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CO 321
Conservation Order Cover Pa~ge XHVZE This page is required for administrative purposes in managing the scanning process. It marks the extent of scanning and identifies certain actions that have been taken. Please insure that it retains it's current location in this file. ,._~,5:~-~ - Conservation Order Category Identifier Organizing RESCAN [] Color items: [] Grayscale items: [] Poor Quality Originals: [] Other: NOTES: DIGITAL DATA [] Diskettes, No. [] Other, No/Type OVERSIZED (Scannable with large plotter/scanner) [] Maps: [] Other items OVERSIZED (Not suitable for plotter/scanner, may work with 'log' scanner) [] Logs of various kinds [] Other ' BY: .... ~¢MARIA Scanning Preparation TOTAL PAGES ~ - ProdUction Scanning Stage I PAGE COUNT FROM SCANNED DOCUMENT: PAGE COUNT MATCHES NUMBER IN SCANNING PREPARATION: ~ YES NO BY: Stage 2 IF NO IN STAGE 1, PAGE(S) DISCREPANCIES WERE FOUND: YES ~ NO / (SCANNING IS COMP~INT UNLESS SPECIAL ATTENTION IS REQUIRED ON AN INDIVIDUAL PAGE BASIS DUE TO QUALITY, GRAYSCALE OR COLOR IMAGES) General Notes or Comments about this Document: 5/21/03 ConservOrdCvrPg.wpd STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 Porcupine Drive Anchorage Alaska 99501-3192 Re~ Show cause as to whether any action ) is necessary to prevent or to assist in ) preventing waste, to insure a greater ) ultimate recovery of oil and gas, or ) to protect correlative rights of persons ) owning interests in the Pt. Mclntyre ) oil field. ) Conservation Order No. 321 Oil and Gas Conservation Commission Pt. Mclntyre oil field October 8, 1993 IT APPEARING THAT: The Alaska Oil and Gas Conservation Commission upon its own motion scheduled a public hearing for presentation of show cause testimony as to whether any action is necessary to prevent or to assist in preventing waste, to insure a greater ultimate recovery of oil and gas, or to protect correlative rights of persons owning interests in the Pt. McIntyre oil field. . 'Notice of hearing was published in the Anchorage Daily News on August 7, 1.993 pursuant to 20 ACC 25.540. . The hearing was held on September 9, 1993 in the Z. J. Loussac Library, Municipal Assembly Chambers, 3600 Denali Street, Anchorage, Alaska. . Testimony was presented by representatives of ARCO Alaska Inc, BP Exploration (Alaska) linc, Exxon Corporation and the State Department of Natural Resources Division of Oil and Gas. FINDINGS: ARCO Alaska Inc. has been designated operator of the Pt. Mclntyre oil field by working interest owners ARCO Alaska Inc., BP Exploration (Alaska) Inc., and Exxon Corporation. . Conservation Order No. 317, which prescribes pool rules for development of the Pt. Mclntyre oil field, concluded that the unitized management, operation and further development of the Pt. Mclntyre and Stump Island oil pools is reasonably Conservation Ordeal' No. 321 October 8, 1993 Page 2 o . o . . . o necessary to effectively carry on pressure maintenance and enhanced oil recovery operations to maximize ultimate recovery. The State of Alaska and the working interest owners have not agreed to integrate their interests to provide for the unitized management, development and operation for all of the proposed area of development for the Pt. Mclntyre oil field. ARCO Alaska Inc. and BP Exploration (Alaska) Inc. filed a joint petition dated September 8, 1993 requesting the Commission to order expansion of the Prudhoe Bay Unit to include a proposed Pt. McIntyre Participating Area. ARCO Alaska Inc. and BP Exploration (Alaska) Inc., testified that a compulsory unitization hearing is appropriate to prevent waste, insure greater ultimate recovery and protect correlative rights. Exxon Corporation testified in support of the joint petition to expand the Prudhoe Bay Unit to include a Pt. Mclntyre Participating Area. Although still participating in ongoing negotiations as observers, ARCO Alaska Inc. and BP Exploration (Alaska) Inc. believe that an impasse has been reached in efforts to voluntarily integrate the interests of the working interest owners and the State of Alaska. The State of Alaska, through its Department of Natural Resources, testified that voluntary efforts to unitize the Pt. Mclntyre oil field are still underway. Exxon Corporation testified that voluntary efforts to unitize the Pt. Mclntyre oil field are still underway. CONCLUSION: The question as to whether any action is necessary by the Commission, acting on its own motion, to prevent or to assist in preventing waste, to insure a greater ultimate recovery of oil and gas, or to protect correlative rights of persons owning interests in the Pt. Mclntyre oil field is rendered moot by the petition of ARCO Alaska Inc. and BP Exploration (Alaska) Inc. NOW, THEREFORE, IT IS ORDERED that the application of ARCO Alaska Inc. and BP Exploration (Alaska) Inc. filed pursuant to AS 31.05 for the stated purpose of forming the Pt. McIntyre participating area and expanding the Prudhoe Bay Unit area is accepted Conservation October 8, 1993 Page 3 No. 321 and a hearing on this matter was held in a manner prescribed by the Commission under its statutory and regulatory authorities within 30 days of proper notice. DONE at Anchorage, Alaska and dated October 8, 1993. David~. Johnston Alaska O~ Chairman 2onservation Commission Tu~kerman Babcock, Commissioner Alaska Oil and Gas Conservation Commission ~dU2sS~la1 ~il aDn°~lgGl~Sss' C°mmi/S~conserv~io°nne~ommission AS 31.05.080 provides that within 20 days after receipt of written notice of the entry of an order, a person affected by it may file with the Commission an application for rehearing. A request for rehearing must be received by 4:30 PM on the 23rd day following the date of the order, or next working day ifa holiday or weekend, to be timely filed. The Commission shall grant or refuse the application in whole or in part within 10 days. The Commission can refuse an application by not acting on it within the 10-day period. An affected person has 30 days from the date the Comnfission refuses the application or mails (or otherwise distributes) an order upon rehearing, both being the final order of the Cmmnission, to appeal the decision to Superior Court. Where a request for rehearing is denied by nonaction of the Commission, the 30-day period for appeal to Superior Court runs from the date on which the request is deemed denied (i.e., 10th day after the application for rehearing was filed). Notice of Public Hearing Cancellation STATE OF ALASKA Alaska Oil and Gas Conservation Commission Re~ The application of ARCO Alaska, Inc. and BP Exploration (Alaska) Inc. filed pursuant to AS 31.05 for the stated purpose of forming the Pt. Mclntyre participating area and expanding the Prudhoe Bay Unit area. NOTICE IS HEREBY GIVEN THAT ARCO Alaska, Inc. and BP Exploration (Alaska) Inc. have withdrawn their petition requesting compulsory expansion of the Pmdhoe Bay Unit to include the proposed Pt. McIntyre participating area. Therefore, the Commission hereby cancels the public hearing that was scheduled for November 2, 1993 to hear testimony regarding the petition. Russell A. Douglass Commissioner Alaska Oil and Gas Conservation Commission Published October 21, 1993 8176 STOF0330 08-5752 $77.90 STATE OF ALASKA, ) THIRD JUDICIAL DISTRICT. ) Eva M. Kaufmann being first duly sworn on oath deposes and says that he/she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on 9/24, 1993 and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount o1: the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Subscribed and sworn to be~")ore me this ...~.... day of ....~......~... ...... the State of Alaska. Third Division. Anchorage. Alaska MY CO6/W~ISSION EXPIR£S ';~- Nolice Of Public Heal?,g. Alaska 011 and Gas : .=Conservation 'Commission, Re:' 'T~e a~,icat~on ~ Ae Alaska, Inc.~and BP Explora- tion (Alaska), Inc. fil~ pu~u- ant to AS 31.~ for the stat~ ' pu~ ~ ~rmlng the ~. Mclntyre pa~lcipating area and 'ex~an~ing ~the Pru~ Bay .Unlt~area. /.. :'.~.~ ~ ~:~. :'~":~ ,.:..:...~,? ?~ .~-'~ , NOTICE IS HEREBY GIV' EN THAT 'ARCO Alaska, Inc. and BP Exploration(Alaska), Inc;' have ~tition~ the Alaska Oil ..and ~ Gas ~; Conservation Comml~ion under AS 31.~.110 to, or~r formation. M a.H. Mclntyre:'partlcipating area. and 'expansion ~ the..Prudh~ Bay Unit area: in accordance with a Plan of Unitization sub- mi~ed with'thelr,'~titlon, and that a hearing on.this ~tition ~ will ~ held In .:conformance I with ~ AAC'25.~.at theZ..J. ~' Loussac"~ Libra ry;~;'Assembly-, l'Cham~, ~ Denali Strut, [ Anchoragej.: Alaska, ,at 9:~ [.~, on :Novem~r 2,'.1~.:', ~ .~11 pa~l~ and other inter~- ~ ~ ~ns' are invited to. at- [~tend the hearing and preMnt ~. testim~:, commission consid~ keratlon M thiS'~tltion Will not ~: n~essarll(,~' ~':,:~]?~:"?o~-the ~. qu~tion ~ ~ra~tlng or denying 'the ~tition 'as'printed but ':"may al~ include'ConSideration .~ alternative means'~ unltlz-'{ 'lng all ora ~lon of the Pt. Mclnty~ :' and '~"Stump '; island '~ls such'.as a:Creation.'~ a .. new ,. unit;~-~Pa~les':~ and ?~other interest~ ~ns accordingly will ~ afford~ the op~ni- :ty to a~r~ any such alterna- ~tiv~ '~in ~::th~ir' :'testimony ~ and ' commen~..: . -.. A pre-hearing conference will ~ held at the Alaska Oil and Gas Con~rvatlon Corn-' minion, ~i Porcupine Drive, · Anchorage/Alaska W~I, at ~:~ AM, on Octo~r 14, I~, phone (~7). 2~-1~3. Pe~ns wlshng ~ participate in the hearing are invited ~'anend . the pre-hearing conference and ~ address the following subiects: ~ ~.~ 1.. Brl~ing .: '. ,:. ' i · 2. PrK~ures .for pre~nl- , ing t~timony .... :',~. -" ~,., 3. Pr~edur~ ~r pre,m- I lng exhibits, · :. ~ :. [.'::.~. Estimated length of the ~ {"'.hearing .V'.; '. '., ..'" ~ .....' ~ .; '.S.' Handling' M informati~ i..-." clalm~ ~ ~ coMidentlal ' 6. Conduct M the hearing' · ~' 7. Other :m&fle~ that p~- ...~ ~ly. may ~ the subi~ M a '. pre-hearing conference /~David ~ Johnston :.:,... '~ ~; Chairman, Alaska OII & Gas :'Publish Sept. 24, 1~ . '~} :"".; . I ALASKA OIL AND GAS CONSERVATION COMMISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 October 19, 1993 Honorable Charles E. Cole Attorney General state of Alaska P.O. Box 110300 Juneau, Alaska 99811 Dear Mr. Cole: The State of Alaska and the working interest owners have finally agreed to integrate their interests in the Pt. Mclntyre oil field. Therefore, the Commission sees no need to proceed with compulsory unitization of the field. Accordingly, we respectfully withdraw our October 12, 1993 request for special legal counsel. The Commission also wants to thank Assistant Attorney General Robert Mintz for his capable assistance throughout this controversy. The Commission has much confidence in his legal analysis and advice. David W. Jo Chairman cc. Rob Mintz, Assistant Attorney General ~,,..~ p,'inted on recycled paper 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING OCTOBER 14, 1993, 9:00 O'CLOCK A.M. TRANSCRIPT OF PROCEEDINGS HELD AT THE ALASKA OIL AND GAS CONSERVATION COMMISSION 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277- 0572/Fax 274- 8982 272- 7515 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 P R O C E E D I N G S CHAIRMAN JOHNSTON: Good morning. I'd like to convene this pre-hearing conference. I note the time is approximately 17 after nine o'clock. The date is October 14, 1993. We are located in the offices of the Commission, 3001 Porcupine Drive, Anchorage, Alaska. My name is David Johnston, I'm chairman of the Commission. To my right is Commissioner Douglass; to my left is Commissioner Babcock; and Laurel Kehler will be recording these proceedings. At this time we have before us a request to withdraw the petition filed by ARCO Alaska and BP Exploration for the compulsory expansion of the Prudhoe Bay Unit. At this time we would like to ask if there is anybody in the audience that has any objections to this petition being withdrawn? (Pause) I see no objections to the petition being withdrawn, therefore, the Commission will approve the withdrawal of the petition. With the withdrawal of the petition we see no need to proceed with the pre-hearing conference nor the hearing on November 2. So without any further ado, this meeting is adjourned. (Off record - 9:19 a.m.) (END OF PROCEEDINGS) R & R COURT REPORTERS 810 N STREET 1007 WEST THIRD AVENUE 277-0572/Fax 274-8982 272-75~5 ANCHORAGE, ALASKA 9950~ 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 CERTIFICATE UNITED STATES OF AMERICA) ) ss STATE OF ALASKA ) I, Laurel L. Kehler, Notary Public in and for the State of Alaska, residing at Anchorage, Alaska, and reporter for R & R Court Reporters, Inc., do hereby certify: THAT the annexed and foregoing Public Hearing of the Alaska Oil and Gas Conservation Commission was taken before me on the 14th day of October 1993, commencing at the hour of 9:00 o'clock a.m., at the offices of the Alaska Oil & Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska, pursuant to Notice; THAT this Transcript, as heretofore annexed, is a true and correct transcription of the testimony given at said Public Hearing, taken by me and thereafter transcribed by me; THAT the original of the Transcript has been lodged with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska; THAT I am not a relative, employee or attorney of any of the parties, nor am I financially interested in this action. IN WITNESS WHEREOF, I have hereunto set my hand and affixed my seal this 16th day of October 1993. 'Notary Public r Alaska My commission expires: 10/20/94 RECEIVED OOT 1 9 199 Alaska Oil & Gas Cons. Commissio,"~ Anchorage 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 ORIGINAL ALASKA OIL AND GAS CONSERVATION COMMISSION PUBLIC HEARING SEPTEMBER 9, 1993, 9:00 O'CLOCK A.M. TRANSCRIPT OF PROCEEDINGS So J° HELD AT THE LOUSSAC LIBRARY ASSEMBLY CHAMBERS 3600 DENALI STREET ANCHORAGE, ALASKA 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 REEE VED R & R 509 WEST THIRD AVENUE 277-8543 COURT S E P '~ ~ ~99~ A~aska Oil & Gas Cons. (;ommissior~ Anchorage REPORTERS 1007 WEST THIRD AVENUE 277-7515 1135 WEST EIGHTH AVENUE 272-3022 ANCHORAGE, ALASKA 99501 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 PROCEEDINGS CHAIRMAN JOHNSTON: Good morning. I'd like to call this hearing to session. I note the time is approximately five after 9:00. The date is September 9, 1993. We are located in the Municipal Assembly Chambers of the Loussac Library in Anchorage, Alaska. My name is David Johnston, I am chairman of the Alaska Oil and Gas Conservation Commission. To my left is Tuckerman Babcock; to my right is Russ Douglass; and to our far right is Laurel Kehler, of R & R Court Reporters, who will be making a transcript of these proceedings. At this time I would like to request Commissioner Douglass to read the public notice that was provided for this hearing. MR. DOUGLASS: Notice of Public Hearing, State of Alaska, Alaska Oil and Gas Conservation Commission. Notice is hereby given that the Alaska Oil and Gas Conservation Commission has, acting upon its own motion in accordance with AS 31.05.060, scheduled a public hearing and extends invitation to all those concerned to show cause as to whether any action is necessary to prevent or to assist in preventing waste, to insure a greater ultimate recovery of oil and gas or to protect correlative rights of persons owning interests at Point McIntyre oil field as defined under Conservation Order Number 317. The hearing on this matter will be held at 9:00 a.m., 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 September 9, 1993, 3001 Porcupine Drive, Anchorage, Alaska, 99501. As a result of this inquiry the Commission may consider forced unitization of the Point McIntyre and Stump Island Reservoirs as authorized by AS 31.05.030 and 31.050.110. Interested parties may confirm this hearing by calling 907/279-1433. Signed David W. Johnston, Chairman. Published August 7, 1993. CHAIRMAN JOHNSTON: And I'd like to note for the record that the Commission upon noting the interest that was being generated by this public hearing did change the location of that hearing and we did notice it, and that was why we are appearing in the Municipal Assembly Chambers today. Since the notice was published in the paper we have received a petition from -- a joint petition from ARCO and BP to consider the force -- or the compulsory unitization of Point McIntyre oil field. That changes the complexion of this hearing to some level; however, the Commission still must make a decision as to whether or not we will want to accept this petition. So I would like to ask the people testifying, primarily BP and ARCO, to -- without necessarily getting into the merits of the petition, to give us their feeling for why the Commission should undertake this petition, primarily emphasizing the conservation issues that are at debate in this 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 matter. We would also be appreciative if you would give us a little bit of a feel for the voluntary efforts that have gone on to date to -- that have been exhausted in the attempt to reach a voluntary agreement toward the unitization of the Point McIntyre oil field. Normally we provide the opportunity for people appearing before the Commission to give sworn testimony or unsworn statements. We also consider the qualifications of individuals to determine if they are an expert witness. In this particular case, however, we're not going to be asking people to testify toward possible facts. I think what we are more interested in is listening to the opinions of various individuals that have some concern in this matter. Therefore, we will not ask that you submit to being sworn in, nor will we ask you to state your qualification for expert witness consideration. We just ask that you state your affiliation, identify yourself, and provide us your thoughts as to why, on ARCO and BP's part, this is a proper petition and the conservation issues that you believe that are at risk and a little bit of the background as to the voluntary efforts that have been exhausted. At this point I would like to request Mr. Obeney of BP Exploration to step forward and appear before the Commission. MR. SIMON: Mr. Chairman. CHAIRMAN JOHNSTON: Yes, Mr. Simon. 