to) use reasonable efforts (for the avoidance of doubt, taking into account the interests and entitlements of all TRA Parties under this Agreement) to defend the Tax treatment contemplated by this
Agreement and any Schedule in any audit, contest or similar proceeding with any Taxing Authority. 

Section 6.3    Cooperation. Each of the TRA Parties shall (a) furnish to the Corporate
Taxpayer in a timely manner such information, documents and other materials as the Corporate Taxpayer may reasonably request for purposes of making any determination or computation necessary or appropriate under this Agreement, preparing any Tax
Return or contesting or defending any audit, examination or controversy with any Taxing Authority, (b) make itself available to the Corporate Taxpayer and its representatives to provide explanations of documents and materials and such
other information as the Corporate Taxpayer or its representatives may reasonably request in connection with any of the matters described in clause (a) above, and (c) reasonably cooperate in connection with any such matter,
and the Corporate Taxpayer shall reimburse each such TRA Party for any reasonable and documented out-of-pocket costs and expenses incurred pursuant to this
Section 6.3. 
 ARTICLE VII 

MISCELLANEOUS 

Section 7.1    Notices. All notices, requests, claims, demands and other communications hereunder shall
be in writing and shall be deemed duly given and received (a) on the date of delivery if delivered personally, or by facsimile or email with confirmation of transmission by the transmitting equipment or (b) on the first Business Day
following the date of dispatch if delivered by a recognized next-day courier service. All notices hereunder shall be delivered as set forth below, or pursuant to such other instructions as may be designated in
writing by the party to receive such notice: 
 If to the Corporate Taxpayer, to: 

Vine Resources Inc. 
 5800
Granite Parkway, Suite 550 
 Plano, Texas 75024 

Attention:     John Regan, CFO 

Facsimile:     (877) 992-0118 

  
 15 

 With a required copy to: 

Blackstone Management Partners L.L.C. 

345 Park Avenue, 43rd Floor 

New York, New York 10154 

Attention:        Angelo Acconcia 

Facsimile:       (212) 201-2874 

and 
 Kirkland & Ellis
LLP 
 600 Travis Street, Suite 3300 

Houston, Texas 77002 

Attention:     Andrew Calder, P.C. 

                     William Benitez

 Facsimile:     (713) 835-3601 

Email:           andrew.calder@kirkland.com 

                      
wbenitez@kirkland.com 
 If to the TRA Parties, to the respective addresses, fax numbers and email addresses set forth in the records of
OpCo. 
 Any party may change its address, fax number or email by giving the other party written notice of its new address, fax number or
email in the manner set forth above. 
 Section 7.2    Counterparts. This Agreement may be executed
in one or more counterparts, all of which shall be considered one and the same agreement and shall become effective when one or more counterparts have been signed by each of the parties and delivered to the other parties, it being understood that
all parties need not sign the same counterpart. Delivery of an executed signature page to this Agreement by facsimile transmission shall be as effective as delivery of a manually signed counterpart of this Agreement. 

Section 7.3    Entire Agreement; No Third Party Beneficiaries. This Agreement constitutes the entire
agreement and supersedes all prior agreements and understandings, both written and oral, among the parties with respect to the subject matter hereof. This Agreement shall be binding upon and inure solely to the benefit of each party hereto and their
respective successors and permitted assigns, and nothing in this Agreement, express or implied, is intended to or shall confer upon any other Person any right, benefit or remedy of any nature whatsoever under or by reason of this Agreement. 

Section 7.4    Governing Law. This Agreement shall be governed by, and construed in accordance with,
the law of the State of Delaware. 
 Section 7.5    Severability. If any term or other provision of
this Agreement is invalid, illegal or incapable of being enforced by any law or public policy, all other terms and provisions 

  
 16 

 
of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any manner materially
adverse to any party. Upon such determination that any term or other provision is invalid, illegal or incapable of being enforced, the parties hereto shall negotiate in good faith to modify this Agreement so as to effect the original intent of the
parties as closely as possible in an acceptable manner in order that the transactions contemplated hereby are consummated as originally contemplated to the greatest extent possible. 

Section 7.6    Successors; Assignment; Amendments; Waivers. 

