BEFORE CORPORATION COMMISSION OF THE STATE OF OKLAHOMA ORDER OF THE COMMISSION FINDINGS AND ORDER

Transcription

1 BEFORE CORPORATION COMMISSION OF THE STATE OF OKLAHOMA APPLICANT: L. E. JONES OPERATING, INC. RELIEF REQUESTED: POOLING LEGAL DESCRIPTION: E/2 NE/4 OF SECTION 36, TOWNSHIP 5 NORTH, RANGE 7 WEST, GRADY COUNTY, OKLAHOMA ) ) ) ) ) ) ) ) CAUSE CD: ORDER NO ORDER OF THE COMMISSION FINDINGS AND ORDER 1. Hearing Date and Place: This cause was heard on the initial hearing docket at 8:30 a.m. on the 12th day of August, 2014, Jim Thorpe Building, Oklahoma City, Oklahoma. 2. Appearances: Donald J. Chaffin, Attorney for the Applicant, L. E. Jones Operating, Inc. 3. Notice and Jurisdiction: The Commission hasjurisdiction of the subject matter herein and of the persons interested therein and has jurisdiction to enter this order as hereinafter set forth. Notice of the filing of application herein and of the time, date and place of hearing thereon was duly and properly given in all respects as required by law and the rules of the Commission. The Administrative Law Judge has examined the notices by publication, the publishers' affidavits of publication thereof and the affidavits of mailing filed herein. The Administrative Law Judge conducted a judicial inquiry into the sufficiency of Applicant's search to determine the names and whereabouts of respondents (if any) who were served by publication and based upon the evidence adduced, the Commission finds that Applicant has exercised due diligence and has conducted a meaningful search of reasonable available sources at hand. The Commission hereby approves the publication service given herein as meeting the statutory requirements, rules of the Commission and minimum standards of state and federal due process, and finds that notice has been given in all respects as required by law and the rules of the Commission. 4. Amendment: The Applicant requested and was allowed to dismiss from its application the following respondents, to-wit: Total E & P USA, Inc., successor in interest to: TotalfinalelfE&P USA, Inc., Total Exploration Production USA, Inc., Fina E & P, Inc., Petrofina Delaware, Inc., and Fina Oil & Chemical Co. (respondent no. 18); Arcadia Resources, LP (respondent no. 19); Chesapeake Exploration, LLC (respondent no. 20); Chesapeake Focus Corp. (respondent no. 21); Focus Energy, Inc. (respondent no. 22); SMR Development 93 Corp. (respondent no. 23); SMR Natural Gas Partners Corp. (respondent no. 24); SMR NGIF Corp. (respondent no. 25); SMR Production Management Co. (respondent no. 26); Duke Energy Co., LLC (respondent no. 27); Focus Energy Acquisition, Inc. (respondent no. 28); Focus Energy LLP (respondent no. 29); Larcbmont Resources, LLC (respondent no. 30); Millbrae Natural Gas Fund

2 CD FINAL ORDER Page L.P. (respondent no. 31); SMR Natural Gas Income Fund 1993 L.P. (respondent no. 32); SMR Natural Gas Partners 1994 L.P. (respondent no. 33); SMR Natural Gas Production, LLC (respondent no. 34); SMR Preferred Investors 1993 L.P. (respondent no. 35); SMR Preferred Partners Development Fund 1993 L.P. (respondent no. 36); Vitruvian H Woodford, LLC (respondent no. 37). 5. Relief Requested: To pool and adjudicate the rights and equities of the owners named in Exhibit "A", attached hereto, underlying the lands described in the caption hereof, for the common sources of supply described in paragraph 6 below, and to designate the Applicant or some other party as Operator. 6. Relief Granted and Election Period: The requested relief is granted and the rights and equities of all owners named in Exhibit "A", attached hereto, are hereby pooled, adjudicated, and determined in the lands described in the caption hereof for the common source of supply as indicated: Common Sources of Supply Fortuna Hoxbar Deese Size of Unit 40-acre (NE/4 NE/4) 80-acre standup 80-acre standup Order No Said owners named in Exhibit "A", attached hereto, must make one or any combination of the following elections within twenty (20) days from the date of this Order. Such costs to be allocated according to Copas Well Costs - Allocations and Adjustments (Formerly known as Bulletin 2), (footage method), shown on Exhibit "B" attached hereto and made a part hereof. In the event a respondent makes an election to accept the bonus provision, then that respondent shall include an executed Internal Revenue Service Form W-9 (the form being required for federal tax purposes). If the respondent fails to include the executed Form W-9, Operator will not issue a check until such information is provided. 6.1 Participation: To participate in the development of the unit and common sources of supply by agreeing to pay such owners proportionate part of the actual cost of the well or wells covered hereby and by paying, as set out below to operator (or providing evidence satisfactory to Operator of such party's ability to pay), such owner's proportionate part of the estimated completed for production cost thereof, within twenty-five (25) days from the date of this Order as follows: Completed as a dry hole - $1,060, Completed as a producer - $1,692, provided however, that in the event any owner elects to participate in said well by paying such owners proportionate part of the costs thereof and fails or refuses to pay such owner's proportionate