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 MR. SIMON: Mr. Chairman, I think I'd be glad to open the introductory comments on behalf of ARCO. CHAIRMAN JOHNSTON: Okay, that would be fine. MR. SIMON: Mr. Obeney would add his. CHAIRMAN JOHNSTON: Excellent. Thank you very much. MR. SIMON: Mr. Chairman, members of the Alaska Oil and Gas Conservation Commission, ladies and gentlemen, my name is Andy Simon. I am manager of Lisburne/Point McIntyre for ARCO Alaska. I received a Ph.D. in Petroleum Engineering from the University of Missouri Rolla in 1980. I have worked in Alaska for the last 13 years in both Prudhoe, and more recently Lisburne/Point McIntyre. In my current position I am directly responsible for Point McIntyre's development and operation. As you are aware, Point McIntyre has been mechanically ready to initiate production since July 1. To reach this point has already required the investment of close to $300 million by the producers. Additional expenditures continue to be made. $150 million is being spent to complete facilities for the balance of the project and expenses of approximately $4 million a month are being incurred to continue drilling. The successful completion of the initial phase of the project has been a real success story; safely done, ahead of schedule and under budget. However, the inability of the producers and the 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST TH%RD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EZGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Department of Natural Resources to integrate their interests and voluntarily expand the Prudhoe Bay Unit has been, to put it mildly, a significant disappointment. We are continuing to work closely with Exxon and the Department of Natural Resources to resolve differences and form a voluntary unit. We remain hopeful that an agreement will be reached and that Point McIntyre will be included in the Prudhoe Bay Unit through the voluntary unitization process. Yesterday ARCO Alaska and BP Exploration petitioned the Alaska Oil and Gas Conservation Commission for an expansion of the Prudhoe Bay Unit area to include the Point McIntyre participating area. This petition starts the clock on the compulsory unitization process so that the existing disputes can be settled and the field can be brought on production as soon as possible in the event negotiations prove unsuccessful. As stated in the petition, the Commission has jurisdiction over this matter pursuant to AS 31.05.027 and AS 31.05.110. At the Compulsory Unitization Hearing ARCO and BP will establish that inclusion of the Point McIntyre participating area within the Prudhoe Bay Unit is necessary to, one, prevent or to assist in preventing waste; two, insure a greater ultimate recovery of oil and gas; and, three, to protect the correlative rights of the owners of the Point McIntyre oil field. In establishing jurisdiction AS 31.05.110-A provides as 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 follows: And I quote the statute. To prevent or to assist in preventing waste, to insure a greater ultimate recovery of oil and gas, and to protect the correlative rights of persons owning interest in the tracts of land affected, these persons may validly integrate their interests to provide for the unitized management, development and operation of such tracts of land as a unit. Where, however, they have not agreed to integrate their interests, the Commission, upon proper petition, after notice and hearing, has jurisdiction, power, and authority, and it is its duty to make and enforce orders to do the things necessary or proper to carry out the purposes of this section. End quote. Not one but all of the factors identified in AS 31.05.110-A are involved here. I would like to spend a few minutes briefly addressing each. First, the Commission has jurisdiction because the parties have been unable to integrate their interests. On March 18, 1993, ARCO, BP, and Exxon filed an application with the Department of Natural Resources to form the Point McIntyre participating area and to expand the Prudhoe Bay Unit to include all of the Point McIntyre participating area. ARCO, BP, and Exxon are the Working Interest Owners of the tracts included in the application, namely Tract 6, 7, 8, 115, 116, and 117. The state of Alaska is sole royalty owner of these tracts. 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 t007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Prior to filing the application, ARCO, BP, and Exxon voluntarily agreed to integrate their interests in Point McIntyre. Attachment III to Exhibit C to the petition sets forth the tract allocations agreed to by ARCO, BP, and Exxon. On August 18, 1993 the director of the Division of Oil and Gas, Department of the Natural Resources, denied the application. As stated previously, the producers and the Department of Natural Resources have been working and are continuing to work on an amended application to expand the Prudhoe Bay Unit to include the proposed Point McIntyre participating area. Although ARCO and BP are hopeful that these negotiations will result in a voluntary formation of the Point McIntyre participating area within the Prudhoe Bay Unit, to date the producers and the Department of Natural Resources have been unable to voluntarily integrate their interests in the field. Where the parties have not agreed to integrate their interests, the Commission, by AS 31.05.110-A, has jurisdiction, power, and authority to make and enforce orders to do the things neCessary or proper to carry out the purposes of this section. The statute not only gives the Commission jurisdiction to make such orders, it provides -- it is the Commission's duty to make such orders. seCond, the expansion of the Prudhoe Bay Unit to include the Point McIntyre participating area is necessary to 810 N STREET 277'0572 OR 277-0573 FAX 274'8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 prevent waste and to insure a greater recovery of oil and gas. The benefits of unitization to the Point McIntyre Reservoir have been well established. As outlined in the March 24 Public Field Rules Hearing, and documented in the uncontested findings and conclusions of the Commission, the unitized management operation and further development of the Point McIntyre and Stump Island oil pools is reasonably necessary to effectively carry on pressure maintenance and enhanced oil recovery operations to maximize recovery. This enhanced recovery by water flooding is projected to increase ultimate recovery by 20% or more and represents an addition of in excess of 150 million barrels of reserves. It is also uncontested that surface commingling of production from Point McIntyre using Lisburne Production Center will increase ultimate recovery, will not cause waste or jeopardize correlative rights. ARCO has previously entered sworn teStimony attesting to the importance of commingled production using the Lisburne facility and other Prudhoe Bay Unit facilities whose use is expected to increase ultimate recovery by 100 to 150 million barrels from a complex of reservoirs scheduled to produce through the Lisburne facility. Third, expansion of the Prudhoe Bay Unit to include the Point McIntyre participating area is necessary to protect correlative rights. AS 31.05.170, Subpart 2, defines the term "correlative right" as, quote, the opportunity afforded, so far 810 N STREET 277'0572 OR 277-0573 FAX 274'8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 10 as it is practical to do so, to the owner of each property in a pool to produce without waste the owner's just and equitable share of the oil or gas or both in the pool. The Department of Natural Resources' denial of the application effectively deprives ARCO and BP of any opportunity to develop the expansion tracts. Accordingly, the Commission involvement is required to protect the correlative rights of both ARCO and BP. In closing, the Commission has jurisdiction in this matter, therefore, we are requesting the Commission under AS 31.05.060 to bring the public notice period and schedule a hearing for compulsory unitization. We are hopeful that the parties can use the time between now and the date set for the hearing to resolve their differences, come to an agreement on voluntary unitization and commence production. That concludes my statement. CHAIRMAN JOHNSTON: Thank you, Mr. Simon. I don't believe we have any questions of you right now. I think we'll reserve our questions following Mr. Obeney's testimony. MR. SIMON: Thank you. MR. OBENEY: Mr. Chairman, members of the Alaska Oil and Gas Conservation Commission, ladies and gentlemen, my name is Terry Obeney. I am manager of Lisburne and new developments for BP Exploration Alaska, Inc. In my current position I am directly responsible for BP's interest 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & RCOURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 11 in Lisburne, Point McIntyre and other new developments, including Niakuk. I simply wish to confirm that BP has signed the petition to integrate the interests in Point McIntyre field by expanding the Prudhoe Bay Unit under the terms summarized in the petition. We have expended substantial energy in trying to resolve the differences among the lessees and lessor. Numerous offers and counter offers have been made and rejected by either Exxon and/or the state. Meetings have occurred at virtually every level of our respective corporate structures in an attempt to address the concerns of each party. We are, at this point, without any other recourse to obtain integration of the parties' interests. Therefore, we are in full agreement with the justification for action outlined by Andy Simon of ARCO and are of the firm belief that the AOGCC has the duty and the authority to act on the petition, hopefully, to bring about conclusion of the Point McIntyre field with the unit, namely the Prudhoe Bay Unit. Thank you. That's all I have. CHAIRMAN JOHNSTON: I have just a few questions. I think they'll be primarily directed at Mr. Simon, although, Mr. Obeney, if you care to jump in and provide any thoughts on this matter, we'd appreciate it. One of the concerns that the Commission has, if we move toward a forced unitization hearing is whether we are helping the process or hindering the process. My concern -- I think I 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THZRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH'AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 12 speak for my fellow commissioners here, is that we would like to see production from the Point McIntyre oil field as soon as reasonably possible. And we're somewhat distressed that this dispute has lingered as long as it has. In our opinion we would have liked to have seen the production flowing from the Point McIntyre oil field on July 2 when we issued our pool rules decision. But, nevertheless, there is a dispute out there. So one of my concerns is the timeliness of Commission involvement. You mentioned issues associated with preventing waste, ultimate recovery and correlative rights, and those are the hallmark of the conservation statute, of course. But in this particular case if there is no production currently taking place is there waste? MR. SIMON: Commissioner, I think we also stated the reason that we are requesting your interception is the parties have been unable to integrate their interests. CHAIRMAN JOHNSTON: That is true, and I am very sensitive to that, but, again, your petition also indicates that voluntary efforts are still under way, and I'm wondering, again, relative to the speed of which the Commission will move on a unitization hearing. Ultimately, obviously, if the parties fail to reach a voluntary agreement, then obviously as a last recourse, I believe, a petition to the Commission is definitely appropriate and -- again, I'm just trying to get a feel for the timeliness of our involvement. And, again, one of 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 13 my concerns is that we get this field on production as soon as we can. In that manner I have to look at proceeding very cautiously with Commission involvement because it's -- it always appears to me that it is better for the parties themselves to voluntarily agree. When you bring a third entity into this you have to kind of start at the very beginning again. You need to -- obviously the Commission will have to schedule a hearing. That will require a 30-day notice; it will require testimony before the Commission; it will require the Commission to go into a extensive period of deliberation as the issues that would be presented to us are in fact very weighty. Potentially, any decision that the Commission renders, because we are a third party here, may not satisfy the parties that are petitioning or the other parties to the thing. In other words, our decision my not give ARCO and BP or Exxon or DNR those things that they want. We may come up with an alternative view of the world. So you have to be prepared for that type of eventuality. So, again, I go back to concerns relative to the timeliness of our involvement. I think at some point it is appropriate, but in trying to determine the timeliness I am moved toward those things that may be at risk today. If waste is not occurring is it timely for us to move? If ultimate recovery is not being jeopardized is it timely for us to move? If correlative rights are not today being jeopardized is it 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & RCOURT REPORTERS 509 WEST THIRD AVENUE 27Z-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVEHUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 14 timely for us to move or should we practice more patience and allow the parties a little bit more time to attempt a voluntary agreement? I just want to kind of get your thoughts on that. MR. SIMON: Yes, Chairman Johnston, I'll kind of sequence if I can remember some of the points. First, we are saying we are currently at impasse; we are unable to integrate our interests. We are hopeful voluntary efforts will continue, but we view it as being very important that the clock on a mechanism to ultimately resolve these issues be started in the event the negotiations are unsuccessful. So therefore today we are at impasse on voluntarily integrating our interests. Number two, ARCO believes that our correlative rights are being impaired. We are being denied the opportunity to produce our fair and equitable share from the Point McIntyre reservoir. Number three, as far as the efforts, 175 days ago we filed an application for the expansion of the Prudhoe Bay Unit and creation of the Point McIntyre participating area. We all, I think, have endeavored extraordinarily hard to bring this issue to closure. To date we have not been successful. We remain hopeful that it would be my opinion that starting~a process that will provide a backstop to assure these issues come to closure and allow the field to move forward is very important and would be a positiVe step. 