(a)    Each TRA Party may assign any of its rights under this Agreement to any Person as long as such transferee has
executed and delivered, or, in connection with such transfer, executes and delivers, a joinder to this Agreement, in form and substance reasonably satisfactory to the Corporate Taxpayer, agreeing to become a TRA Party for all purposes of this
Agreement, except as otherwise provided in such joinder. 
 (b)    No provision of this Agreement may be amended unless
such amendment is approved in writing by each of the Corporate Taxpayer and by the TRA Parties who would be entitled to receive at least two-thirds of the total amount of the Early Termination Payments payable
to all TRA Parties hereunder if the Corporate Taxpayer had exercised its right of early termination on the date of the most recent Exchange prior to such amendment (excluding, for purposes of this sentence, all payments made to any TRA Party
pursuant to this Agreement since the date of such most recent Exchange); provided, that no such amendment shall be effective if such amendment will have a disproportionate effect on the payments one or more TRA Parties receive under this
Agreement unless such amendment is consented in writing by such TRA Parties disproportionately affected who would be entitled to receive at least two-thirds of the total amount of the Early Termination
Payments payable to all TRA Parties disproportionately affected hereunder if the Corporate Taxpayer had exercised its right of early termination on the date of the most recent Exchange prior to such amendment (excluding, for purposes of this
sentence, all payments made to any TRA Party pursuant to this Agreement since the date of such most recent Exchange). No provision of this Agreement may be waived unless such waiver is in writing and signed by the party against whom the waiver is to
be effective. 
 (c)    All of the terms and provisions of this Agreement shall be binding upon, shall inure to the
benefit of and shall be enforceable by the parties hereto and their respective successors, assigns, heirs, executors, administrators and legal representatives. The Corporate Taxpayer shall require and cause any direct or indirect successor (whether
by purchase, merger, consolidation or otherwise) to all or substantially all of the business or assets of the Corporate Taxpayer, by written agreement, expressly to assume and agree to perform this Agreement in the same manner and to the same extent
that the Corporate Taxpayer would be required to perform if no such succession had taken place. 

Section 7.7    Titles and Subtitles. The titles of the sections and subsections of this Agreement are
for convenience of reference only and are not to be considered in construing this Agreement. 

  
 17 

 Section 7.8    Resolution of Disputes. 

(a)    Any and all disputes which are not governed by Section 7.9 and cannot be settled amicably,
including any ancillary claims of any party, arising out of, relating to or in connection with the validity, negotiation, execution, interpretation, performance or non-performance of this Agreement (including
the validity, scope and enforceability of this arbitration provision) (each a “Dispute”) shall be finally settled by arbitration conducted by a single arbitrator in Delaware in accordance with the then-existing Rules of Arbitration
of the International Chamber of Commerce. If the parties to the Dispute fail to agree on the selection of an arbitrator within thirty (30) calendar days of the receipt of the request for arbitration, the International Chamber of Commerce shall
make the appointment. The arbitrator shall be a lawyer admitted to the practice of law in the State of Delaware and shall conduct the proceedings in the English language. Performance under this Agreement shall continue if reasonably possible during
any arbitration proceedings. 
 (b)    Notwithstanding the provisions of paragraph (a), the Corporate Taxpayer may bring
an action or special proceeding in any court of competent jurisdiction for the purpose of compelling a party to arbitrate, seeking temporary or preliminary relief in aid of an arbitration hereunder, and/or enforcing an arbitration award and, for the
purposes of this paragraph (b), each TRA Party (i) expressly consents to the application of paragraph (c) of this Section 7.8 to any such action or proceeding, (ii) agrees that proof shall not be required
that monetary damages for breach of the provisions of this Agreement would be difficult to calculate and that remedies at law would be inadequate, and (iii) irrevocably appoints the Corporate Taxpayer as agent of such TRA Party for service of
process in connection with any such action or proceeding and agrees that service of process upon such agent, who shall promptly advise the TRA Party of any such service of process, shall be deemed in every respect effective service of process upon
the TRA Party in any such action or proceeding. 
 (c)    EACH PARTY HEREBY IRREVOCABLY SUBMITS TO THE JURISDICTION OF
COURTS LOCATED IN WILMINGTON, DELAWARE FOR THE PURPOSE OF ANY JUDICIAL PROCEEDING BROUGHT IN ACCORDANCE WITH THE PROVISIONS OF THIS SECTION 7.8, OR ANY JUDICIAL PROCEEDING ANCILLARY TO AN ARBITRATION OR CONTEMPLATED ARBITRATION ARISING OUT OF OR
RELATING TO OR CONCERNING THIS AGREEMENT. Such ancillary judicial proceedings include any suit, action or proceeding to compel arbitration, to obtain temporary or preliminary judicial relief in aid of arbitration, or to confirm an arbitration award.
The parties acknowledge that the fora designated by this paragraph (c) have a reasonable relation to this Agreement, and to the parties’ relationship with one another; and (ii) The parties hereby waive, to the fullest extent permitted
by applicable law, any objection which they now or hereafter may have to personal jurisdiction or to the laying of venue of any such ancillary suit, action or proceeding brought in any court referred to in the preceding paragraph of this
Section 7.8 and such parties agree not to plead or claim the same. 