3 CD FINAL ORDER Page 3 part of the completed for production costs as set out herein within the period of time as prescribed in this Order, then such owner shall be deemed to have elected to accept the cash bonus and royalty consideration, as set out in paragraph 6.2 below; provided that if an owner's interest is burdened in excess of the royalty interest provided in paragraph 6.2 below, then, in that event, such owner shall be deemed to have accepted the cash bonus and excess or overriding royalty provided in paragraph 6.3 below; provided that if an owner's interest is burdened in excess of the royalty interest and excess or overriding royalty provided in paragraph 6.3 below, then, in that event, such owner shall be deemed to have accepted the consideration in lieu of cash as provided in paragraph 6.4 below. Thereupon, payment of such cash bonus, if any, should be made by operator within thirty-five (35) days after the last day on which such defaulting owner, under this Order, should have paid his proportionate part of such costs or should have made satisfactory arrangements for the payment thereof. 6.2 Cash Consideration: ($ per net mineral acre and a 1/8 total royalty) In lieu of participating in the working interest in such proposed unit well and the development of the separate common source of supply involved in this Cause in the land covered hereby, to elect to receive the sum of $ per net mineral acre owned by such owner or per net mineral acre covered by an oil and gas lease held by such owner, as the case may be, and the statutory 1/8th royalty as defined in S. 2001, Section 87. 1, the same to be delivered into the lease tank or into the pipeline to which any such well is connected, free and clear of all costs, expenses and risks incurred in or in connection with the drilling, completing and testing of any such well covered hereby; any owner electing this option shall deliver to Operator under this Order a net revenue interest of 87.50% of 8/8ths of the oil, casinghead gas, gas and gas condensate produced from any well covered by this Order, with such net revenue interest being determined by deducting from such owner's share of production all existing royalties (including the one provided for immediately above) and other non-operating or non-cost bearing burdens; and provided further, that such royalty provided for above and such net revenue interest of 87.50% of 8/8ths shall be proportionately reduced and payable only in the proportion that the number of net acres in the units covered by the drilling rights owned by such owner bears to the entire number of mineral acres in such units. Bonus provided in this subparagraph shall be paid by Applicant within thirty-five (35) days from the date of this Order, and when so paid shall be satisfaction in full for all rights and interests of such party in the entire drilling and spacing unit or units covered hereby, except for the normal 1/8th royalty interest as defined in 52 O.S. 2001, Section 87.1(e). Further provided, that in the event the owner's interest is subject to a total royalty, overriding royalty, or other burdens in excess 1/8th of 8/8ths, then such owner may not elect the consideration provided in this paragraph Cash Consideration: ($ per net mineral acre and a 3/16 total royalty) In lieu of participating in the working interest in such proposed unit well and the development of the separate common source of supply involved in this Cause in the land covered hereby, to elect to receive the sum of $ per net mineral acre owned by such owner or per net mineral acre covered by an oil and gas lease held by such owner, as the case may be, plus an excess royalty or overriding royalty (in addition to the statutory 1/8th royalty as defined in 52O.S. Supp. 2001, 87.1)

4 CD FINAL ORDER Page 4 in the maximum amount of 1/16th of 8/8ths of the oil, casinghead gas, gas and gas condensate produced from any well covered by this Order, the same to be delivered into the lease tanks or into the pipeline to which any such well is connected, free and clear of all costs, expenses and risks incurred in or in connection with the drilling, completing and testing of any such well covered hereby; provided, however, in the event such owner's interest is burdened by a royalty, overriding royalty or other burden on production in excess of the statutory 1/8th royalty as defined above (hereinafter referred to as "burdens"), such burdens shall be charged against such excess royalty or overriding royalty of I/ 16th of 8/8ths so that such excess royalty or overriding royalty shall be reduced by the amount of any such burdens; and therefore, any owner electing this option shall deliver to Operator under this Order a net revenue interest in an amount determined by deducting from such owner's share of production all existing royalties (including the one provided for immediately above) and other non-operating or non-cost bearing burdens in the oil, casinghead gas, gas and gas condensate produced from any well covered by this Order; and provided further, that such excess royalty or overriding royalty of 1/16th of 8/8ths, subject to the reduction provided for immediately above, and such net revenue interest calculated as set forth above shall be proportionately reduced and payable only in the proportion that the number of net mineral acres in the units covered by the drilling rights owned by such owner bears to the entire number of mineral acres in such units. Bonus provided in this subparagraph shall be paid by Applicant within thirtyfive (35) days from the date of this Order, and when so paid shall be satisfaction in full for all rights and interests of such party in the entire drilling and spacing unit or units covered hereby, except for any normal 1/8th royalty interest as defined in 52 O.S. 2001, 87.1(e) and excess or overriding royalty set out above. Further provided, that in the event the owner's interest is subject to a total royalty, overriding royalty, or other burdens in excess of 3/16th of 8/8ths, then such owner may not elect the consideration provided in paragraph Consideration in Lieu of Cash: (no cash and a 1/5th total royalty) In lieu of participating in the working interest in such proposed unit well and the development of the separate common source of supply involved in this Cause in the land covered hereby, or electing the option set forth in subparagraph 6.2 or 6.3 above, to elect to receive in lieu of any cash sum, an excess royalty or overriding royalty (in addition to the statutory 1/8th royalty as defined in 52 O.S. Supp. 2001, 87.1) in the maximum amount of 7.5% of 8/8ths of the oil, casinghead gas, gas and gas condensate produced from any well covered by this Order, the same to be delivered into the lease tanks or into the pipeline to which any such well is connected, free and clear of all costs, expenses and risks incurred in or in connection with the drilling, completing and testing of any such well covered hereby; provided, however, in the event such owner's interest is burdened by a royalty, overriding royalty or other burden on production in excess of the statutory 1/8th royalty as defined above (hereinafter referred to as "burdens"), such burdens shall be charged so that such excess royalty or overriding royalty shall be reduced by the amount of any such burdens; and provided further, that such excess royalty or overriding royalty of 7.5% of 8/8ths, subject to the reduction provided for immediately above, and such net revenue interest calculated as set forth above shall be proportionately reduced and payable only in the proportion that the number of net mineral acres in the units covered by the drilling rights owned by such owner bears to the entire number of mineral