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 15 CHAIRMAN JOHNSTON: Do you believe that failure to produce a field today within the infrastructure that is in place and everything that's ready, set to go, the only thing that is affecting the ability to produce that field is lack of an agreement? Would that constitute waste in your opinion? MR. SIMON: Since the field is not producing, no physical waste is occurring. CHAIRMAN JOHNSTON: But would the decision to delay production -- or actually not the decision but the delay in production that is not occurring today due to lack of an agreement between the parties, could that be construed as waste in the sense that the infrastructure on the North Slope has a finite life and therefore if you do not produce oil today that potentially tomorrow you may be losing that oil because of the infrastructure not being available to you to extract it? Could that be a logical conclusion that the Commission would come to? MR. SIMON: Chairman Johnston, I cannot answer the question. I can say that five million barrels of production have been deferred by the 71 days the project has been shut-in. I think economic waste would depend on a number of parameters, such as future oil price, which are uncertain. CHAIRMAN JOHNSTON: Mr. Obeney, you stood up. Did you have any thoughts on ..... MR. OBENEY: I would add a few things. CHAIRMAN JOHNSTON: Please do. 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 16 MR. OBENEY: We fully appreciate that the forced integration of interests could be a lengthy and complex process. We don't believe it has to be. I'd like to stress, with regards to the time table that the AOGCC, all the unsung heroes of the negotiations to date, that your involvement has brought the negotiations a lot closer -- the parties a lot closer. With due respect to Exxon and the DNR, neither party appears to have a deadline to resolve their differences, and further involvement with the AOGCC in setting a time table of some sort will only serve to bring this matter to a close and bring about production. So I think your involvement is critical to making progress. I'd like to stress that the legislation provides this mechanism, it recogniZes the attendant risks, and is a vehicle to encourage voluntary unitization. Only if the AOGCC is willing to act will the parties be pressed to settle. We don't believe that demonstration of physical waste is necessary in this instance or physical waste will occur if the leases are produced independently. The correlative rights are the principal dispute. CHAIRMAN JOHNSTON: In terms of correlative rights, Mr. Obeney, it's my understanding that BP is the owner of a lease in the Point McIntyre field that has a discovery royalty provision. MR. OBENEY: No, that's not correct; it's an 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST TH[RD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 NEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 17 ARCO/Exxon lease in the southern part of the field that has a discovery royalty plan. CHAIRMAN JOHNSTON: I see. And that's the one that would reduce the royalty rate to 5%? MR. OBENEY: Yes. I don't know the dates. ARCO can speak to that. CHAIRMAN JOHNSTON: Excuse me for that mistake. I had understood it was BP. MR. OBENEY: I wish it was true. CHAIRMAN JOHNSTON: Then I would like to direct this question to Andy Simon then, on behalf of ARCO. When does that,discovery royalty provision expire? MR. SIMON: The discovery royalty, as the Chairman notes, is a reduction from the standard 12-1/2% to a 5% royalty rate which runs for a period of 10 years from the drilling of the discovery well. As such that reduction in royalty would run through 1998. CHAIRMAN JOHNSTON: So the clock is ticking on that discovery royalty at this point; ..... MR. SIMON: Yes, sir. CHAIRMAN JOHNSTON: ..... is that correct? MR. SIMON: Yes, sir. CHAIRMAN JOHNSTON: So the inability to produce that reservoir today, the owner of that discovery royalty is losing the benefit of that discovery royalty today; is that 810 N STREET 277-0572 OR 277-057:3 FAX 274-8982 R & RCOURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 18 correct? MR. SIMON: Yes, sir. CHAIRMAN JOHNSTON: So, in other words, that is an expression again of correlative rights. You have the right of opportunity to extract a resource at a 5% royalty burden as opposed to a 12-1/2% royalty burden? MR. SIMON: Yes, sir. CHAIRMAN JOHNSTON: So that gets back again to the timeliness, I believe, of Commission involvement if the framework that -- there is an opportunity here that is being sacrificed for failure to come to an agreement with the parties that have a say in the matter. MR. SIMON: Yes, I would not disagree. CHAIRMAN JOHNSTON: Thank you very much. At this time the Commission would like to invite Mr. Baker to appear before the Commission. MR. BAKER: Mr. Chairman, members of the Commission, ladies and gentlemen, my name is Gary Baker, and I represent Exxon Corporation. Exxon is the largest Working Interest Owner in the Point McIntyre oil field, and as such we are a very interested party in this proceeding. Exxon supports the petition of ARCO and BP to force unitized -- the Point McIntyre field as an expansion of the Prudhoe Bay Unit to include the Point McIntyre participating area. Exxon believes that expansion of the Prudhoe Bay Unit 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 NEST THIRD AVENUE 277-8543 1007 NEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 19 to include Point McIntyre will prevent waste, protect the correlative rights of all of the parties of interest which include the Working Interest Owners and the State of Alaska as the royalty owner. We also believe that unitization of Point McIntyre will ensure the greatest ultimate ~recovery of oil and gas from the field. Exxon notes that in paragraph 24 of the application ARCO and BP are willing to waive a 1980 Royalty Settlement Agreement provisions that is between the state and various producers and field cost deductions from royalty for the benefit of the royalty owner. Exxon believes that the 1980 Royalty Settlement Agreement and certain field cost deductions that are in dispute between the lessors -- between the lessor and the lessees are over post-production charges and are not a dispute that involves waste, protection of correlative rights, or the greater ultimate recovery of oil and gas. In short, Exxon does not believe that the royalty dispute between the lessor and the lessee should be an issue in a forced unitization proceeding before this Commission. Exxon is continuing to work and discuss with the state, through the Department of Natural Resources, the issues that are holding up voluntary unitization. The fact that this application has been filed will in no way affect our ongoing negotiations with the state, at least from Exxon's standpoint. 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & RCOURT REPORTERS 509 WEST THZRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 20 Thank you. CHAIRMAN JOHNSTON: Thank you, Mr. Baker. I don't believe we have any questions of you at this time. I have an indication here that Mr. Van Dyke, of the Department of Natural Resources, may choose to appear before the Commission. Mr. Van Dyke, do you care to make any comments at this time? MR. VAN DYKE: Yes, I would. CHAIRMAN JOHNSTON: Please step forward and appear before the Commission. MS. KOBAYASHI: May it please the Commission, my name is Tina Kobayashi. I'm an assistant attorney general with the Department of Law, and Mr. Van Dyke has asked that I address some other points, but I think I'll let him go first. CHAIRMAN JOHNSTON: Thank you very much. I don't necessarily see your name on the sign-in sheet. Did sheet. MS. KOBAYASHI: I should be on the sign-in CHAIRMAN JOHNSTON: Maybe it's on the other one we left out there. I just want to make sure we had your names so we got it spelled right. Thank you. legible. MS. KOBAYASHI: MR. VAN DYKE: Maybe my handwriting isn't Mr. Chairman, Commissioners, my name is Bill Van Dyke, and I am petroleum manager with the 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 21 Division of Oil and Gas, Department of Natural Resources. I'd like to confirm that negotiations still are underway to form a voluntary unit and that meeting went into late last night and probably will continue today. That process is far, I think, from being at an impasse. As the Chairman noted, it's a question of timing. You know when an impasse is reached. Certainly negotiations are still underway today. I think there's also a question of timing. Someone mentioned it's been about six months since the application was submitted to the Division for expansion of the Prudhoe Bay Unit and formation of the Point McIntyre participating area. That's been about, I think, 171 days was the number I heard. It's been about five and a half years since the accumulation was discovered. To put it in perspective, it's -- hopefully a little more time can be given to the voluntary process at least. I think there's -- we certainly hope that that can happen, a voluntary unit can be formed. When you look at it from the date of discovery, a few more days probably isn't that much longer. I think that's about all that I can say at this moment. I know Tina would like to make a few comments. MS. KOBAYASHI: Yes, if the Commission goes ahead with this petition the Department of Law and the Department of Natural Resources would like to participate in any discussions that goes along with this petition. We are 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & RCOURT REPORTERS 509 WEST THIRD AVENUE 277-8545 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 22 not, at this point, ready to comment on the petition because the Commissioners just received it yesterday. It's a very lengthy petition. We have not had time to review it. We have spent most of our time in negotiations and so we would like an opportunity to comment on it later. And that's all I have unless the Commission has any questions. MR. DOUGLASS: Mr. Van Dyke, one question. You talked about these negotiations. Are all parties involved; Working Interest Owners and the DNR? MS. KOBAYASHI: Perhaps I can answer that. By that do you mean are Exxon, ARCO, BP, all -- yes. MR. DOUGLASS: MS. KOBAYASHI: MR. VAN DYKE: Yeah, okay. Yes, everybody is involved. It may not be that all parties are in all meetings or -- not everyone is there all the time, but all parties are participating. CHAIRMAN JOHNSTON: Has DNR received adequate information to date upon which to render its decision; do you feel that industry has been forthcoming with the information that is appropriate Or to allow you the ability to determine what is appropriate provision in terms of the Department of Natural Resources? MR. VAN DYKE: Certainly with respect to the geology, the plan development, what the future plans, as far as 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 23 drilling goes, those type of issues, certainly we've received adequate information, yes. As far as looking at the oil in place, that type of review, yes. CHAIRMAN JOHNSTON: So then basically the essence of the disagreement is not necessarily resulting from a lack of information; it is just a different perspective that DNR has it's view of the real world and the industry representatives have their view. Is that accurate? MR. VAN DYKE: I'm not aware of any major dispute we have right now concerning facts or the technical interpretation of the reservoir. It's probably primarily an economic dispute. CHAIRMAN JOHNSTON: Has DNR feel that the negotiations are at an impasse at this point? MS. KOBAYASHI: No, I think we can continue to talk. It's hard to say. I wouldn't say that we are at an impasse at this point. CHAIRMAN JOHNSTON: It's always difficult, of course, to know when you are at an impasse, and of course the tendency is, as you say, to continue to talk; however, at some particular point we've got to make a decision, and although Bill Van Dyke indicates that this is -- since discovery it's been five years or longer and that a few more d~ys may not matter, and maybe in the great scheme of things a few more days does not matter, but I have a very difficult time with that 810 N STREET 277-0572 OR 27?-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 24 idea when I bring it down to the working level of that oil field worker that is dependent on that job to support his family and to talk about a few more days here and there. You know, I do have some concern about the -- you know, that small person out there that needs to see this production come on so he can provide or she can provide a source of revenue to their family. So I hope that we're not losing sight of the fact that there are other people -- real people that have a stake in this decision, and I have to say, you know, to both sides that the Commission is very deeply concerned that these negotiations have taken this long, and certainly encourage you to work diligently toward a voluntary resolution. I think that is by far the preferred alternative, and I would encourage you to re- examine and refocus your efforts toward doing that with an eye toward -- you know, with not forgetting that small person out there that needs this to support their family. MS. KOBAYASHI: Thank you. I do understand that. I don't think that either the companies or the state are ready to say that we are at an impasse. I'd like to emphasize that the negotiations have been progressing, that there has been progress made. We spent most of yesterday, and I anticipate we'll spend a considerable amount of time in the next few days continuing our negotiations, and I think we are making progress. CHAIRMAN JOHNSTON: Thank you very much. 