Section 7.9    Reconciliation. In the event that the Corporate Taxpayer and the TRA Party
Representative are unable to resolve a disagreement with respect to the matters governed by Section 2.3 and Section 4.2 within the relevant period designated in this Agreement (“Reconciliation Dispute”), the
Reconciliation Dispute shall be submitted for determination to a nationally recognized expert (the “Expert”) in the particular area of disagreement mutually acceptable to both parties. The Expert shall be a partner, principal or
senior employee in a 

  
 18 

 
nationally recognized accounting or law firm, and unless the Corporate Taxpayer and the TRA Party Representative agree otherwise, the Expert shall not, and the firm that employs the Expert shall
not, have any material relationship with the Corporate Taxpayer or the TRA Party Representative or other actual or potential conflict of interest. If the Corporate Taxpayer and the TRA Party Representative are unable to agree on an Expert within
fifteen (15) calendar days of receipt by the respondent(s) of written notice of a Reconciliation Dispute, the Expert shall be appointed by the International Chamber of Commerce Centre for Expertise. The Expert shall resolve any matter relating
to the Exchange Basis Schedule or an amendment thereto or the Early Termination Schedule or an amendment thereto within thirty (30) calendar days and shall resolve any matter relating to a Tax Benefit Schedule or an amendment thereto
within fifteen (15) calendar days or as soon thereafter as is reasonably practicable, in each case after the matter has been submitted to the Expert for resolution. Notwithstanding the preceding sentence, if the matter is not
resolved before any payment that is the subject of a disagreement would be due (in the absence of such disagreement) or any Tax Return reflecting the subject of a disagreement is due, the undisputed amount shall be paid on the date prescribed by
this Agreement and such Tax Return may be filed as prepared by the Corporate Taxpayer, subject to adjustment or amendment upon resolution. The costs and expenses relating to the engagement of such Expert or amending any Tax Return shall
be borne by the Corporate Taxpayer except as provided in the next sentence. The Corporate Taxpayer and the TRA Party Representative shall bear their own costs and expenses of such proceeding, unless (i) the Expert adopts the
TRA Party Representative’s position, in which case the Corporate Taxpayer shall reimburse the TRA Party Representative for any reasonable out-of-pocket costs and expenses in such proceeding, or
(ii) the Expert adopts the Corporate Taxpayer’s position, in which case the TRA Party Representative shall reimburse the Corporate Taxpayer for any reasonable
out-of-pocket costs and expenses in such proceeding. Any dispute as to whether a dispute is a Reconciliation Dispute within the meaning of this
Section 7.9 shall be decided by the Expert. The Expert shall finally determine any Reconciliation Dispute and the determinations of the Expert pursuant to this Section 7.9 shall be binding on the Corporate
Taxpayer and each of the TRA Parties and may be entered and enforced in any court having jurisdiction. 

Section 7.10    Withholding. The Corporate Taxpayer shall be entitled to deduct and withhold from any
payment payable pursuant to this Agreement such amounts as the Corporate Taxpayer is required to deduct and withhold with respect to the making of such payment under the Code or any provision of U.S. federal, state or local or foreign tax law. To
the extent that amounts are so withheld and paid over to the appropriate Taxing Authority by the Corporate Taxpayer, such withheld amounts shall be treated for all purposes of this Agreement as having been paid to the Person in respect of whom such
withholding was made. 
 Section 7.11    Admission of the Corporate Taxpayer into a Consolidated Group;
Transfers of Corporate Assets. 
 (a)    If the Corporate Taxpayer is or becomes a member of an affiliated or
consolidated group of corporations that files a consolidated income tax return pursuant to Sections 1501 et seq. of the Code or any corresponding provisions of state or local law, then: (i) the provisions of this Agreement shall be applied with
respect to the group as a whole; and (ii) Tax Benefit Payments, Early Termination Payments and other applicable items hereunder shall be computed with reference to the consolidated taxable income of the group as a whole. 