5 CD FINAL ORDER Page 5 acres in such units, and when so paid shall be satisfaction in full for all rights and units covered hereby, except for any normal 1/8th royalty interest as defined in 52 O.S. 2001, 87.1(e) and excess or overriding royalty set out above. 6.5 Overburdened Interest Owners: The leasehold interests of Chevron USA, Inc. are burdened to a 25% net revenue which results in an overburdened interest not representative of fair market value because the additional overrides (created more than twenty years ago) are over and above the royalty contained in the Oil and Gas Lease. In the event Chevron USA, Inc. elects not to participate, they will forfeit their interest for a nominal consideration of $25.00 and Operator will assume the excess burden. 7. Failure to Elect: In the event any owner fails to elect within the time and in the manner as set out above, which of the alternatives set forth in paragraph 6 above, any such owner accepts, then such owner shall be deemed to have accepted the cash consideration and statutory 1/8th royalty as set out in paragraph 6.2; provided that if an owners interest has burdens that exceed 1/8th total royalty provided in paragraph 6.2 above, then, in that event, such owner shall be deemed to have accepted the cash consideration plus excess or overriding royalty as set out in paragraph 6.3; provided that if an owner's interest has burdens that exceed the 3/16th total royalty provided in paragraph 6.3 above, then, in that event, such owner shall be deemed to accepted the consideration in lieu of cash as provided in paragraph 6.4 above. In the event any owner elects to do other than participate in the development of the unit by paying his pro rata share of the costs thereof, or fails to make an election provided above, such owner shall be deemed to have relinquished unto Applicant, all of such owner's right, title, interest, or claim in and to the drilling and spacing units and common sources of supply covered by this Order, except for the normal 1/8th royalty interest, and share in production to which such owner shall be entitled by reason of any election hereunder. 8. Operator: NAME AND ADDRESS L. E. Jones Operating, Inc. P.O. Box 1185 Duncan, Oklahoma an owner of the right to drill in said drilling and spacing unit is designated Operator of the unit well and common source of supply covered hereby and all elections required in Paragraph 6 hereof should be communicated to said Operator, in writing, at the address above as required in this Order. All written elections must be mailed AND postmarked within the election period as set forth in Paragraph 6, above; provided such election may be mailed certified mail, with return receipt requested, in which event such certified election must be deposited in the post office within the election period set forth in Paragraph 6. That said Operator has a current plugging or financial statement on file with the Corporation Commission. 9. Commencement of Operations: That Operator shall commence operations for

6 CD FINAL ORDER Page 6 the drilling or other operations with respect to the initial well covered hereby within 180 days from the date of this Order and shall diligently prosecute the same to completion in a reasonably prudent manner, or this Order shall be of no force and effect, except as to the payment of bonus. That Operator may complete said well or wells in several separate zones being pooled. That all prospective zones may not necessarily be completed during the initial completion, but rather, may be done in a reasonably prudent time and manner. 10. Operator Lien: That Operator, in addition to any other rights provided herein, should have a lien, as set out in Title 52 O.S. Section 87.1(e), on the interest of any owner, subject to this Order, who has elected to participate in the well covered hereby by paying such owner's proportionate part of the costs hereof. 11. Special Finding: That Applicant exercised due diligence to locate each of the respondents subject to this applicant and that a bona fide effort was made to reach an agreement with each respondent and that the Applicant has not agreed with all such respondents in such drilling and spacing unit to pool their interest and to develop the drilling and spacing unit common sources of supply as a unit; that the Applicant has proposed the drilling of a well on said unit and to develop said common sources of supply; that the Operator, hereinabove named is an owner of the right to drill on said drilling and spacing unit and to develop and produce said common sources of supply. The granting of the relief requested by the Applicant shall include the intent of the Applicant to pool and adjudicate the rights and equities of the owner in the lands described herein as to those separate common sources of supply set forth above to be tested by the proposed well on a unit basis and not on a borehole basis for any well drilled as to the respective separate common sources of supply cited herein. That the election not to participate, or the deemed election not to participate as a cost bearing working interest in the proposed unit well, shall operate to foreclose the interest of the respondents as to elections to participate or not in any subsequent well that may at some indefinite time, if at all, be drilled within the subject lands to the common sources of supply covered by this Order as to such non-participating interest. That the initial election made by the respondents herein shall be binding as to the respondents, their assigns, heirs, representatives, agents or estates. 12. Elections as to Subsequent Wells: As to any subsequent wells proposed to be drilled under the terms of this Order, all parties electing to participate under paragraph 6.1 of this Order in the initial well drilled hereunder shall be entitled to written notice by certified mail of any proposal to spud an additional well under the terms of this Order. Such proposal shall contain a description of the surface and bottom hole location of the proposed well to be drilled, the estimated total depth, the proposed zone of completion, the estimated dry hole and completed costs for such well, and be accompanied by an Authorization for Expenditure executed by the proposing party. Thereafter, any respondent entitled to receive such notice shall make a written election to the proposing party within twenty (20) days from the date of receipt of such written proposal to either participate in the proposed additional well or to accept one or more of the options contained in Paragraphs 6.2, 6.3 or 6.4 of this Order (subject to the same restrictions in regard to overburdened interests as set out herein). Any respondent electing to participate in such subsequent well shall