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 25 MR. BABCOCK: I have one question, Mr. Chairman. What's your definition, Mr. Van Dyke, of a unit agreement? MR. VAN DYKE: A generic definition would be certainly the complete package of the integration of interests, the plan of development, the formation of the participation areas, the terms which that agreement would -- or the unit area and how that area would be expanded or contracted down the road. We have a model unit agreement that we use at the Division. There are other model unit agreements available throughout the country and throughout the world. It's the complete package. MR. BABCOCK: Thank you. CHAIRMAN JOHNSTON: At this time I'd like to just call a five-minute recess to allow us time to consult with one another to determine the rest of the hearing. (Off record - 9:48 a.m.) (On record - 9:58 a.m.) CHAIRMAN JOHNSTON: I'd like to call the hearing back in session, please. MR. BABCOCK: I have a very brief comment. CHAIRMAN JOHNSTON: Thank you. The Commission has decided that it will deliberate on this matter for a few days and we will then render a decision as to whether we will move forward with a compulsory unitization hearing. We will 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 notify all concerned parties, and I suspect we'll make that decision within a week to 10 days. If there are no further comments -- yes, Ms. Davis. MS. DAVIS: May it please the Commission, my name is Marsha Davis, and I'm senior counsel for BP Exploration. Ladies, gentlemen, BP did want to make a few final comments and relative to the comments that we've heard from Exxon and the state representatives. As far as the participation of BP and ARCO, it is true that we are hearing comments from both sides, but of late we have not been participating in joint deliberations on the negotiations. We are certainly heartened by the comments we've heard from the state and Exxon's representatives that they do not believe they are at an impasse, however, we ourselves have concerns in that what we hear are comments that do indeed sound like impasse positions. As far as their comments that they believe in the next few days they hope that they'll have the breakthroughs and they'll resolve their differences, we feel that that is entirely consistent with continuing a consideration of our petition which will provide for the 30-day public comment period. And, finally, relative to the comments on correlative rights, Waste, and ultimate recovery, we'd like to remind the Commission that those criteria are weighed against the alternative of the parties having to produce their leases 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 27 independently, and therefore the comparison would be what do we, ARCO and BP, do with respect to our leases with our lease rights versus in a unit, and we feel that the elements are there justifying inclusion of our leases within a unit. Thank you. CHAIRMAN JOHNSTON: Thank you for those comments. I particularly appreciate your observation relative to the impasse nature of this -- of these discussions. At this time the ..... Mr. Chairman. MR. BABCOCK: I just have one comment, CHAIRMAN JOHNSTON: Please go ahead. MR. BABCOCK: I just want to comment along the lines that since the Commission has never forcibly unitized in the past that the state of Alaska and the mineral working interest owners have always managed to voluntarily unitize, which is in the best interests of the state, the people, and has been the best in the interests of conservation of the resource, that at least I would very heartily encourage all the parties to work diligently to resolve their differences before this Commission makes a decision as to whether or not to take up this petition, and that one of the issues, should it come before -- should the Commission decide to take this up, that at least I would take very seriously, is the protection of the 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST TH%RD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 28 correlative rights on the discovery royalty. Nothing else, Mr. Chairman. CHAIRMAN JOHNSTON: Thank you. Any other comments from the audience? There being none, I would like to then adjourn this meeting. I note the time is approximately 10:00 o'clock. The date is, again, September 9, 1993. Thank you. (Off record - 10:00 a.m.) (END OF PROCEEDING) 810 N STREET 277-0572 OR 277-0573 FAX 274'8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 29 CERTIFICATE UNITED STATES OF AMERICA) ) ss STATE OF ALASKA ) I, Laurel L. Kehler, Notary Public in and for the State of Alaska, residing at Anchorage, Alaska, and reporter for R & R Court Reporters, Inc., do hereby certify: THAT the annexed and foregoing Public Hearing of the Alaska Oil and Gas Conservation Commission was taken before me on the 9th day of September 1993, commencing at the hour of 9:00 o'clock a.m., at the Z.J. Loussac Library, Assembly Chambers, 3600 Denali Street, Anchorage, Alaska, pursuant to Notice; THAT this Transcript, as heretofore annexed, is a true and correct transcription of the testimony given at said Public Hearing, taken by me and thereafter transcribed by me; THAT the original of the Transcript has been lodged with the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska; THAT I am not a relative, employee or attorney of any of the parties, nor am I financially interested in this action. IN WITNESS WHEREOF, I have hereunto set my hand and affixed my seal this 13th day of September 1993. Notary Publi~Jin and for Alaska 'My commission expires: 10/20/94 R'ECEIVE D $ E P 1 199 Alaska Oil & Gas Cons. Commission Anchorage 810 N STREET 277-0572 OR 277-0573 FAX 274-8982 R & R COURT REPORTERS 509 WEST THIRD AVENUE 277-8543 1007 WEST THIRD AVENUE 277-7515 ANCHORAGE, ALASKA 99501 1135 WEST EIGHTH AVENUE 272-3022 ALASKA OIL AND GAS CONSERVATION COMMISSION POINT MCINTYRE SHOW-CAUSE PUBLIC HEARING LOUSSAC LIBRARY - ASSEMBLY CHAMBERS SEPTEMBER 9~ 1993 SIGN IN PLEASE NAME & COMPANY (PLEASE PRINT) Do You Plan to Testify? Yes No ALASKA OIL AND GAS CONSERVATION COMMISSION POINT MCINTYRE SHOW-CAUSE PUBLIC HEARING LOUSSAC LIBRARY - ASSEMBLY CHAMBERS SEPTEMBER 9~ 1993 NAME & COMPANY (PLEASE PRINT) SIGN IN PLEASE Do You Plan to Testify? ALASKA OIL AND GAS CONSERVATION COMMISSION POINT MCINTYRE SHOW-CAUSE PUBLIC HEARING LOUSSAC LIBRARY - ASSEMBLY CHAMBERS SEPTEMBER 9~ 1993 NAME & COMPANY (PLEASE PRINT) SIGN IN PLEASE Do You Plan to Testify? Yes No 'X ALASKA OIL AND GAS CONSERVATION COMMISSION PRE-HEARING PT. MCINTYRE OCTOBER 14 1993 NAME & COMPANY (PLEASE PRINT) SIGN IN PLEASE Do You Plan to Testify? Yes No /! ALASKA OIL AND GAS CONSERVATION COM~IISSION October 14, 1993 ADMINISTRATIVE APPROVAL NO. 317.1 WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907} 276-7542 Re: Integration of Interests and Commencement of Regular Production. A. D. Simon, Manager Lisburne/Point Mclntyre ARCO Alaska, Inc. P. O. Box 100360 Anchorage, AK. 99510-0360 Dear Mr. Simon: We have received your correspondence dated October 14, 1993 requesting Commission authorization to commence production from the Pt. Mclntyre oil field within two (2) hours of an order from the Commission. ARCO Alaska, Inc., BP Exploration (Alaska), Inc. and Exxon Corporation filed with the Commission on October 13, 1993, a copy of the Amended Application for Proposed Pt.. Mclntyre Participating Area Prudhoe Bay Expansion and a copy of an Order by the Director of the Division of Oil and Gas, Department of Natural Resources approving this Amended Application. It appears that the interests of all persons owning interests in the Pt. Mclntyre oil pool and the Stump Island oil pool have been validly integrated pursuant to the agreement incorporated in these documents. The Commission has previously reviewed the plan of development and operation foi' the Pt. Mclntyre oil pool and Stump Island oil pool, apart from an agreement validlY integrating interests. With integration of' interests now accomplished, the Commission approves the plan of developmen! and operation. 20 AAC 25.517(c) provides that a "copy of an agreement validly integrating the interests of all persons owning interests in affected property in the pool or portion of the pool for which development is contemplated by the operator must be filed with the Commission no later than 30 days before the commencement of regular production from the pool." 20 AAC 25.505(b) provides that an "order issued in conformance with 20 AAC 25.540 prevails over this chapter .... "Conservation Order No. 317, establishing pool rules for the Pt. Mclntyre Oil Field, was issued in conformance with 20 AAC 25.540. Rule 1 of Conservation Order 317 provides that "[r]egular production may not begin until the interests of the working interest and royalty owners are integrated in accordance with the -, ~ printed on ~ecycted 13apef b y C.D. provisions of 20 AAC 25.517 .... "Rule 14 of Conservation Order 317 provides that the Commission "may administratively waive the requirements of any role stated above or administratively amend this order as long as the change does not promote waste, jeopardize correlative fights, and is based on sound engineering principles." The Commission notes that a copy of an agreement integrating the interests of the working interest owners has been on file with the Commission since April 1993, although the Department of Natural Resources had not yet approved the agreement. Under the circumstances, the Commission believes that no purpose would be served by delaying production for 30 days. Nor does the Commission believe that allowing regular production to commence sooner would promote waste, jeopardize correlative fights, or contravene sound engineering principles. Accordingly, pursuant to Rules 1 and 14 of Conservation Order 317, the Commission waives the 30-day period before commencement of regular production from the Pt. Mclntyre field. Regular production may commence upon issuance of this Administrative Approval. David W. ~'o~ Chairman BY ORDER OF THE COMMISSION 0 CT .1 4 ,A~aska Oil & Gas Cons, An.choraoe AFFIDAVIT OF CLIFFORD BURGLIN The following statements contained in this Affidavit are a true and correct representation of the facts and ()pinions regarding the correlative rights, mineral title, record title; and ownership interests of Clifford Burglin in and to Alaskan State Leases identified as ADL 34622 and ADL 34623. !. Clifford Burg!in acting on behalf of Thomas J. Mik!autsch and himself .hereby acknowledges and attests to the fact that both persons are ~embers of an unincorporated business association known as the December 3, 1968 Join~t Venture Association (Exhibit "A") which was superseded in part and is now known collectively and indepen~.antly as the~ Gu!f Settlement Agreeememt (Exhibit "B"), the.~ Gulf Oil Trust (Exhibit "B" supra) ~ and the Exxon Settlement Agreement (Exhibit 2. In accordance with paragraph #3'of the December 3, 1968 Joint Venture Association the~c~-~ing~'~'~ interest ~!~'~ and the Lessee of Record status of Alaskan State Leases ADL 24622 and ADL 34623 for '~convenience'~ were r~¢.orc%ec~ i/~ t}',e the name of General Amerlcan Oil company of Texas now Phillips Petroleum and mineral 'title was registered with the State of Alaska on a "Confidential" basis. 2A. As of September 2i, 1969 the working interest title and ~the Lessee of Record staqus ~ ~ ~o~ ADL 34622 and ADL ~4623 was transferred from Genera! American Oil Company of Texas ~o Humble Oil and Re.fining now Exxon and was registered with the State of Alaska wi'thout ii!u;minating 'the "Confidential~, Trnst Relationship established by the~.~m~e~_5~"~ ~- . .~ ].968 Joint Venture nnincerporated Business Association. 2B Am of March 13, ~c, i0 50% of the wormz.,~g into. re title and 50% 'of the Lessee of Record status for ADL '34623 was transferred fro~ Hum. D].e. Oil and Refining now Exxon to Atian,~ic Richfielci Co., now ARCO. 2C.. i'n accol-dance with the law of .Agency as it applies to an unincorporated joint venture business association and as a direct result of the prevailing condition of the !eases, Burglin acting on behalf of T. J. Miklautsch~ ac'ting on behalf of the Dece~]~ber 3, 1968 Unincorporated Joint Ventur~ Business Association, and acting on behalf of himself individually finds and states as follows "It is no longer .CONVENIENT to maintain th~ working interest ~rights, co~retativ% ri. gilts, and Lessee of Record status~ title, or ownership interests in tl~e form or fashion as has been heretofore registered With the[.~ State of Alaska or to maintain ownership of any kind on a Confidential basis~" 2D. Burglin fir~ds that sny reason to 'maintain "Convenience" or "Confidentiality', has expired due to the prevailing conditions of the two Le~se.s and the necessity of co!~ducting unitization or Forced Pooling hearings before the State of .Alaska's Oil and Gas Conservation Commission. RE( EIVED -1- OCT 1 4 199 A~aska 011 & (~as Cons. ~ommtssto~'~ Anchorage 3. Stipulating known facts Clifford Burglin finds that Thomas J. Miklautsch and himself are current members of the superseding unincorporated business association now known as tke Exxon Settlement Agreement wh~se entity status is partly defined in Section V of said Agreement under the heading of ~IISCELLANE©US item (2). Clifford Burg!in acknowledges on behalf' of ~'homas J. Miklautsch and himself that they are both members of the unincorporate~ business association known as the Gulf Settlement Agreement effective as of March of 1977. 3A. Burglin stipulates (a), upon the implementation of Exhibit #4 to the E××on Settlement Agree~nent (b>, upon the issuance of a finding by.the State of Ala~ka that the Pt McIntyre well ~? located on~.ADL 3~622 is capable ef com~ercial production of at lea~t 500 barrels of oil per day (c), upon the evidence and the testimony of expert %~itn~ses appearing before the AOGCC by date of March 24, 1993 on page 28 thereof, the net result is the implementation of Section I Subparagraph (?) (G) of the E~Xon Settle.~ent Agreement is now warranted by the facts. Burg!in finds that prevailing conditions compel him to. acknowledge the basis for rescinding and terminating Section I subparagraphs (7.) (A)-(H) of the Exxon Settlement 'Agreement including and with particularity subparagraph (7) (F) ~hich denominates the basis for th% rights, titie, and interests of the drilling operations conducted by Exxon or Arco or Exx.on'~and ARCO with reap.eot to all areas of ADL 34622 and APL ~4623 other than the proposed 160 ac.re ~Special Exploratory We!!~' Drilling Spacing Unit surreunding Pt. McIntyre Well #7. 3B. Burglin hereby info~ms 'the State of Alaska and the AOGCC that the impact of Section I Subparagraph (7) (G) serves to terminate a.~ong other 'things th~ several Operator rights and the drilling party rights of Gulf Oil subsequently Chevron and Exxon~ ter~inates 'ane Operator rights of E×'xon/ARCO held jointly reqarding the remaining acreage enco~npassing APL 34622 and APL 34623, terminatez Gulf Oil's o~ nershlp or claim upon 'the remaining acreage independan't!y or through the Gulf-MBH Alaska Limited Partnership, effectuates the prior 'termination of Hamilton Brothers' Operating rights to the Pt. storkersen #1 well, terminates Exxon~s Operator rights to the Pt.. sto'rkerse~.~ w~ll, terminates Chevron's title rights indspendantly and through the unregistered Chevron-MB~ Alaska Limited Partnership now the regis'tered E×xon-MBH Alaska Limited Partnership, contracts Exxon's ~ights as Managing?Qeneral Partner by and through the Exxon-MBH Alaska Limit.ed Partnership down to 160 acres or the subsequently designated dri 1 ling spacing unit for the Pt, Mointyre #7, contracts the Exxon-MBH Alaska Limited Partnership's rights previously conveyed by Miklautsch (Haugen), Burgiin, and Hamel to the 160 acre or smaller "Special Exploratory Well'". drilling spacing unit and modification thereof, contracts ARCO's operator rights to the Pt. McIntyre ~7 well only, contracts Ex×on and ARCO's Lessee record status to the size of the ensuing drilling spacing u~it, and contracts Exxon'~ and -2- 0 CT 1 4 199;3 ,Alaska 011 & Gas Cons. Commisston Anchorage title unto 160 acres or the ultimate size of the drilling spacing unit, desegregrates Burglin's and Miklautsch's correlative rights which by the force of the contraction imposed by Section I (7) (G) implies that all surrendered correlative rights, title, ~and interest of GUlf, Exxon, Chevron, Genera~ American, ~ Phillips, ARCO, and others are now held ',in Trust" jointly and severally until such time as the rights vest through the Trust vehicle to Miklautsch and Burglin. For informational purposes only the interest of the Alaskan Interest Organization are otherwise known as the interest of Exxon. For information purposes only the interest of ARCO Alaska Inc., are otherwise known as the interest of ARCO. 3C. Burglin finds that all areas of the leases other than the immediate and undefined 160 acre tract surrounding the bottom hole location of 'the Pt. McIntyre #7 well ("Special Exploratory Well") previously placed "in Trust~' by the Gulf Oil Trust are vested unto Miklautsch and Burgiin as of the effect~ive date of Exhibit #4 to the Exxon Settlement Agreement with fUll correlative rights, title, 'and interests appurtenant thereto. Those parties previously stipulated that their corr~iative rights pmrtaining to the remaining acreage~ on both /.eases other' than the 160 acre tract denominating 'the "Sp~ciai E×plora~ory Well" drill spacing unit are terminated and extinguisl]ed in their entirety with regard to the remaining acreage on both leases, and are of no furthe~ force and effect with the sole exception being the correlative rights placed '~in Trust" for "Convenience" sake. The ~'prima fascia'~ evidence of termination is the validity of the Exxon Settlement Agreement's Exh~it ~4 at~ac.