  
 19 

 (b)    If any entity that is obligated to make a Tax Benefit Payment or Early
Termination Payment hereunder transfers one or more assets to a corporation (or a Person classified as a corporation for United States federal income tax purposes) with which such entity does not file a consolidated tax return pursuant to
Section 1501 of the Code or any corresponding provisions of state, local or foreign law (including as a result of any series of transactions or acts), such entity, for purposes of calculating the amount of any Tax Benefit Payment or Early
Termination Payment (e.g., calculating the gross income of the entity and determining the Realized Tax Benefit of such entity) due hereunder, shall be treated as having disposed of such asset in a fully taxable transaction on the date of such
contribution. The consideration deemed to be received by such entity shall be equal to the gross fair market value of the contributed asset. For purposes of this Section 7.11, a transfer of a partnership interest shall
be treated as a transfer of the transferring partner’s share of each of the assets and liabilities of that partnership. 

Section 7.12    Confidentiality. 

(a)    Each TRA Party and each of their assignees acknowledge and agree that the information of the Corporate Taxpayer is
confidential and, except in the course of performing any duties as necessary for the Corporate Taxpayer and its Affiliates, as required by law or legal process or to enforce the terms of this Agreement, such person shall keep and retain in the
strictest confidence and not disclose to any Person any confidential matters, acquired pursuant to this Agreement, of the Corporate Taxpayer and its Affiliates and successors, concerning OpCo and its Affiliates and successors or the members, learned
by the TRA Party heretofore or hereafter. This Section 7.12 shall not apply to (i) any information that has been made publicly available by the Corporate Taxpayer or any of its Affiliates (including as a result of
public reporting obligations), becomes public knowledge (except as a result of an act of the TRA Party in violation of this Agreement) or is generally known to the business community and (ii) the disclosure of information to the extent
necessary for the TRA Party to prepare and file its Tax Returns, to respond to any inquiries regarding the same from any taxing authority or to prosecute or defend any action, proceeding or audit by any taxing authority with respect to such returns.
Notwithstanding anything to the contrary herein, each TRA Party and each of their assignees (and each employee, representative or other agent of the TRA Party or its assignees, as applicable) may disclose to any and all Persons, without limitation
of any kind, the tax treatment and tax structure of the Corporate Taxpayer, OpCo and their Affiliates, and any of their transactions, and all materials of any kind (including opinions or other tax analyses) that are provided to the TRA Party
relating to such tax treatment and tax structure. 
 (b)    If a TRA Party or an assignee commits a breach, or threatens
to commit a breach, of any of the provisions of this Section 7.12, the Corporate Taxpayer shall have the right and remedy to have the provisions of this Section 7.12 specifically enforced by
injunctive relief or otherwise by any court of competent jurisdiction without the need to post any bond or other security, it being acknowledged and agreed that any such breach or threatened breach shall cause irreparable injury to the Corporate
Taxpayer or any of its Subsidiaries or the TRA Parties and the accounts and funds managed by the Corporate Taxpayer and that money damages alone shall not provide an adequate remedy to such Persons. Such rights and remedies shall be in addition
to, and not in lieu of, any other rights and remedies available at law or in equity. 

  
 20 

 Section 7.13    Change in Law. Notwithstanding anything
herein to the contrary, if, in connection with an actual or proposed change in law, a TRA Party reasonably believes that the existence of this Agreement could cause income (other than income arising from receipt of a payment under this Agreement)
recognized by the TRA Party upon any Exchange by such TRA Party to be treated as ordinary income rather than capital gain (or otherwise taxed at ordinary income rates) for United States federal income tax purposes or would have other material
adverse tax consequences to such TRA Party, then at the election of such TRA Party and to the extent specified by such TRA Party, this Agreement (i) shall cease to have further effect with respect to such TRA Party, (ii) shall not
apply to an Exchange by such TRA Party occurring after a date specified by such TRA Party, or (iii) shall otherwise be amended in a manner determined by such TRA Party, provided that such amendment shall not result in an increase in or
acceleration of payments under this Agreement at any time as compared to the amounts and times of payments that would have been due in the absence of such amendment. 

[The remainder of this page is intentionally blank] 

  
 21 

 IN WITNESS WHEREOF, the Corporate Taxpayer and each TRA Party have duly executed this Agreement
as of the date first written above. 
  

			
	CORPORATE TAXPAYER:
	
	VINE RESOURCES INC.
		
	By:	 	  

		 	Name:
		 	Title:
	
	TRA PARTIES:
	
	VINE RESOURCES HOLDINGS LLC
		
	By:	 	  

		 	Name:
		 	Title:
	
	[OTHER TRA PARTIES]
		
	By:	 	  

		 	Name:
		 	Title:

  
 Signature Page to Tax
Receivable Agreement

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