7 CD FINAL ORDER Page 7 submit such respondent's proportionate part of the completed for production costs not more than twenty-five (25) days from the date of receipt of the initial notice proposing such well. Thereafter, in the event any party elects the cash consideration and royalty and/or excess royalty as provided in Paragraphs 6.2, 6.3 or 6.4, any bonus payable under such election shall be paid within thirty-five (3 5) days from the date of receipt of the initial well proposal. Furthermore, in the event any respondent entitled to notice in regard to the drilling of a subsequent well on the units subject to this Order fails to elect within the time limits as set out above in regard to such subsequent well, or having elected to participate in such subsequent well, fails to make timely payment of such owner's proportionate part of the completed for production costs as set out in the notice then such owner shall be subject to the same "deemed election" as provided in paragraph 7 of this Order. In the event any owner elects to do other than participate in such subsequently drilled well with all or a portion of such owner's interest, such owner shall be deemed to have relinquished unto the Applicant, all of such owner's non-participating right, title, interest, or claim in and to the drilling and spacing units and common sources of supply covered by this Order (other than the interest of such owner in any well drilled pursuant to this Order prior to the date of such election or deemed election) except for the normal 1/8th royalty interest, and other share in production to which such owner shall be entitled by reason of any election hereunder. Any proposed subsequent operation must be commenced within one hundred eighty (180) days from the date of the original proposal letter. If the subsequent well is not commenced within one hundred eighty (180) days, the well proposal will expire and all parties will be restored to the legal position they held prior to the proposal of such subsequent well. The designated Operator under the terms of this Order shall drill and operate any well drilled under the terms of this provision. The subsequent well provisions of this Order shall have no application to any deepening, sidetracking or reworking operation applicable to a well previously drilled under this Order. 13. Escrow Account: If any payment ofbonus due and owing under this Order cannot be made because the person entitled thereto cannot be located or is unknown, then said bonus shall be paid into an escrow account within ninety (90) days after this Order and shall not be commingled with any funds of the Applicant or Operator. Any royalty payments or other payments due to such person shall be paid into an escrow account by the holder of such funds. Responsibility for filing reports with the Commission as required by law and Commission rule as to bonus, royalty or other payments deposited into escrow accounts shall be with the applicable holder. Such funds deposited in said escrow accounts shall be held for the exclusive use and sole benefit of the person entitled thereto. It shall be the responsibility of the Operator to notify all other holders of this provision and of the Commission rules regarding unclaimed monies under pooling orders. 14. Parties or Interest Unknown: The attached Exhibit "A", is a listing of all parties or interests which are known or unknown or cannot be located, curative respondents, and each party's last known address, if available. 15. Filing of Affidavit: That the Applicant, or its Attorney, shall file with the Secretary of the Commission, within ten (10) days from the date of this Order, an Affidavit stating that a copy

8 CD FINAL ORDER Page 8 of said Order was mailed within three (3) days from the date of this Order to all parties pooled by this Order, whose addresses are known. 16. Applicant is proposing to develop the separate common sources of supply in the drilling and spacing unit covered hereby in the aggregate as a group or unit. The Applicant intends to evaluate and develop, as a reasonably prudent operator under the same or similar circumstances, all of the separate common sources of supply covered hereby as each will be penetrated in the initial unit well involved herein and valuable information regarding these separate common sources of supply will be obtained through the risk assumed and the expenses incurred in connection with such initial unit well. Furthermore, the bonus values testified to are based upon consummated oil and gas leases which cover all of the separate common sources of supply herein. Therefore, as set forth in the Application filed herein, Applicant believes, and the evidence presented herein shows, that it is appropriate that this pooling order treat all of the separate common sources of supply involved here in the aggregate as a group or unit. Applicant is the owner of the right to drill a well into, to produce hydrocarbons from and to appropriate production from the separate common sources of supply in the units involved herein. 17. Conclusion: The relief requested is necessary to prevent or to assist in preventing the various types of waste of oil or gas prohibited by statute or any of said wastes, and to protect or assist in protecting the correlative rights of interested parties. Such requested relief, as set forth above, should be granted and IT IS SO ORDERED. CORPORATION COMMISSION OF OKLAHOMA oó 6t4t7 BOB ANTHONY, Chairman /)( PATRICE DOUGLAS, Vice Chairman 0"~" 'V q~ DANA L. MURPHY, Commishond DONE AND PERFORMED THIS DAY OF AUGUST, BY ORDER OF THE COMMISSION: P L4QO, Commission Secretary