~'~e~, h~reto and made~i a part hereof which is included her~wi~.h for this stated purpose~ and no other. · ' ~ ~' -~"~ ' the r face 3D Burg!in stipulates that in a,~.,~urda..t, ue w!th subsu conveyance of 160 acres or the resultant drill spacing unit designated by the AOGCC, Burg!in re~rves his right to amend the Special Exploratory well "Drill Spacing , '~'-', ~ Un~. as one. of his core correlative rigt~ts~ and hereby ' ~ ~- ~e.~ts to reduce 'the size of said Drilling Spacing Unit to 8c~ acres as per the t~nants of Exhib~'.~ #2 to the Exxon Setti~nent .Agreeing. ont. Burglin seeks a ruling from the AOGCC with ~"egard to the vel idity of such a determination based upon the existing testimony regarding known reservoir characteristics and the assumed areal drainage pattern of the Pt. McIntyre wall #7. 3E. In accordanc~ with the~[Law of Agency as such applies to an unincorporated business association known as the Exxon Settlement Agreement Clifford Burglin acting on. behalf of T. J. Miklautsch aI%d himself hereby invokes the execution and the manifestation of the Gulf Oil Trust as sUch is proffered, within the Gulf Settlement Agreement stipulated in part by.paragraptl ~2 and part.by paragraph #2 (b) through 'the m~ltiple use of the term "Trust" within the language of that Agreement. RECEIVED' OCT 1 4 199 ,Alaska oil & Gas Cons. C°mm'tssl°t~ Anchorage SENT BY:Xer'ox Tele¢opier' '/021 ;10-13-93 · OCT 1 4 199 AlaskaOil&6asCons. omm ssio 4. Clifford Burg!in herein and hereby lays claim to a~h~ all correlative rights, title, and ownership J. ntersstm appurtenant to his ownership interests in the various unincorporated businesm association~ heretofore enumerates by and through the Gulf Oil Trust. Burglin hereby presents these ownership claims in thim form and fashion before the State of Alaska's Oil and Gas Conservation Commission' for the sole purpose of s~eking the protection afforded Miklautsch.' and. Burglin as the owner of correlative rights in accordance with the mineral law of th~ State of Alaska. ~. Clifford Burg!in acting on behalf of the Gulf Oil Trust !..~i~. hereby executes and presents a valid copy of Alaskan Fo~ DO&G ':'. 25-84 DNR #10-113 an assignment of mineral title that will b~ recorded with the State of Alaska which vests all mineral title~ correlative right.s, interests, and ownership rights inc!u~ing~ Lessee of Recor~ status in and to 'the remaining portions of APL 34622 and APL 34~23 in the proper name. and in the proper proportion as stipulated by da'~e of September i~ 19~8 for all areas of th~' two ADL Leases other than the "~Special Exploratory Well" drilling spacing unit. 6.. Burgiin hsreby attests to the fact that pursuant to the authority granted u:~der a confidential letter agreement dated September 13~ .1990 whereby Burglin.~awardad certain right~ "in. Trust" to Arctic Basin Industries Inc.~ and to Mark A!exandar individually' including the right to negctiate~ bargain, se!l~ other,'lee dispos~ of the rights, tttle~ and. interests of the unincorporated bus!n, ess association of Clifford Burglin created by date of April !~ 1967, the right to sell~ barter, or convey =he assets of the Gulf Oil Trumt · . c_eat, ea Ha'z-ch 14, i977~ 'and. the right to d~.,',,,*,~.~ of -~=~, ~he assets of the other un~noorporate~ b~siness associations h%rein enumerated and, in accordance therewith Arctic'Basin I ndust~les Inc.~ and Mark Alexander are to be compensated for rend~ri~]g any a~.d al! services~ appurtenant thereto. 7. BUrglin" claims all correlative rig:ht~ and other ownership interests or rights in conjunction ~ith the terms of the Gulf Oil Trust and implied by the net effect of the tmp!emsntation of Section I subparagraph (7) (G) of the Exxon Settlement Agreement. Burglin her~in declares to 'the State of Alaska and to others that the express, implied, and alluded to inte~%t and basis of the Gulf Oil Trust and Exxon Sett].emen% Agreement have come to fruition as evidenced, by the certification .imsued by the State. of Alaska of the commerci~lity of the "special Exploratory Well" deno~inated in paragraph #2 (c) of the Gulf Sett!em~nt Agreement being the same as Pt. McIntyre well #7 identified - as the "Drilling Operation,, denominated ,in Section I subparagraph (7) (F) of the Exxon. Settlement Agreement° Pt. McIntyre well #7 is also known as the Pt. McIntyre well 7A. BUrglin's claim of correlative rights are based upon direct evidence of tile validity of E×hibit 94 to the Exxon Settlemont -4- Agreement, are based upon a finding zs,:,ued by the State of Alaska!~ · AOGCC, and ultimately based upon the certification isSU~'d"by the State. of Alaska that the Pt. McIntyre well %7 iS capable of producing oil" and gas in' commerica! quantites (E×hibit "D") vis a vis that the well is capable of producing 500 BOPD as .sUCh a fact is supgOrted by the sworn testimony "of a · ~.~epresentative of ARCO upon appearing before the A~G¢.C at hearing held March 24, 1993 i~ Anchorage, Alaska. 8. Further Affiant sayeth not~ '~,, This AffLdavit is si~ned and sealed"~as of this the day of ~~.6.~ ' , 1993. ~FFIANT: CLIFFORD BURGLIN THIRD JUDICIAL DISTRICT STATE OF ALASKA On this day per~onaliy appeared before m.e the duly under'si~ned authority Clifford H', Burg!.in who ,having identified himself to me did state %Index- oath that this is a true and accurate rep~esentation~ of the facts and opinions regarding the circumstances surrounding ADL 34''~' hz2 and ADL 3462.~ located .~n ~ the State of Ala~ka and ,~,ithin the knowledge of this Affiant are known by him to be a true and accurate record of such facts ]?,ade to the be~t of h~%~ ability. -5- REEEIVED OOT 1 ,Alaska Oil & Gas Cons, ~nctiorage :~'' ~''~;~ Ill I"..i,'i~.li_:.I~-WEL["':OOM~LETION OR RECOMPLETION REPORT AND ¥60 ...... ~..~,-,,, .... --- ,- '~, .~ , ,, -- . ................. .,. ..---- ,,,-, ..... ............. ~ ~'L~.' ~"'"'" : ........~'~'~""°', ..... ' ...... ;",',"~- ;-'- ~ ' . ';-'. ,- .~ ' ' ' · '" "' '..'"~. "'%.'~,~ ....... ."-.,' .... ~ ' .[ ......... · ........................ ' ........ & f' I n 0 Ile~vlel Weft :.,:. !!.--::'" ..... ·. ,,: .... . ... , ARCO Aluka. Ino ~-27 , ,~m~:~ .... ~ ............ ,. ~ l. ...... ,l. .. ..... , ,: .~.. . ........... ' , I '~l::'~'~';~aT" .... ' L I .... : '~, T~ .... ., .~ ...l ..... , .... :,.l l .... .... : .... · :AITop p~q~BO i~g~ll ,.,~:,:,:..:,l.,,~... :. ?..:;'l'~;.:;:l',...' ,~.~:,,,~ . ~ C " ' :-.: - -- I ...... ~'~'l:--I ' "~=~'?77" '~''': ' ::'"'"',' ': ':"":" '"':'"'"'v":'~: . .. '. : .....: .:'.: '...... ,.. , . ~ · . :..: : .............. ,, ,~ ..... .~ ~ ,-,,.,:~ ..' -,._ ~ 3 ............... '. ;.~.:...:... ............. I ......... ~LA"J~e-- ... , .l ! l._ _ · '" 1 0.8/0' 7' t, 2540'- I ~680'M O/~g34'.g04~T',,JD "'~ ' i . ;... ...... -- ' ~ _ '.~~.~..--.l~_,,~ .... . .... ~ ............. '.,~, . .. .. :....' .'.. . .....- . :- .. : .- ~ .' .... · ... "" WA~R,BBL OILGRAV~Y.APl ..~..¥/%:~.~.:-.':.... .~ ....... ;yi~, 7¢.'? :. L.'." :'; ,: .:'" '": :...~'".:.. ..... ~., ~ i ;' i'I1' i i ...:; 'II:.ii: I ~ ~' '1~: ' Ij I I :l . J '' i i'..i: ' I ~ :11 il : I:.I: j: ' I J~ · J ' Ii': ..J I lll:J: . I : ' : i ';: .' .... · . J Ii ,~J.~l ;I " DESO~IP.TIONII; I:~ ;:I~I I1~1 I I f:~:'~:;I :I ::~I ' : III :': III~ I I:'II ~: : ' I: 'I I:'I:II I ;~:~II : I : II'I1:'~ ' ' :I I I I I; : I I : ...... ~'I II'I II I I I I I I I I I :1 ; ~ .... , I~'i ~I~111'j ...... ~I I~ J J ' ,;,: lJJ~l IT:JJjjI~ ; ...... : jl J J: j:l /:jj ;j:~lJ i iii i I I :J I r i I i I J J C ...... J 'Vj D ................... ":'., .' ":.:2."' .. ......... · · .'. ~- .,,4 "' ,~/l · ..... . - :'" ~ubmilitl · . .. ,''.. ~......,~, .1 'r · , · · .~,'"':':'~" ~-..-'-~, -:~ -"- / .;. .... ; ....... .~T,-: ..,.~ ,... ~. ,.,..; ....... ~ ,.....:,.,.. ........ ............ , .......... .,.~..,.,....,,,.: ..... .....~ .-___._ , ¢', '.' ' ~ ' ~' ts ~. w ' ' ..... ' . .... '-'-- :; ' - ' ..... -' ;"..¢/';;~,; :k 'J' '-;;'". ' :i ;'"-;' ':,'L:r'..::~ · t~ . .... . ..... , . ~,,,, .,..1 ..... ....... ,.,.,..,.......,....,....,,,., .,.., .... ~ ,.,,,..., . ..... , . ..j~.,.,.,,..,, lti.,..,.~ ,.....,,.,.....,..,,......¥.,.. ....... . ..... .. ,,~,., ,.~:.,, .... .... ....... .~.,.,,,.,..,.,, .... ,,..- :..,,.,'.l ~'.'.,'., '"~..~' ~.' ,:".;.~...,mH~ ~u~ : '.'. .. ,'..'."'?"::~'"'"'..'" '":'":""?'~",'":" . · ,, '. ' ', ,'?',L ,~:L.,, :<.. '.~;..-,,,~:f~:~ ...... : ...... ;., "' . , 'I "SAO'AVRNIaKTOK ' SURF /' GOLVILLE GROUP 10180' I;3512' 8907' .. ,, .. , , , . ,, , '~"'~', . :.,. ~ .,, .. r' ' #2,..., ,, l""-,.i : RECEIVED l . OOT ......, A~aska Oil & Gas CoDs. GorHmiss~o,~ INSTRUCTIONS , , General: ~Thi~ form i~ designed for submitting s compi~t~ ~fn~l ~rr~ct well ~mpi~:ion repo~ ~nd i~ on att ~pes el,lands and leases tn Alaska, .... water, dlsPoaal,' watst aupply fotinj,~tbn, "~i~¢~va~n,'lN~bn for ln-situ ~mbustlon. ' ;' ' ' ' 7" ' ' ' , ,:, ;(' .. . -. , , ~ ," ,,;', ', , ,,. ..... . .... . ..,... ., ~,,~, ,~,,,.,,,¢~ ,: , , ~:. .... o,~,~, ~,,,, ,,¢,.., ,,,~,:, ..... ,, .... . STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION Re: In the Matter of the Application ) of ARCO Alaska, Inc, and BP ) Exploration (Alaska)Inc. Filed ) Pursuant to AS 31.05 for the ) Stated Purpose of Forming the ) Pt. Mclntyre Participating Area ) and Expanding the Prudhoe Bay ) Unit Area. ) ,) Conservation File No. Withdrawal of Petition of ARCO Alaska, Inc. and BP Exploration (Alaska)Inc. ARCO Alaska, Inc. and BP Exploration (Alaska) Inc. hereby withdraw their petition to the AOGCC requesting compulsory expansion of the Prudhoe Bay Unit to include the proposed Pt. Mclntyre Participating Area. Action by the Commission on this Petition has been rendered unnecessary because of the agreement by the State of Alaska and the Pt. Mclntyre Owners to voluntarily integrate their interests in the Pt. Mclntyre field. The Pt. Mclntyre Owners' "Amended Application for Proposed Pt. Mclntyre Participating Area Prudhoe Bay Unit Expansion" and the order approving this amended application issued by the Director of the Division of Oil and Gas, Department of Natural Resources shall be filed with the Commission on or before the pre-hearing conference to be held at 9:00 AM on October 14, 1993. DATED this 13th day of October, 1993. ATTORNEYS FOR ARCO AND BP ARCO Alaska, Inc. By: Daniel G. Rodgers BP Exploration (Alaska)Inc. Marcia R. Davis ~i~E'"IVI~D 00T 1 DEPT. OF NATURAL RESOURCES DIVISION OF OIL AND GAS " · { WALTER d. HICKEL, GOVERNQR P.O. BOX 107034 ANCHORAGE, ALASKA 99510-793¢ PHONE: (907) 762-2553 ORDER The Application to Expand the Pmdhoe Bay Unit and to Form the Pt. Mclntyre Participating Area, filed on March 18, 1993, as amended by the Amended Application dated October 13, 1993, is granted. The Application to Produce the North Pmdhoe Bay State No. 3 Well as a Tract Operation, dated May 17, 1993, is granted. An Amended Decision and Findings explaining the basis for these orders will be issued before year-end. Ji~i~e c~oEr'Eas° Dated: October 13, 1993 RE EIVED OOT 1 199 Alas.ka 0il.& Gas Cons, .Comalisst0~ ARCO AI~ASKA, INC. 700 G Street, Anchorage, Alaska 99501 (907) 276-1215 BP EXPLORATION (ALASKA), INC. 900 E. Benson Boulevard., Anchorage, Alaska 99501 (907) 561-5111 EXXON CORPORATION P. O. Box 2180, Houston, Texas 77252 (713) 656-3431 October 13, 1993 James E. Eason, Director State of Alaska Division of Oil and Gas Post Office Box 107034 Anchorage, Alaska 99510 Re: Amended Application for Proposed Pt. Mclntyre Participating Area Prudhoe Bay Unit Expansion Dear Mr. Eason: On March 18, 1993, ARCO Alaska, Inc. ("ARCO"), BP Exploration (Alaska) Inc. ("BPX"), and Exxon Corporation ("Exxon") (collectively "Applicants") filed an application ("Application") with the Department of Natural Resources ("DNR") to form the Pt. Mclntyre Participating Area and to expand the Prudhoe Bay Unit ("PBU") Area to include all of the Pt. Mclntyre Participating Area. The Applicants proposed to expand the PBU to include portions of the following leases: Tract 6 (ADL 34627), Tract 7 (ADL 34624), Tract 8 (ADL 28297), Tract 115 (ADL 28298), and all of leases Tract 116 (ADL 34622) and Tract 117 (ADL 365548) ("Expansion Acreage"). The Applicants also proposed to form the Pt. Mclntyre Participating Area which included the Expansion James E. Eason, Director October 13, 1993 Page 2 Acreage and additional portions of the Tracts 6, 7, and 8. The acreage encompassing the additional portions will be referred to as the Slivers. The Expansion Acreage plus the Slivers constitutes the Pt. McIntyre Participating Area. The Expansion Acreage, the Slivers, and the Pt. McIntyre Participating Area are depicted on Attachment A. The completed Application proposed amendments to the PBU Agreement, supplements to the PBU Operating Agreement, a Plan of Development and Operations, and other unitization documents. On March 31, 1993, ARCO and Exxon requested that the DNR further delay the contraction of certain acreage out of the PBU. On April 14, 1993, Director Eason issued a decision denying the request for a deferral of contraction ("Contraction Decision"). Instead, the Director declared that certain leases, including all or parts of Tracts 5, 6, 7, and 8 (the "Contracted Acreage"), were contracted out of the PBU as of April 1, 1993. The Contracted Acreage is also depicted on Attachment A. The Slivers are part of the Contracted Acreage. The Contraction Decision was appealed to the Commissioner of the DNR by ARCO and Exxon on April 30, 1993. The appeal stayed the Contraction Decision. On August 18, 1993, Director Eason issued a Decision and Findings ("Expansion Decision") denying the Application. The Expansion Decision provided that it did not prejudice any rights which the Applicants may have to amend their proposal and to respond to the concerns raised in the Expansion Decision. See Expansion Decision at p. 27. The Applicants have met with the Director and the DNR staff on numerous occasions since the issuance of the Expansion Decision to address these concerns. Furthermore, the Applicants have provided DNR with additional information showing the basis for their proposed tract allocations. Attachment B sets forth the Applicants' proposed tract allocations. The Director has indicated that because of this new information and continued review of the Applicants' proposed allocation by the DNR's staff, he would be willing to accept the Applicants' tract allocations. On September 24, 1993, the Applicants appealed the Expansion Decision to the Commissioner. On May 17, 1993, ARCO and Exxon applied, among other things, to produce the North Prudhoe Bay State ("NPBS") No. 3 well as a tract operation within the PBU ("Production Application"). The NPBS reservoir underlies portions of Tracts 7 and 8, which were contracted out of the PBU as a result of the Contraction Decision. The DNR has not yet issued a decision on the application to produce NPBS No. 3 well as a tract operation. James E. Eason, Director October 13, 1993 Page 3 The Applicants now wish to amend their Application and request that the Director issue a decision approving this Amended Application subject to the following terms and conditions: ae With the exception of the Slivers, ARCO and BPX waive any application of the 1980 Settlement Agreement~ to the Pt. McIntyre Participating Area. b. ARCO disagrees with the State on whether ARCO has the right to deduct field costs from the State's royalty share of oil and gas from the Pt. McIntyre Participating Area. To allow production of the Pt. McIntyre Participating Area to begin, ARCO, with the exception of the Slivers, waives any right it may have to a field cost deduction from the royalty share of oil and gas produced from the Pt. McIntyre Participating Area. The field cost deduction for hydrocarbon liquids from the Slivers shall equal the volume of Pt. McIntyre Participating Area hydrocarbon liquids production attr~utable to the Slivers times the field cost deduction for oil under the terms of the 1980 Settlement Agreement. The volume of hydrocarbon liquids production attr~utable to the Slivers shall be calculated for each affected tract by multiplying the total volume of Pt. McIntyre Participating Area hydrocarbon liquids allocated to the tract by a ratio, the numerator of which is the surface area of the reservoir within the Sliver and the denominator of which is the total surface area of the reservoir on the tract as depicted in the oil pore foot map attached as Attachment C. The BPX lease in the proposed Pt. Mclntyre Participating Area, ADL 365548 (Tract 117), is on Lease Form DO&G 24-84. BPX acknowledges that the State's royalty share of oil and gas produced from Tract 117 shall be free of any field cost deduction. ~ On April 1, 1980, ARCO, BP, and the other North Slope producers entered into an agreement with the State of Alaska settling some of the "upstream" royalty issues ("1980 Settlement Agreement") in the so-called Amerada Hess litigation (Civil Action No. 77-847, First Judicial District at Juneau). The 1980 Settlement Agreement provided for a field cost allowance for PBU leases covered by the Agreement. The 1980 Settlement Agreement is the subject of a Final Judgment, Findings of Fact, and Conclusions of Law entered by the Court on August 13, 1980. James E. Eason, Director October 13, 1993 Page 4 de ee The Applicants request that the Slivers be included within an expanded PBU. ARCO and Exxon further request that the contraction of the NPBS Acreage from the PBU be deferred until December 31, 1994. These requests are not an admission that the Contraction Decision was correct. Granting these requests is not an admission that the Contraction Decision was incorrect. The NPBS Acreage, which is part of the Contracted Acreage, is depicted on Attachment A. ARCO and Exxon shall submit an application to form a NPBS Acreage Participating Area by September 30, 1994. If the application is not filed by September 30, 1994, the NPBS Acreage automatically contracts out of the PBU as of that date and no further request for deferral need be considered. If the NPBS Acreage is not included within a participating area by December 31, 1994, then NPBS Acreage automatically contracts out of the PBU as of that date without prejudice to ARCO and Exxon to apply later to expand the PBU to include the NPBS Acreage. Exxon disagrees with the State regarding their respective rights. To allow production of the Pt. McIntyre Participating Area to begin while preserving Exxon's rights and the State's rights, the Applicants propose the following procedure: Upon the issuance of an order granting the Amended Application: (1) ARCO shall withdraw its appeal of the Contraction Decision to the Commissioner and waive any right to appeal to the courts; (2)ARCO and BPX shall withdraw their appeal of the Expansion Decision to the Commissioner and waive any right to appeal to the courts; (3) ARCO and BPX shall waive any right to appeal the approval of the Amended Application; (4)Exxon shall partially withdraw its appeal of the Contraction Decision to eliminate all claims related to the Excluded Acreage; and (5) the Applicants agree that the Excluded Acreage (as depicted on Attachment A and legally described in Attachment D) is eliminated from the PBU. The Commissioner shall decide Exxon's appeal of the Contraction Decision no later than the 30th day following James E. Eason, Director October 13, 1993 Page 5 receipt of this Amended Application ("Commissioner's Contraction Decision"). Exxon waives any tight it has to a heating before the Commissioner (and related tights such as cross examination and post-hearing briefs), and waives its claim on appeal (III.J. in its brief dated June 4, 1993) that it was entitled to a hearing before the Contraction Decision was issued. 111. Exxon may appeal to or commence litigation in (or both) the Alaska Superior Court, and/or may appeal to the Commissioner, to contend among other things that the Commissioner's Contraction Decision (assuming he affirms the Contraction Decision) and other DNR decisions concerning the Pt. Mclntyre Participating Area and the Contracted Acreage were incorrect. Any such appeal or litigation is collectively referred to as the "Contest." In the Contest, (and in any other litigation, administrative proceedings, or appeal arising out of the Contest), Exxon shall not challenge the legality of DNR's established procedures or DNR's power and authority to act and make decisions concerning the contraction or expansion of the PBU, the Pt. Mclntyre Participating Area, or the Contracted Acreage, but may claim, for example, that the established procedures were not followed or that the DNR decisions or actions are not consistent with applicable law. Also, Exxon shall not claim that the DNR is disqualified from acting because the State could realize a gain as a result of the DNR's actions. In the Contest, Exxon may pursue all avenues of relief subject to the limitations in this paragraph and in paragraphs(e)(ii) and (e)(iv). Any claim for money damages, however, shall be limited to field costs under the 1980 Settlement Agreement plus interest at the Bank of America prime rate. Exxon may not contest the Commissioner's Contraction Decision and other DNR decisions concerning the Pt. McIntyre Participating Area and James' E. Eason, Director October 13, 1993 Page 6 Contracted Acreage, except as provided in this para- graph (e)(iii). Each party shall bear its own costs and fees in the Contest. This paragraph (e)(iii) does not affect the rights of Exxon and the State in the ANS Royalty Litigation scheduled for trial in April of 1995. Exxon must present its position in the Contest as if the Contracted Acreage were not in the PBU and as ff there were no deferral of contraction of the NPBS Acreage out of the PBU, until Exxon obtains a final, non-appealable ruling that the Contracted Acreage should not have been contracted out of the PBU. If Exxon obtains such a ruling, it may use the ruling in presenting its position in the Contest. Exxon, however, shall not at any time in the Contest, in any other litigation, in any appeal, or in any administrative proceeding argue or claim that it is entitled to field costs or any other costs or relief because the Slivers, the North Prudhoe Bay State Acreage, and the Pt. Mclntyre Participating Area are in the PBU as a result of granting this Amended Application or the Production Application. Exxon recognizes and agrees that such an argument would be "bootstrapping." Neither the State nor Exxon will contend that any issue has become moot as a result of approval of this Amended Application or the Production Application. The State and Exxon will join in opposing and, if necessary, appealing dismissal of any litigation filed pursuant to paragraph (e)(iii) based on mootness, absence of a case in controversy or any similar doctrine which would result in that litigation not being decided on its merits. V, By recognizing that Exxon may file litigation, the State does not waive any right or defense to the litigation. The State may assert any right or any defense, including, without limitation, the defense that any claim for relief in that litigation should be dismissed because the appropriate action would have been an appeal of the Commissioner's Contraction Decision or other DNR decisions relating to the Pt. McIntyre Participating Area and the Contracted Acreage. James E. Eason, Director October 13, 1993 Page 7 Vie By filing this Amended Application and pursuing any relief permitted by it, Exxon does not waive any rights which it may have to field and other costs under the terms of the Pt. McIntyre Participating Area leases. If it elects to assert those rights, any claim for money damages under the Pt. McIntyre Participating Area leases shall be limited to field and other costs, if any, permitted by those leases, plus interest at the Bank of America prime rate. All appellate rights of the State and Exxon, if any, are preserved. Except for the Slivers deductions provided in paragraph (b), Exxon shall not deduct any field and other costs from the State's royalty share of oil and gas production from the Pt. MeIntyre Participating Area until it gets a final, non-appealable ruling that it is entitled to a deduction. Agreeing not to take a deduction is (1) without prejudice to Exxon's right to claim it is entitled to a deduction, and (2) cannot be used by the State as evidence that Exxon is not entitled to a deduction. If Exxon is entitled to a deduction, repayment for deductions not taken will be made by credit to Exxon's then-current royalty returns until Exxon has been repaid in full, including interest at the Bank of America prime rate. Neither ARCO nor BPX will be a party to the Contest or a party to any other action by Exxon under paragraph (e)(iii) or (vi). Regardless of the outcome of the Contest, the Pt. McIntyre Participating Area and the North Prudhoe Bay State Acreage shall remain in the expanded PBU, subject to paragraph (d). ARCO and BPX shall withdraw the AOGCC unitization petition filed September 8, 1993 upon the issuance of an order granting this Amended Application. Neither the State nor the Applicants will collectively or individually reffle a similar petition or seek AOGCC review of the unitization resulting from the granting of this Amended James E. Eason, Director October 13, 1993 Page 8 g. h. Application. If anyone, including the AOGCC, appeals, contests, or attempts in any way to review the unitization resulting from the granting of this Amended Application, the State and the Applicants will defend and support all the terms of that unitization resulting from this Amended Application. Effective July 1, 1993, the State's royalty-in-kind ("RIK") nomination percentage was reduced to accommodate the expected production from Pt. MeIntyre and NPBS No. 3 well. Because Pt. McIntyre and NPBS production did not start on July 1st, the RIK purchasers have not been receiving all the barrels to which they are entitled under their supply agreements with the State. Until the RIK purchasers have a reasonable opportunity to adjust the nomination percentages to accommodate the Pt. MeIntyre and NPBS production, the Applicants will work with the State and the RIK purchasers to ensure that the RIK purchasers receive appropriate allocations of production. If necessary, the Applicants will purchase Lisburne Production Facility barrels at the values specified for royalty-in-value oil in the Applicants' respective royalty settlement agreements. ARCO and BPX are bound by their commitments in this Amended Application regardless of how the field cost issue is ultimately resolved with Exxon. Any judicial or administrative determination, or any settlement between the State and Exxon, shall not affect the rights and obligations of the State and BPX, and the State and ARCO. An order granting this Amended Application and the Production Application shall be issued no later than five working days after it is received by the DNR. A decision explaining the basis for these orders shall be issued before year-end. The order and decision shall adopt without modification the terms of this Amended Application and the Production Application. James E. Eason, Director October 13, 1993 Page 9 Under the present circumstances, ARCO, BPX, and Exxon believe that the terms in this Amended Application, which have been negotiated between the Applicants and the State, are reasonable and protect the interests of all parties, including the State. Very truly yours, ARCO ALASKA, INC. A. D. Simon BP EXPLORATION (ALASKA), INC. Marcia R. Davis, Senior Counsel EXXON CORPORATION ,.~ ~' ~ Expansion Acreage and Slivers ~ Excluded Acreage F'~ Contracted Acreage ~J Expansion Acreage ~ .. ~] WBPA EXX 34622,, Tract 117 , % ~ Slivers NE 34623 ~ract 116 ~ ,.., ~ NPBS Acreage , . , Expansion Area + Slivers = PMPA , , , ' Slivers are only part of the Expansion Acreage Contracted Acreage ' , , -- ..~ ~...-....-~.:,-~ ~ ~ :~~~ · _ Tract 27 Tract 28 ' Tract 29Tract 301 I A/E 28300 NE 28301 A/E 34628 NE 34629 Attachment A %~~ Tracu 7 !15 116 117 ADL 34627 34624 28297 28298 34622 365548 ATTACHMENT ~.~~ Pt. McIn=vre Trac= . ParticiDa=inq ~ 7.0 31.2 21.9 0.1 7.6 32.2 Pt. Mclntyre Reservoir ~X,,,x'~, Reservoir Area within Sliver Total Reservoir Area Within Tract Attachment C Ex c lu deal-~ ..~'.~A'c r e a g e Tract/Lease Tract 5 ADL-34626 Description N/2, SE/4 Section 21 and All of Section 22, T12N-R15E, U. M. Tract/Lea~e Tract 6 ADL-34627 Description N/2 Section 20, T12N-R15E, U. M. ATTACHMENT D ALASKA OIL AND GAS CONSERVATION COMMISSION October 12, 1993 WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 Honorable Charles E. Cole Attorney General State of Alaska PO Box 110300 Juneau, AK 99811 Dear Mr. Cole: For the first time in the history of our state the Alaska Oil and Gas Conservation Commission has scheduled a compulsory, unitization hearing. This hearing may lead to the forced unitization of those interests in the Point Mclntyre oil accumulation. The Department of Law is required by statute to provide the AOGCC with fulltime legal counsel.] We believe every legal precaution should be taken to best prepare the Department of Law and the AOGCC to properly proceed with compulsory unitization. We have discussed this with Assistant Attorney General Rob Mintz, who serves as our primary counsel for commission business. As we understand the situation, no attorney currently employed by the Attorney General has experience with forced unitization. Indeed, this issue breaks new ground for the state. Notwithstanding that handicap, we will proceed to satisfy to the best of our abilities our statutory obligations.' On the other hand, we believe all parties would be best served if the Department of Law were to provide fullfime legal counsel with expertise in this unusual arena. As contemplated by our statute, we would be happy to work with Rob Mintz to locate such a' person and to secure a contract only with your approbation. If you are satisfied that the legal counsel presently available from the Department of Law is completely sufficient to prepare for this unique undertaking we will defer to your legal judgment. It is our considered opinion, however, that this is a case where specialized legal counsel or legal consultants provided by the Department of Law would be of tremendous benefit to our decision-making and any subsequent defense of that decision that will rest on your shoulders. Time is of the essence. A pre-hearing conference is scheduled for October 14 and the public'hearing is scheduled for November 2, 1993. 'n Chairman cc: Rob Mintz, Assistant Attorney General 1AS 31.05.021 (a) The Department of Law shall provide fulltime legal counsel to the commission. The legal counsel provided by the Department of Law is subject to the approval of the commission. (b) The commission may, subject to the approval of the attorney general, contract for the services of additional specialized legal counsel or legal consultants. WALTER J. HICKEL, GOVERNOR DEPT. OF NATURAL RESOURCES DIVISION OF OIL AND GAS P.O. BOX 107034 ANCHORAGE, ALASKA 99510-7034 PHONE: (907) 762-2553 October 11, 1993 David Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501 RE: Point Mclntyre Oil Field Notice of Public Hearing Published September 24, 1993 Dear Chairman Johnston: The State of Alaska is a royalty owner in each of the six oil and gas leases included in the Point Mclntyre petition filed with the Commission by ARCO and BPX and dated September 8, 1993. In response to the Commission's notice of public hearing and if the Commission decides to consider the petition, the Department of Natural Resources requests that the Commission hold hearings concerning the petition. The Department intends to submit additional comments prior to the hearings and plans to have a representative at the pre- hearing conference scheduled for October 14, 1993. Sincerely, ~.es E. Eason UDirector CC: Harry Noah, Commissioner Patrick Coughlin, .Assistant Attorney General file: PtMchrrq RE,¢EIVED OCT 1 1 199~ Alaska Oil & Gas Cons. Commission Anchorage MARK ALW. XANDER 7502 ALCOMITA HOUSTON, TX 77083 (713) -561-6~89 (713)-870-0462 FAX 1017/93 State of Alaska Mr. David W. Jolmsto~ CONFIDENTIAL CORRESPONDENCE Chairman Alaska Oil and Gas Conservation commission 3001 Porcupine Drive Anchorage, AK 99~01-319Z (907)-279-1433 RE: Pendin~ hearing on motion before commission. Dear Chef, man Johnston, Pursuant to the september ~, 1993 motion previously filed before the co~mi$sion I would like to provide you with an article which appeared in the AAPG magazine in t~e 1980's. I am deleting most of those pages which do not pertain to the Kapurak' River Formation. The reason that I am sending ~'ou this article is found within the body of the article wherein it clearly identifies that a reservoir study of the Kapurak River formation was commissioned by the State of Alaska's oivision of Oil and Gas and wa~ awarded to Mr. ~. K. Van Poolen in 1978. Equally important is the revelation that another reservoir study was made in 1974, these studies allegedly can not be reproduced. The 1978 study stated that relative to the Kapurak River Formation the state of Alaska established a 3.5 billion barrel reserve for the entire structure, of which your proceedings address a small mlnori=y of =~e structure and the total reserve. Why? I have made repeated attempts to secure this report from Alaskan sources, to no avail. I have made repeated attempts for the open uooperation of your agency and others in order to obtain flow test data and confidential records on the Kup Delta 51-1, KuD Delta 51-Z, and the Pt. Storkersen #1 well, to no avail. I can not make a complete case or present all of the proper documentation before your Commission unless and until you as chairman call for, demand, and obtain the release of all "confidential information,, relative to the KaDurak River ~ormation prior to our presenting evidence before your hearing. This is critical in order to present the.entire structual picture generated Dy t~e AAPG article as well as your hearings, on the Pt. RECEgVED -1- OCT O 7 993 Alaska 0i! & Gas Seres. Commissm McIntyre participation area or the Pt. McIntyre economic reservoir limi%~ which you h~ve been publi~ally deline~ti~ ~in~e March 1993. I request that all data be made available immediately in order to pre~ent the relevant facts to your commission and to others. There is reason to exgect that correlative rights have net and are no~ going ~o ~e pru't~t~d fr~m draina~e. Producable oil migrates through reservoirs in a non-discriminatory fashion. Unit boundarie~ set by those prumotin9 specific economic analysis do not hold mother nature to task nor can an economic analysis ~eline~t~ an areal drainage ~ystem. Given such a context w~ose correlative right.