9 CD FINAL ORDER Page 9 REPORT OF THE ADMINISTRATIVE LAW JUDGE a The foregoing Findings and Order are the report and recommendations of the Administrative Law Judge. 4P VED... J¼ Maati \,Ad I Law Judge DZ/ 1 REVIEWER A o(-/- DATE APPRO D AS TO FORM AND CONTENT: Donald J. khfi(oba# 1587 Y:\CompgMyFiles\SOWs\ \9403 LE Jone\ Pool E2 NE Sec 36\ORDERwpd

10 CD FINAL ORDER Page 10 EXHIBIT "A" POOLING RESPONDENT LIST E/2 NE/4 of Section 36, Township 5 North, Range 7 West, Grady County, Oklahoma Respondents whose addresses are known: 6. David W. Potts Land & Exploration Co. P.O. Box 692 Ann G. Porter, Successor Trustee of Ardmore, OK the Charles P. Garvin Trust dated 11/04/ Dorothy Jane Garvin Gross 2734 Battleground Dr Berkeley Drive Murfreesboro, TN Tyler, TX SGH Enterprises, Inc., formerly Samson Hydrocarbons Co., formerly SNG Production Co., formerly Samson Natural Gas Co., formerly Grace Petroleum Corp., formerly Cleary Petroleum Corp. Attn: Russ Hargrove do Samson Resources Company Samson Plaza Two West Second Street Tulsa, OK BancFirst of Duncan Oklahoma, as trustee of the Mary Helen Dunaway Trust P0 Box 1488 Duncan, OK Charlotte E. & Knox L. Garvin Oil Interests LLC 1419 Green Berry Rd. Jefferson City, MO Chevron USA, Inc. Attn: Robert Endicott P.O. Box 2100 Houston, TX Farmer's National Company, Agent for BancFirst of Duncan, Oklahoma Trustee of the Mary Helen Dunaway Trust Attn: Rob Millikan 5110 S. Yale Ave., Suite 400 Tulsa, OK GB Energy, Inc. P.O. Box 1673 Chickasha, OK Hazelwood Production and Exploration Co., LLC 6801 Broadway Extension, Suite 320 Oklahoma City, OK Houston Garvin Revocable Trust Houston Garvin, Trustee 204 Jackson Circle Kerens, TX Lacy Saak 6503 N. Hillcrest Nichols Hills, OK 73116

11 CD FINAL ORDER Page Sara G. Meaders Living Trust 21. Ronald James Thigpen, Trustee 1920 Green Wing Drive 22. Granbury, TX and 23. Sara G. Meaders, Trustee 1132 Terrace View Drive 24. Fort Worth, TX Shelley Garvin Sigler, Successor Trustee u/tla known as the Harold T. 26. Garvin Revocable Trust 16 South 9th BancFirst Bldg. Duncan, OK Shelley Garvin Sigler, Successor 29. Trustee uta dated Aug. 5, 2011 of the Harold T. Garvin Revocable Trust 30. P.O. Box 467 Wimberley, TX Susan Garvin Long County Road 288 Tyler, TX Thomas R. Garvin Revocable Trust 34. Thomas Garvin, Trustee 3723 Lyles Dr. 35. Oxford, MS DISMISSED 37. Curative Respondents whose addresses are unknown: DISMISSED DISMISSED DISMISSED DISMISSED DISMISSED DISMISSED DISMISSED DISMISSED DISMISSED DISMISSED DISMISSED DISMISSED DISMISSED DISMISSED DISMISSED DISMISSED DISMISSED 19. DISMISSED 20. DISMISSED * All persons, if living, or if deceased, their respective unknown heirs, executors, administrators, devisees, trustees, successors, and assigns, and all corporations, if in existence, or if not in existence, their respective unknown officers, successors and assigns.

12 EXHIBiT B C onas Council of PetroleumjA000untant5 Societies Turning Energy Into Synergy ell Costs - All known as Bulletin 2) Accounting Guideline AG i. Publication/Revision Date - April 2003 Council Approved Copyright by the Council of Petroleum Accountants Societies. Inc. (COPAS)

13 AG-1 WELL COST - ALLOCATIONS AND ADJUSTMENTS CONTENTS I I!. NEW WELL COST APPORTIONMENTS A. ALLOCATION OF INTANGIBLE DRILLING COSTS...3 B. ALLOCATION OF TANGIBLE COSTS...8 C. SURFACE EQUIPMENT... D. DRILLING OVERHEAD Ill. WELL COST ADJUSTMENTS AND OTHER PAYMENTS - EXISTING WELLBORES...1O A. INTANGIBLE DRILLING COST COMPENSATION...11 B. COMPENSATION FOR SURFACE AND SUBSURFACE TANGIBLE EQUIPMENT...13 IV. ALLOCATION OF OPERATING EXPENSES A. DIRECT OPERATING COSTS B. INDIRECT OPERATING COSTS...15 V. WORKOVER OPERATIONS VI. A. ALLOCATION OF COSTS FOR WORKOVER OPERATIONS...15 B. DAMAGES...16 ABANDONMENT.W... A. PARTIAL ABANDONMENT-NON-PRODUCTIVE FORMATION...17 B. PARTIAL ABANDONMENT AFTER COMPLETION OF WELL IN MULTIPLE FORMATIONS C. ABANDONMENT IN ALL FORMATIONS VII GLOSSARY EXHIBIT... _23 This document has been reviewed by the Petroleum Accountants Societies through representation on the Council of Petroleum Accountants Societies. Jr is recommended that the contents of the document be used as a guide to joint interest operations accounting. The Council appreciates the contributions of the Petroleum Accountants Society of San Juan Basin for research and publication of this document.