~ outside the economic limit are to be protected? There are obvious dlscrepencies in =ne existing record with regard to the role of all parties and as regards the discovery mhd the development cT the entire Kapurak River structure. These discrepencies need to be cleared up in an honest and open forum. It should be apparent that certain exhibits and Conservation order NO. 317 item ~13 ~O not adequately entail the known western data points whose existence should be of no doubt to all concerned, in as much as ~his data wa~ somewhat depicted by the AAPG article as early as the 1980's and should have been studied extensively Curing the reservoir analyses of 1974 and 1978. The 1974 and 1978 reservoir studies produced by the State have not been presented in evidence before your commission and are not presently open for public scrutiny. Why? Furthermore, Conservation Order No. 317 items #17-#19 attest to the fact ~na~ in accordance with the stipulated parameters o~ that order, the Kapurak River formation as encountered in the Pt. Storkersen ~. well, the Kup Delta Wells and probably other wells on the western end of 'the structure including =hose wells listed or iden=ife~ in =ne AAPG article are and should be included within any "economic limit" or ~conomi¢ Unit designation thereof when the reservoirs encountered therein fulfill all of the parameters listed in the Conservation Order and the wells are known to exis~ within the same geologic structure. I ~eel %hat Exhib~.t II-2 as presented to your commission is a clear and obvious depiction of past practises and an omen of things =o come in that Units are formed after consolidation of ownership and by means of deprivation of information and through =~e use of such a tactic one can then expand any Unit after the affects of economic or confidential information discrimination nave manifested themselves. In essence anyone so advantaged can effectively drive out all the lesser owners Of correlate.ye rights. 'Your commission altt~ough it need not be reminded of the fact, has a duty and an obligation which I believe it will uphold if you n~ l='~ chairman are walling to demand the release of "full disclosure" of all data for the entire Kapurak River structure east to west and north to south an~ for ~11 those wells encountered therein and thereby only if you are willing to impose an inordinately ~tiff penalty and fine fcr failuz'~ to comply. I know as fact that as ~arly as Noyember of 1969 flow test analyses and other information was placed under confidential status by the State of Alaska and other~ and, that data has ye= to be revealed to the public as of this date. The enclosed affi~avit of first ~iscovery is one example. Why dOeS AlaSka condone this practise if the release of information would inorea~o oompetltion and if that in tu:'n would bring ~e state greater revenues and create an equal access, equal opportunity si~uation for on~ aha mll? It is time to reach a goal during your t~nure as C~ariman an~ fullfill the obligation that your agency agreed to as ordered and docree~ by AOGCC Conme~.~;ation Order %7~ dated April ~, 19~9. I call upon you to see that the relea, se and revelation without limitation of the information ~escribed as "confidential" in Conservation Order ~72 be revealed in its entirety, or else you. ar~ n~t in reality conducting open hearings. T~is same information was allegedly provided to the Regional Oil and Gas Supe~viaior of the USGS :~lative to ~he Pt. ~torKersen #1 well and in particular with r~gard to the Kapurak River Formation and the separate Sadleruuhlt reservoir encountered tnere~n. This information can not be found in the BLM's national archives in Anchorage. Why do you think this lm sO? While you are lucking into =~e ma~ter~ would you care to speculate as to the Sadlerochit oil reserve which was flow tested a% the Pt. Stork~resen ~1 well and in particular ~lnce that lease allegedly was and always has been outside the economic sharing limits of th~ PBU has t~ls reserve Peen ~ubject to drainage or was this reserve in truth a part of another separate pool.? What did the 1974 and 197~ reservoir analyses conclude? If ADL 34622, ADL 34623, and P.L.0, 1571 site contained PBU Sadlerochit reserves have those reserves been drained, for the last 830 years and if so whose correlative ri~'hts were protected durin~ that time? If not will you allow, your hearing and your rulings to denegrate into another repeat of the ~xhibit II-2 strateq¥! It would appear that to date overlapping structures appear to be developed only after the State of Alaska goes alon~ with =onsolldation of ownership. What other reason is thare that the Kupurak River Formation while exhibitin~ "zones of mineralization,, would be developed befere a ~eparate Sadleroohit structure would. ~asn't the Sadlerochit proven itself to be mor~ financially productive than the Kapurak~ unless one knew that a separate Sadlerochit reservoir has already been drained or that a separate SaOlerochit reservoir is of limited areal extent in 'which case when were such determinations made and who was privy ~ such information? -3- Without full disclosure, the very legitimacy of your commission and its hea~ings will be held mu~pect. It ls time Obvious discrimination which is taking place in the Alaskan oil ~ields %0 be addressed. ~uunomics are no~ the sole reason that independant Operators are not present in representative numbers on the North Slupe of Alaska an~ throughout the Alaskan oil fields in general. If you were involved with an independmnt oil company wher~ el~e in Amerlca woUld you nope to find oil? I know that tndependants are working in Alaska but why are they so few in number? I believe t~at the relationships in Alaska and elsewhere in the U.S. at the state and federal level between government ~nd industry are t~e biggest reason. Please, do the ~tght thing and release all data incl,lding the files of the Alaskan ~turney ~eneral"s o~ice whose annotation I believe is Subscribed to the Affidavi~ of First Discovery dated (~ee inm~rl~tion AGO 1023~4'/). You should suspect =~at consplcously absent from the testimony 9rovided at your hearings to date is the testimony of any ~'~pres~n'tative of =~e federal government, why when larger issues are at stake? i feel that full disclosure is necessary ~ecause of the catch 22 ~ituation present wlt~ regard to P.L.O. site 1~?1 known as U.S. Survey 4044, That situation is that either the State of Alaska witheld uonfidential data from =he U. S. government about the existence of a new KGS (Kapurak) or a separate KGS ('Sadlerochit) or in the alterna~ive the POI in obvious conflict with the USGS? own analysis of the Pt. Storkersen well and in particular the Kapurak River geologic s=ructure now known as the Pt, McIntyre =eservoir was improperly or illegally patented to the State of Alaska. ~am~lton ~ro~ers as Operators must have by sheer stupidity missed the Kuparuk River Structure of Pt. McIntyre and the separate Sadleroc~it s~ructure of an undefined new pool both of' which after they flow tested the wells, haw fortunate for those who have managed to consolidate their ownership of same. Could the timing of the 1978 reservoir study, the finding of the Pt. ~cIn~yre discovery, and the release of the $olioitor's opinion to patent to the State of Alaska and o~er rule its own a~ency ~e all coincidences? Nowhere in the overall consideration can a "zone of mineralization" subsequently described as a north-~o~]th s=rati~ra~nl¢ boundary of impermeability become the basis for your commission to find or suspect the existence of two sepa~t~ reservoirs within the overall Kapurak Structure. Although ooin¢idental, we now know' but we have not always know~ that multiple east west faultm have in the past delineated saparate Sadlerochit structures. would suggest that Mr. Eason's dissertation on th~ award of ~lsoovery royalty at Pt. McIntyr~ #3 be a good starting place to 1.ook at reasons why the Exhibits delivered to dat~ appea~ lndica=e a cloudy and undefined westerly direction of the -4- economic field limits at and around ADL 34622, ADL 34623, and P, L.O. =ito 1571, Could th= present, or past relationships between government and industry have impacted some of the reveal what lies in store fo~ the future? await your response, c..Thank you, Alexander C~ni~any, t,,ein~ £L~'~ dul~ ~worn~ dupc~se~ ~d 4C0 Prudhoe Bay---A lO.Year Perspective By H. C. Jamison=, L. D. Brockett2, and R. A. Mclntosh3 Abstract The Prudhoe Bay field ia recognized as the largest Oil field in the United ~tates. The Permian-Triassic reconfirm, e~tim~t~ t~ ~ontatn reserves of 9,0 btllio~ Of Oil and 36 Tcf of gas, have overshadowed other known substantial a~cumuiatt~ns ol hydrocarbons tn formations ranging in age frem Mississipian to Cretaceous in the gene~'al a~*ea et Pi*udi~oe Buy. Thiu ~[udy iu u ~ur~'~m~ry the geology of the Lisburne carbonate rooks, as well the Kuparuk River sandstone rese~otrs and their poten- tial. The ~gional Structure and stratigraphic relationships of other less slgnlllcant Permlan-~iasstc anO Cretaceous accumulations are also included. Perhaps unrecognized, except in mtmspe~, is nifica~e of the planned sequential availablili~ of both FeStal an~ State lan~s on the North Slope beginning ~n 1958. An 11-year period of land availabt{ity followed 14-year moratorium, The history of exploration that ted to the di~very in 1968 is presented from tha viewpoint, ~ts ~riod culminated with the (September, 1989) of NasKa "Bltl~n Dollar Sate," The post*dis~very s~n~e of exploration, develop- ment, and preclusion in the area has been characterized by environmental, social, legal, political, and economic oomplexi~ and ~ntroversy.. Compartso~ of the status of petroleum exploration today on the North Slope of with the history of the 1950s through the early 1970s is an object lesson for exploratiOnists, INTRODUCTION Mom than a dccad~ has p,,~¢d aincc th~ i~nnounccrn~:.nt of the discovery of the Prudhoe ]~ay field and the comp~etio~ of tho Prudhoc B~)' Stat~ I w~li ca April 15, 1961~. Thc w~ll wan d~'Jll~.d by Atla~'~tic R[ch.q¢ld Comgatt)' a~ operator for and Humble Oil a~d Refining Company (now Exxon). Since that Omc at tca~t t~n mor~: North Slop~ hydro;arboi~ ~u~- tiona hav~ ~en discovered by the~e and other companies. In- dustry exploration activity and interest is now at thc level since the post-discove~ 1969-19T0 ~ak ~r~od because of the ~cem~r, 1979, Fo~etaI-Szaze Beaufo~ Sea ~ase Sale. P~tmleum txplorution in no,hem Alask~ h~s focused on the pan of the Arctic basin between the Brooks Rang~ ~nd BoaUfo~ Sea. This ~gion, which contains the north slope of the Brooks Kange drainage ~ystem, thc Arctic FOothills an~ ~he Arctic Coastal Plain., is ~fe~d to as the North S}o~. lts geol- ogy ts characterized by complex st~a~igrahic 'and structural re- lationships. The ~edimen~ary section range~ in ag~ f~m p~-~vonian through ~nia~ and contains humerus zonos with reservoir potemial. Regional t=ctonics huve r~sulted in combinations of structural elements ~nd slratigr~phic varia- tions favorable for the entrapment of hydrocarbons. This t Man~scriot ~eceivea, A~ril ! 0, 1979: accepted for publication. July 30. 1979, Read ~fo~ the As~iation at Houston, Ap~l 4, 1979~ ~k Co~r~ti~, Calgary, Al~'t~, T~ writers thank t~ ARCO Oil and Gas Company tbr ~rm~ssion to publish ~ht~ ?ai~r. O~r app~ci~ioa is ~ten~ed lo company geol0gis~s of th~ Alas[a No~ Distt~cl Office in Anch~,rage, and ts~cially to P. A, Barker. J. K, I.,aw~c~, O, ~ Ma~ewski, J. C. Me~i~t, G E Player, aha R. W. Tucker for Cofltr;but~O~ to the content and prepar~l~O~ of ~[oknoWlodg~ th~ ex~ aa~iata~ce ofChafle~ Sleiglitz for p~para[~on of the il~uat:'afions. ,, Ct~pyrigl~l (~ tgg0 by The American A.s.~ociation of Petroi~:~lrn See ~opyrighl ata'tcm~n~ ~r~ thc. front of ~.h~ book. Article Iflentitleaflolt Number: ~ ' I AREA Prudh0e State l. and (4) Gull Island six locations w~m being prepared. Geologic surface work creased to 12 c~w-month~ anO seismic crew months w~n~ fram 0 to 24. Plaa~ w~.r~ undc~ way f~r a pi~ll;~e l'rom the No~h 51ope to an ice-f~e po~ in south Alaska, EventualLy Valdez was ~elec- ted a~ th~ soath~r/~ t~r~linus a~ formal announcements of the plans fbr the 800-mi ( 1,280 kin) ~ans-Alaska Pipeline System w~ mmvunced J~ February 1969. The cost wa~ estimated at $900 million. Eight m~or companies later formed Alyeska Pipeline Service ~mpany to design, construct, and opetat~ ~he pi~lin¢, (Alternates to pipeliniag were explored and Hum- ble proved th~ possiV~hty ut' use of tanket~ with the 1969 voy- age or,he SS Manhattan from the U .