14 FOREWORD The objective of this document is to provide guidance for two accounting issues: 1) equitable apportionment of costs and expenses for Downhole Commingled Wells and Multiple Completion Wells, and 2) equitable Well Cost A4us1xnents for certain situations. Refer to the COPAS publication 'Accounting For Unitlastloes" (Accounting Guideline AG -2) for guidance on investments adjustments pertaining to the formation of secondary recovery units, changes In federal exploratory units' participating areas, and changes In drilling or spacing unit sizes. The information contained in this document is intended to aid in understanding and applying atiocationsladjustments as well as negotiating future allocations/adjustments. No attempt has been made to include a suggested solution for all of the contingencies that may occur. It is also recognized that there may be more than one equitable solution to each situation. In these instances, alternate suggestions have been included. The Joint Operating Agreement, Accounting Procedure, and other relevant agreements for a particular property will always take precedence and should always be taken Into consideration.

15 I. INTRODUCTION Well cost apportionment and/or adjustment is needed when multiple formations with different ownership share a common weilbore. Cost and expense apportionment is necessary as a result of a Dowuhole Commingled Well or Multiple Completion Well. These types of wells are designed to economically benefit all the owners of different oil and/or gas producible formations by sharing in the costs and expenses of drilling and/or producing the different formations. Many of the goods acquired and services performed in connection with a Downhole Commingled Well and Multiple Completion Well directly benefit more than one formation. The costs of these goods and services that constitute Direct Charges need to be allocated to the formations that benefit This document is intended to provide guidance in allocating these costs to the formations or otherwise reaching agreement on an acceptable means of cost reapportionment. Specific topics addressed include cost sharing for drilling a new Downbole Commingled Well and Multiple Completion Well, and cost reapportionment that may be necessary when recompleting an existing weilbore. Even when the working interest ownership is the same in each of the objective formations in a Dowithole Commingled Well and Multiple Completion Well, the issues may eventually need to be addressed. This is necessary because the ownership or participating interest of a formation could change, thus giving rise to equity concerns in the allocation of operating expenses, workover costs and expenses, and abandonment expenses. However, this is not a common occurrence. The governing Operating Agreement or other agreement will often establish the situations giving rise to the need for an adjustment and may provide the method of calculating such adjustment See Exhibit 1. Approval for a Downhole Commingled Well and Multiple Completion Well must be obtained from working interest owners of all affected formations under the provisions of the Joint Operating Agreement or pursuant to regulations or order of the agency having jurisdiction, e.g., a force pooling order. The Operating Agreement may further establish whether all working interest owners or only the consenting parties need to approve the Multiple Completions. The proposal to complete the well in more than one formation should separately identify the cost and expense apportioned to each formation and should be submitted to the Non-Operators entitled to such notice pursuant to the terms of the Operating Agreement for approval. If the parties do not have a written agreement establishing the terms for allocating costs between zones, it is advisable to enter into such an agreement prior to performing the operation. A Cost Allocation Agreement (for a sample Cost Allocation Agreement see the Exhibits in the COPAS publication "Accounting For Uuitizations," formerly brown as Bulletin 11) can be made a part of the Joint Operating Agreement or it can be a separate, standalone agreement. Sometimes there are separate Operating Agreements for each formation, but the working interest owners of all the formations enter into a Cost Allocation Agreement that addresses the rights and obligations of each set of formation owners. Additionally, model form Operating Agreements may contain provisions 2

16 concerning certain events that call for cost allocation or an investment adjustment, and sets out how those adjustments should be calculated. See Exhibit I. Absent agreement or contractual provisions to the contrary, the scope of audits covering investment adjustments will be limited to verifying the accuracy of the Well Cost Adjustments and the cost and expense apportionment to the Operator's records, and the accuracy of the apportionment decimals. Compliance with Accounting Procedure requirements of the existing owner's Operating Agreements for these historical costs may not be a right of the new owner(s) but rather a right only of the original owners, which may or may not have been exercised. The parties may mutually agree to make such audit rights available to the new owner(s), but such rights should be clearly set forth in the Cost Allocation Agreement or have other contractual basis. II. NEW WELL COST APPORTIONMENT This Section addresses cost allocation for new wells being drilled with attempted completions in multiple formations. Well cost allocation may be necessary on new wells for a variety of reasons. Some of those reasons are: ownership could be different between the different objective formations, working interest ownership could be the same and the participating interest might be different for two or more formations. Well cost allocation may also be necessary to calculate a tax basis for each objective formation, to determine the basis from which to separately calculate each producible formation's depletion, to facilitate the calculation of finding costs for each formation, or for a special situation. For example, a special situation would be that under offshore Operating Agreements, it is common to allow a party to limit its participation to the base of the deepest known producible horizon, so that it is non-consent on the deeper drilling, i.e., exploratory tail. This event may give rise to a cost allocation, as described in Section ILA.3.d. Well costs are composed of the following cost categories: A. Intangible Drilling Costs B. Tangible Drilling Costs C. Surface Equipment D. Drilling Overhead Each of these categories can require a different allocation method to allocate associated costs. Whichever methodology is used, whether listed in this document or not, the intent is for the parties to select an allocation methodology that is equitable for a given situation. A. ALLOCATION OF INTANGIBLE DRILLING COSTS Intangible Drilling Costs (IDC) are defined as those expenditures that are nonrecoverable and, as such, have no salvage value. These costs are incurred in drilling and preparing wells for the production of oil and gas, and normally end at the first connection

17 beyond the Wellhead. For allocation purposes, Intangible Drilling Costs are categorized in the following three categories: 1. Shared Pre-drilling costs 2. Shared Drilling Costs 3. Formation Specific Costs A different allocation method is generally used for each of these Intangible Drilling Costs categories. 1. Shared Pre-drilling Costs Shared Pie-drilling Costs are IDC that arise from preparing a site for drilling, and they benefit all objective formations in a Multiple Completion Well and/or Dowuhole Commingled Well. Examples of Shared Pie-drilling Costs are site surveys, site preparation, right-of-way, surface damage payments. water supply wells, etc. These examples are not meant to be all-inclusive. Shared Pre-drilling Costs are typically allocated equally between all objective formations. The parties may agree to another equitable allocation method. 2. Shared Drilling Costs Shared Drilling Costs are IDC that are intended to benefit more than one formation in a Multiple Completion Well and/or Downhole Commingled Well. Examples of Shared Drilling Costs are rig costs, drilling water, field supervision, Drilling Overhead, etc. These examples are not meant to be all-inclusive. Allocating the Shared Drilling Costs to the objective formations is a two-step process. The first step is to associate the Shared Drilling Costs to the applicable Drilling Interval(s) and the second step is to allocate the applicable Drilling Interval's associated costs to the objective formations. There may be Intangible Drilling Costs that are treated as Formation-Specific Costs in one instance that are allocated as Shared Drilling Costs in other instances. The Operator should make reasonable efforts to charge Formation-Specific Costs to the benefiting formation, see sub-section 3 below, "Formation-Specific Costs." Listed below are descriptions and examples of several methodologies that may be used to allocate Shared Drilling Costs in a given situation. Whichever methodology is used, whether listed or not, the intent is for the parties to select an allocation methodology that is equitable for a given situation. Some equitable methods of allocating the Shared Drilling Costs are: a. Day Ratio: The first step is to determine the factor for allocating Shared Drilling Costs for the applicable Drilling Interval(s). The allocation factor is determined by a fraction of which the numerator is the number of days to drill through that Drilling Interval and the denominator is the total number of drilling days spent on the well. The total number of drilling days begins on the spud date and terminates when the completion election is made. Since rig costs are the largest expense and deeper drilling is generally slower than shallower drilling, the drilling Day Ratio may more closely align the costs with the Drilling Interval incurring the costs than will the Footage Ratio methodology. 4

18 Step two is to allocate each Drilling Intervals' costs to the objective formations. If using the Day Ratio methodology to allocate Formation-Specific Costs, Step two is not applicable because doing so would improperly result in the lower formation(s) being allocated a portion of the completion costs for the upper formation(s). The first Drilling Interval's costs are allocated equally to all formations with each owner standing a proportionate share based on its respective participating interest in each formation. The second Drilling Interval's costs are allocated equally to all objective formation(s) below the base of the first objective formation. This allocation continues through the last Drilling Interval. musuation: A party proposed drilling a well and completing it in three objective formations. The well was drilled in 75 days. If the time from spud date to the base of the first objective formation, the first Drilling Interval, took 27 days. all objective formations would receive 113 of of the Shared Drilling Costs. If the time required to drill from the base of the first objective formation to the base of the second objective formation, the second Drilling Interval, took 11 days, then 11/75 of the Shared Drilling Costs would be divided equally between the second and third formations. If the time required to drill from the base of the second objective formation to the base of the third objective formation, the third Drilling Interval, took 37 days, then of the Shared Drilling Costs would be charged to the third objective formation. b. Footage Ratio: The first step is to determine the cost allocation factors the applicable Drilling Interval(s). The factor used for the first Drilling Interval is determined by a fraction of which the numerator is the footage drilled from the surface to the base of the first objective formation and the denominator is the total footage drilled for the entire well. The factor used for the second Drilling Interval is determined by a fraction of which the numerator is the footage drilled from the base of the first objective formation to the base of the second objective formation and the denominator is the total footage drilled for the entire well. This process continues through the last objective formation. Each factor is multiplied by the costs to be allocated to determine the applicable Drilling Interval's costs. Rather than calculating a unique set of factors for each well, the parties may agree to use an average relative footage by objective formation for similar wells in an area. Step two is to allocate the applicable Drilling Intervals' costs to the objective formations. The first Drilling Interval's costs are allocated equally to all formations with each owner standing a proportionate share based on its respective participating interest in each formation. The second Drilling Interval's costs are allocated equally to the objective formation(s) below the base of the first objective formation. This allocation process continues through the last Drilling Interval. Rather than calculate a unique set of factors for each well, the parties may agree to use an average relative footage by objective formation for similar wells in an area. It should be noted that deeper drilling is usually slower, and thus more expensive than drilling the shallow portion of the well. Consequently, using Footage Ratios to allocate the costs does not take into account the additional expense involved in deeper drilling and therefore, may not align the costs with the Drilling Interval contributing the most costs.

19 Illustration: A party proposed drilling a well and completing it in three objective formations. The well was drilled to a total depth of 14,000 feet If the footage from surface through the first objective formation, the first Drilling Interval, is 12,000 feet, then 12,000/14,000 or 85.72% of the Shared Drilling Costs would be allocated equally to all objective formations. If the footage from the bottom of the first objective formation through the second objective formation, the second Drilling Interval, is 1,000 feet, then 1,000/14,000 or 7.14% of the Shared Drilling Costs would be allocated equally to the second objective formation and the deeper objective formation. If the footage from the bottom of the second objective formation through the third objective formation, the third and final Drilling Interval, is 1,000 feet, the third objective formation would be allocated 1,000/14,000 or 7.14% of the Shared Drilling Costs. c. Percentage of Historical Actual: The first step is to determine the factor for allocating Shared Drilling Costs to the applicable Drilling Interval(s). First, for each objective formation, take a recent historical sample of Shared Drilling Costs on a stand-alone basis, i.e., as a single completion well This method requires careful cost comparison between the same geographical area and the same time period as well as consideration of similar well specifications. The factor for a given Drilling Interval is determined by a fraction of which the numerator is the total historical shared expenditures to drill a stand-alone well in a given objective formation and the denominator is the total historical Shared Drilling Costs attributable to all wells in the historical sample. If the drilling operations experienced unusual circumstances that resulted in cost overruns, the cost overruns should be excluded from historical costs in calculating the factors. Likewise, the parties should reach an agreement that any unusual costs, inconsistent with the historical costs, will be borne by the formation or Drilling Interval giving rise to the costs. Step two is to allocate the applicable Drilling Intervals' costs to the objective formations. If using the Percentage of Historical Actual methodology to allocate Formation-Specific Costs, Step two is not applicable because it improperly results in the lower formation(s) being allocated a portion of the completion costs for the upper formation(s). The first Drilling Interval's costs are allocated equally to all formations with each owner standing a proportionate share based on their respective participating interest in each formation. The second Drilling Interval's costs are allocated equally to the objective formation(s) below the base of the first objective formation. This allocation process continues through the last Drilling Interval Illustration: A well is completed in three objective formations. Historical Shared Drilling Costs for stand-alone wells completed or attempted to be completed in three objective formations for the three Drilling Intervals are $2,000, $4,000 and $6,000 respectively. The allocation of the Shared Drilling Costs is as follows: $2,000 for Drilling Interval one is allocated equally to all three objective formations (1/3 of $2,000 to each), $4,000 for Drilling Interval two is allocated equally to the second and third objective formations (1/2 of $4,000 to each), and $6,000 for Drilling Interval three is allocated to the third objective formation. 11

20 D Exploratory Tall: This allocation method is used in special situations. For example, under offshore Operating Agreements, it is common to allow a party to limit its participation to the base of the deepest bown productive horizon, so that it is non-consent on the deeper drilling, i.e., exploratory tail. This event may give rise to a cost allocation. There are a variety of ways to allocate the costs of a well with an exploratory tail. The most common way is for the parties participating in the shallow formation to pay the entire well costs to the base of the shallow formation, while the party or parties wishing to test the deep formation pay(s) loo'/o of the costs below the shallow formation. However, the parties may agree to use any of the other methods provided in this document 3. Formation-Specific Costs Formation-Specific Costs are intended to benefit a specific formation in a Downhole Commingled Well or Multiple Completion Well and do not benefit another objective formation. Examples of Formation-Specific Costs are electric logs, drill stem tests, coring, shooting, acidizing, perforating, squeeze jobs, etc. These examples are not meant to be all-inclusive. Formation-Specific Costs, in the vast majority of cases, are charged directly to the associated formation. These Formation-Specific Costs are identified from a detailed analysis of actual expenditures. This would involve utilizing the well completion records as well as accounting records. This method is time-consuming and subject to getting good information from operations personnel. More importantly, this method of charging Formation-Specific Costs requires information from the vendor regarding what formation it worked on, as well as additional invoice coding. If the parties believe the additional information gathering creates greater opportunity for errors, then the parties may wish to consider another way to collect and allocate these costs on an equitable basis, particularly if there is an allocation basis that will reasonably match the cost to the formations. The Operator should make reasonable efforts to charge Formation-Specific Costs to the benefiting formation. While this may require additional administrative effort in invoice processing, the objective is to assign costs to specific formations whenever possible because it is the most equitable way to ensure that each owner pays its respective share of the costs attributable to its formation. Charging as many Formation-Specific Costs to the benefiting formation as possible, rather than using an allocation method, will generally result in fewer audit exceptions, unless the parties specifically agreed to use an allocation method. There may be costs that are treated as Formation-Specific Costs in one instance that are allocated as Shared Drilling Costs in other instances. For example, drill bits often are used to drill through more than one Drilling Interval, because the Operator does not stop to change the drill bit at the base of each Drilling Interval. Therefore, drill bit charges would be treated as Shared Drilling Costs and would be allocated. On the other hand, if one Drilling Interval uses an expensive, or otherwise specialized drill bit, it would result in a more equitable cost apportionment to charge the more expensive bit to the formation(s) that receive(s) the benefit Other examples of costs that can either be allocated or treated as Formation-Specific Costs are mud, chemicals, or steerable motors to drill horizontal portions of the well. If the mud or chemicals used in the respective Drilling Intervals have little variation, these costs