$, East Coast via the Non,west Passage to Pmdhoe Bay.) As exacted, exploratory drilling during 1969 roached a dra- matic new hahn ot'33 completed wells (following ~wo in 1968) and geologic crow-months reached 20 with seismic crew-months increasing to 97. All data from w~lls drilled the area we~ kept in strict confidential status pending the 23rd State ~ompetitive ~as¢ SaDe in Septem~.r, The state pa~: up almost 413,~0 acres (169,~ ha.) along the Arctic Ceast tween the Colville and Camfing Rivers, The successful bonm~ hms on 164 tracts totaled $90~,041,605 making it the on record, ~tal bids submitted exceeded $1 ~68 bill,on. This was the las~ sale held on the No~h Slope, The course of North Slope exploration following the digeav. ery and the resultant enthusiasm of the industry indicated in the so-called "Billion Boltar Sale" can best be de,cried by quot- ing Lion (1971): "The mosl significant d~velopmcnt in Alaska in 1970 was the Mginning of a storewide exploration decline brought a~ul by the combination of th~ Federal land freeze and the eonlinu~d delay in obtaining permeation tn aon~l r'uct the frans-Alaska pi~line from the Amtic Slope to the Gulf of Alaska." He further stated, "Cmltrary to ail predictions, ex- ploratory drilling in Alaska in 1970 showed an ~tarnaing de- crease of 3tg% compared with 19(O, Only 28 exploratory wells were ddJled, with 3 discoveries, all in the Prudhoe Bay a~a of the Arctic Slope." Adams' (1972) summary expressed the situ- ation in ti}is way: "Petroleum exploration ann development drilling activily in Alaska during ] 971 was visually a; a stand- stil~. Thm~ years afle~ th~ discovery of Pmdhoe Bay fi~ld, the largest oil field ever found on the Noah American continent with ~coverabte mserve~ estima~d at !0 billion bbl ofoil and 26 Tcf of gas, sta~wi0c ex pioratorv dr~lli ng declined almost fivctold and dewlopment drilling was down 49.2~, from 1970. Only six exploratory wells an~ twenty.nine development wells were completed in 1971.' ~nvironmental organizations had succeeded rhrm~h the courts in d~laying the issuance off, deral ~rmi~s to ~gin pipe. line construction, The continuing federal "land f~eze" least pauly remedied by the passage of thc Alask~ Nativ~ Claims S~ttlement Act in ~ce~n~r 1071 Ne~e~hetos~, it wa~ 6 years from the discovery to the beginning of construction of the pi~line haul road n{~h of the %kon River in April 1974, Construc6on was finally authorized i~} November !953. lowing ~ongm,~]onal and Presidential actio~, Native Regional Corporation land selections we~ eompl¢ted by December 1975 which afforded oppo~unities for companies to these areas u~der concession-type contracts with the various nati v~ a~soeiation,. From 1970 through 1974 only 35 exploratory wells were drJlle, d on the No~h Slope, bamly cxcocdirlg thc 1969 single-year total of 33. Prudhoe Bay field development drilling continued ~{ a modera~o level ~nding pipeline ap}aoval~ and actual construc, tio~, In late 1969 unitization efi~s w~re itiate~ and continued throughout this period, although at slow pace a~er 1970 when ~he duration of thc delays ~came mor~ apparent, Oeophyaicn} er~w-mond'~ agaiu ~<~<]led a high level ofg~ in 1970 and then declined to a iow of 8 ~a 1972, H, C. Jamleon, L. D. Brockett, R. A. McJntosh ,, SEA LEVEL 4,000' 6,000' 8,000' tO,oO0' 12,000' 4,000' TOOklfl FEDERAL No, t · S/~GAVANIRKTOK PM, HAMfLTON 94~10 8, NORTH PT. SEA LEVEL 2,000' 4~000' 6,o00' 8,000' ~0,00o' 4,000 ~6,000~ FIG. 7-,-No~h m south cross section, Pr~dhoe Bay Complex, For location, see structure maps of [vishak (Fig. Lisburne (Fig, 14), Kuparuk (Fig, 20), and West Sak (Fig, 2l), B ~sT 2C 4C e( 8( lox WEST UNil)N KOOKP;JK MOBIL A.R,Co., w, KUR W, SAK R, No. i No, 3~11.1t COLVILLE GP. ~ ~~ '$L 4OO0 ~j~____=-==--,-= 6000 ~ND~TONE gOOO ,FL~.'..-.;~,-, ,, , to,oeo F[O, g--East to west cross section, Prudhoe Bay f. fomplex, Fof location, see slructure map or [vishak (, Fig, I 1 ), Li,sburnc (,Fig, 14), Kup~ruk (Fig, 20), and West Sak $lmds (Fig. H, C. Jemllon, L. O. Iro~kett, R, ~. Molntolh ~ ~'-' .~ CQn~e~1on 3/8/66 Tible 1. North Slope discovery wells drifted by industry through 1977. -------------- NORTH SLOPE DtKGVERY WEL~S ~r0~¥ctive well N,lmg Zones ~e~t~ ~d$/0)1 qate Sine141? Colvflle llSnubl~K ?,$?2-7,~ ?~ ~ 4/l~/SS ARCo.H~14 Ay~yek S,~76-G,99G O~ ~ ~O~O __ sddleroChlt S,S78-8,?S0 ~iI 202~ BOPO Weh~ 9,200,9,410 0tl 434 a0Po__ ~14pah 9,~05-9.S25 O~s/Oi! i,$ ~FIO IISZ SOPO $/~/~g SteCletP USnr #I ~updeuk 6.1$O-S,lS2 011 10~ SOPO __ ~, Kupe~uk St. 10/~4/S9 $O¢i~ K~vearik Pt. 32.26 Kupa~uk 6,$98-6,947 011 ~100 GOO0 Sddl,~rochit 4,524-§,125 Gas lO.S 11/25/S9 Hamt?ton 6?OS. $$dlero~hlt 10,~S~.~0,9~GQS/011 5.5 ~?G/O 38~ 60PO 1/19/70 ARCo greeley Pt. St, ~ KUDa~k 6,6~0-~,715 OaS Z,5 ~CFO/0 4/9/10 ARGO.Hu~le 5~6 ~tver · Shubl~kg,124,9,176 Gat/oIT 3.6 ~Cr~/O 1~ 60PO 5$dleroChSt ' KQp ~ltl S1-2 Shubltk 11,56~-tl,636 Oil SZO ~P0 SadlerOchtt 1t,63~-1~,040 Oil 695 4/26/71 ARCo West Sak R. St. ~1 We~ Sak SSnd~ 3,745,4,0~ 0,I I1~ 6/I?/72 ForeSt ~tk Unit ~1 Shublik 6,D38,8,768 6$s Z ~CFG/D 4/6/7S ~btl-Socll Sad)erOChJt 10,07G-10,132 oil Z~6) GOPD ~ydyr Sty S~nte wi ~/~ltYS ~x~on Alaska St. k-I 12,56~.12,43S Oi~ ~507 60~0 (Fl~xman Ts14nd) 4/1t76 ARCO-[xxon SedleroChit 12,t2~-1~,537 Ol~ ll)~ Gull t~linU St, ~l 4/~8/76 ~hLo*BP Sag OiTti ~1Al~peh --g,276-10,1~4 0tl ?G?S BOPO ......... 12/i/?7 ExxOn Pt, ThOUGh el 1),96),13,OiO O+l 2)00 lBile~merian Sequence. [n the Prudhoe Bay area the fo?ma- , overlies the Kin[ak Shale and i~ uncont'or- overlain by Lower Cretaceous shales, This relationship it convenient to pl~ce the Kuparuk River Formation in tElle.smeriafl l~e Ellesmerlan sequence is, in most part, unconformabJy by the Brookian sequence. This unconformity, termed ~Lower Cretaceous unconformity by Jones and So?ers' is most pronoun?ed in ~he Prudho~ Day am~ where it is element of the elam and m the east alGaS the whe~ it truncates ~ entire Elle~merimn ~e- querier. Whether the unconformity exists or can be reco[nized toward the center of the Colville u'otl~h is problematical, Th~ Brookian sequence in the Foothills of the Brooks Range consists of the Lower Cretaceous Okpikruak FortT~ation, Torok Formation, and Nanushuk Group: the Upper Cretaceous Col- ville Group: and the Tertiar~ SaSavanirktok Formation. All Of these sediments were derived from southerly uplii'ted areas in what ia now tM Brooks Range. They form thick elastic wedjes in the Colville trough and thin northward over the Barrow arch. The UpDer Cretaceous and Tertia~ units progressively thicken to the noi'theast across the eastern North Slope, d~ to 298 H. C. Jamleon, L. O. Br~c,,,~ett, R. A. MClntosh . - _ T. ble 1. North Slops discovery wells drilled by industry through 1977. NORTH SLOPE {;)I$COYERY WELLS Compl etlon Produ¢ tl ye 3/8/66 -' Stnc)aiJ'Colvtile sl Shubllk 7.B72-),g22 4/15/68 ARCo-Humble Ayiya~ 6,876-6,gg8 Otl 280 BQPD P~udho~ B~y St. al Sag River 8,130 Sadlerochft 8,~08-8,~tM Oai ~5.6 MMCF/D Sadlerec~it 8,~78-8,750 Oil ~025 I)OPD '-"~a ho~ 8,750-8,883 Gas 2~ MMC~/D WahOO 9,200~9,410 0(1 434 BOPD Alapah 9~0§-g,8~0 G~/O~l ).) ~46F/0 ll~2 BOPO ,3-11-11 I1/~S/6g HamilbOn Bros. Potn~ $~orke~$e~ i/lg/?O ARCo Beeehey Pt. ----.~.-, ~ m-.. 4/9/70 ARCO-Hum~l~ 5adl,~rochi t Sadl eroCh i t ~,u~:o ruk 6,6g0-6, ?l O Gas 2.5 ~CFG./O NOrth P?udhOe St. #1 $sdlerochi t ..... ,~,,~ --: i . ~~~~ 8/)3/70 H~mtt ton BeO~, Kuearuk K~ Delta ~1,2 Shublik $~d i erochi t 4/;)§/71 A~Co West $~k $~. St. ~1 West ~ok Sands 4f6/75 t~b t ! .Sacs 1 Sadl eroch i t (Flaxman Island) 12t8/77 8xxon Pt. Thomson ~t ~~. , __ ,:~,, ~~,....,~ ..... 9,240-9,2~6 Oil/Oas 1,1 I~O~G/O 27~7 ~)OPO tl,562-I1,638 OJ~ 520 BOPO l) ,538-12,040 0~) 6~$ BOPF) 3,7<15,,4,000 O~l i)2 r~OPO 10,076-10,122 Oil 8~63 B~PO 12 ~665.12 ,635 0tl 250/ 8OPO 1~,5~8-)2,537 Oil 1152 8(J~Q 12,96.~-t 3,050 Oil 2300 90PO the Ellesmerian sequence. [n the Prudhoe Bay area the tbrma- tion conformably overlies the Kingak Shale and {s unconfor- mably overlain by Lower Cretaceous shales. This relationship makes it convenient to place the Kuparuk River Formation in thc EUesmerian sequonce. The Elleamerian sequence is. in most paR, unconfbrmabty ......... . overlain by th~ Brookian sequence. This uncon(~rmitT, teemed the l~wer Cretaceous uncontb~ity by Jones and S~ers- (19'76), is most pronounced in the Prudhoe Bay area whe~ it is a major trapping element of the field and to the east along the Ba~ow arch whom it truncates thc entire Ellesmerian sc. quence. Whether the unconformity exists or can be recognized toward the center of the Colville trough is problem~ttieal, The Brookian sequence in the R)othills et' the Brooks Range consists of the Lower Cretaceous Okpikruak Formution, Torok Formation, and Nanushuk Group; the Upper Crctaceou~ Col. v~lJe G~up; and the ~iary Sagavanicktok F~rmation. All of these sediments we~ derived f~m southerly upJiRed areas in what is now {he B~oks Range. They lbrm thick elastic wedges in the Colviile troBgh and thin no~hward over thc Barrow arch. The Upper Cretaceous and ~iary units progressively thicken to the no~heast across the eastern NoRh Slo~, doe to o 5 $6 Kilometers COLVILLE HIGH Pruclhoe Bay, Alaska 10,500 301 FiG, 1 l--$~rucliure map of top of the ]vishak Sandstone ("$adlerochit,). Star symbola indicate wells known to have discovered oit in the P~rmo- ~iassic ~rvoir section: (1) Mobil, Gwydyr Bay St,~e 1, (2) ~arnilm~ Bm ~ aruk ~I 1, (4) ARCO, Noah Prudhoe Bay State I : ~ ~ ~,,, ~. ,-~' ,-- .~~.~...~:~,~..,~1:2, (3) H~milton Brcahers, P~int Storkensen ~ ,- ........... ~,~,a contour Jme~va~ i~ levi.' ..... r~viewed in order of oldest to youngest age.,, The various reservoirs of the Pru&~oe Bay Complex are esti. mated to contain at least 23.5 billion barrels ol'oil in place, Approximately 20 billion bbl of oil in place occur in the Permian.Triassic of the Prudhoe Bay reid (H~ K~ van Poolen and Associates, Inc,, and the State of Alaska Division of Oil and Oas, 1974), An additions} 3.5 bi~lion bbt ofoi] in place are attributed to the Kuparuk River Formation (van Poo~en ~nd Alaska, 1978). Inadequate data e~Jst to m~e reliable estimates of the volume of oil in place tbr other accumulations. Com- mercial p~duetion of hydrocarbons trapped in accumuIations other than the Pe~ian-~iassic of the Prudhoe Ba~ field will de.nd primarily on economics, and thus will be ~xtremely sensitive to production rate, as well as reserves, Permo-Trlassic Reservoirs The most prolific reservoirs of thc Prudhoe Bay Complex occur within the Permian-'II-iassic section. They are the Sadlerochit Group, the Shublik Formation, and the Sag River Formation (Fig, 10), The Sadlerochit Group ha~ been defined to include, in ascending order, the tichooku Formation, Kavik Shale, and Ivishak :Sandstone (Jones and Speers, 1976). The Put River Sandstone of Lower Cre:aceous age lies uneonfor. mably on the Sag River in a limited area of the Prudhoe Bay field, bu~ is considered pa~ of the field "Permo-'ll'iassic Reset, voit." ,A number of publications, most notably those of Detter- man (1970), Dettennan et al (1975), Morgridge and Smith (1972) and Jones and Speers (1976) have described various peers of the Permo-Triassi¢ sequence and, consequently, this paper will be limited to brief discussions of the productive res- ervoir zones, Structure on top of the Ivishak Sandstone of the Sadlerochit Group in the Prudhoe Bay Complex is expressed as an east to southeast .anticlinal trend containing two prominent highs, one a~ Prudhoe Bay, and one in the. CoJville River delta area, ferred to, respectively, as the "Prudhoe high ' and the "Col. vilie high" (Fig, I l), The Complex is interrupted by a series of northwest to southeast trending downqo4he-wesl normal faults ~tween the ColviUe and Prudhoe highs. These faults have displacements of up to 2~ ft (6J m). A con~plicat¢d ties of down-to-the.no~h normal faults wilh throws of up to 1,~ fl (305 m) define the no~heastern flank of the complex. The southern flank dips regionally into the Colville t~ugh, Although test results in the discove~ well of 2~,6 million cf/d of gas and 2,025 b/d of oil from the Sadlerochi: indicated significant production rates, they do not compare to field well rates, Some typical high rates reposed in November ]978 ranged fi'om 15,792 b/d to 19,909 b/d of'oil ~Yom thc Permo-~i~azic. lvi.tha& Sandstone--The principal productive unit of the Prudhoe Bay field is the deltaic sequence of the lvishak Sand~ H, C. Jernlson, L. D. BrOckett, R. A. MclntGsh Prudhol 81¥ Unit~ IVI~HAK R?E FIG. 12~[sopach map of [vishak Sands~n,~ (",%dlerochit"), Contours in f~et. stone of the Sadlerochit Group (Jones ~nd $peers, 1976), in- formally referred to as the "$adlerochit, '" This reservoir was first encountered in the Atlantic Richfield. Humble (Exxon) Prudhoe Bay State [ discovery well (Fig, 10) where it occurs from 8,'206 to 8,673 fl (2,301 to 2,644 m) measured d~pth, Sones and S~ers defined tho type section fbr tho [vishak Sand- stone as the strata occurring within the interval 8,935 to 9,513 ft (2,723 to ~,9~ m), ~n~asured electric.log depths, io the BrRish Petroleum [9-10-1~ well. Thickness dee~as~s fi'om mo~ than 630 ft ( lpg m) in the south and southwestern par of the Prudh~ Bay Complex to less than 330 ~ (107 m) in the nogheaat (Fig, 12), Jones and Speers (1976) attributed much of the no~hward thinning in th~ field ama to pre-$hublik erosion, [n the western pas of tl~e complex, the lvishak Sandston~ thins over the Colville high, whereas east of the Prudhoe high it has ~¢n completely moved by erosion, In the Prudhoe Bay field the Ivishak Sandstone consists pri- marily et' two fine. to medium.grained pebbly sandstone quence$ ~¢parat~d by an {ntecval domineered by massive con- glom~rates. The ¢o~taet ~twe~n the Kavik Shale and the [viahak Sandstone appears gtadatJonal on mechanicaJ logs and is arbitrarily placed at thc lowest ~mu$ sandstone. The t~p of the Ivishak Sandston~ ia commonly placed at thc base of a thin, radioactive, phosphatic conglomerate that is overlain by calcareous roadsteads of th~ Shublik Formation. Sandstones of the lower sequence, are separated by major shale interbeds that were. deposited in bays between the distributary channels of a delta. The sandstones are clean, mas- sive, occasionally conglomeratic, and grade downward into finer grained sandstones interbedded with siitstone and shale that overlie ~h¢ Kavik Sh~l~. This sequenc~ i$ about 3~ m) thi¢~, Porosities and p~rn~eabilities in the ver~ fine- fine-grain~d sandstones averag~ ~bo~lt 20% and 73 md, while the fine- to medium.grained sandstones have porosities r~ng- ing from 23 lo 30% with ~rm~abititi~s raaging from 2~0 to more than 3,~0 md. The lower sandstone $~quenc~ is overlain by massive, non- marine sandy conglomerates that mark the maximum south- ward advance of the $adlemchi/delta, The conglomerates are more than 140 ft (43 m) thick in the no~heastern pa~ Prudhoe Bay field and ~hin to l~ss than 40 ft ( t2 m) to the east, west, and south, Porosities within the conglomerates usually range from 10 to 20% wRh ~rmeabitities ranging From less than 30 to t~or¢ than 1,000 md. Overlying the conglomerates a~ homogeneous fine- medium-grained sandstones of the upper sandstone sequence, The basal pa~ was probably deposited in braided streams, whii~ the uppermost rocks indicate a nearshom marginal-marine environment. The up~r sandstone is mom than 2~ ~ (61 m) ~hick in the southwest and thins northe~lstw~d. Porosities g~nerally range from 25 to H. C. Jaml,on, L.D.( c/(ett, R. A. Mclntosh Miles and diameters of I mm or [ess (Zone (3) "enrollee Interval"-.4,790 to 8,930 fl (,2,679 to 2,557 mt--The upl~r pan of the Wahoo i~ ized by an abundance of small ( 6it t mm) diameter, algai-encrusted grains with t~ren~lute outer Associated Poraminifera identi fy this interval as Zone Kupar.k River Formation The Kuparuk River Formation consists ot'.~:md~tone.s, ~:ilt ~tcme:., and shales of Lower Cretaceous age deposited in a shallow marine, tidal-influenced environmnnt and derived, least in part, from a southerly or easterly source. [t is present over the western and southwestern part of the ~udh~ Bey Complex, as well as along the no~hern flank, it lies confor- mably on marine Kingak Shale. The Nn~h Slo~ Stratigraphic Committee of the Alaska Geological Society (1970-1971) formally named thi~ i~telval the Kupamk ~iver Sands and d~- fin¢d the type section. Detterman 0[ al ( 1973} used the term, "the Kuparuk River Sand," while lone, and Sp¢crs { 1976) t~r to it as Ihe Kupartlk River FOrmation. The interwtl between 6,474 and 6,880 ft { i ,973 to 2,097 m), in the ARCO ~ .,..-,~iver Sta{e I woll, was s~l¢cted aa illustrative of the Kuparuk '",iv~r Formation for this ~a~r haeau~, of the well ~s near the center of tho Kupa~k de~sitiona[ area and b,caus~ much of the interval was ¢omd (Fig, Along gh¢ shor~ uf the Beaufort Sea the Kupart~k I~as identified in wells in an area at least 18 mi (28.9 kin) noah to .south and g~ater lhan 3~ mi [>~.3 kin) east to wesL Although thc noah~rn and ~uthern limits are no~ d~fined, ~xisting 'well control indl¢~t~ ~at th~ ~ormation thickens to mo~ than ft (183 m) ~o~heastwaM b~ncath the Beaufort Sea and thins le~:~ than 90 ft (27 m) in thc wesl, south, and southeast (Fig. 18), This thinning can ~, ~br the most pa~, attributed to trun- cation b7 the Lower Cretaceous unconformity, However, thin- ning may also be attributed m local erosional unconl~rmities or depoaidonal ~iatuses within the formation (Fig. 19). In the subsurfae~ the top et'the Kuparuk River Formation has b~cn encountered at depths ranging from Less than 5,800 ft ( !,768 m) to ~eeper than 9,~ ft (2,743 m). It is contoured au easterly plunging anticline ~runcated on the noahwest and south¢ast by the Lower Cretaceous unconformity (Fig. The so~thwcstetn flank of the structure ~s not defined. Tho no~hcastem flank is interrupted by normal hulls tha~ control hydrocarbon accumulation~ in this area, The Eileen hull t~nds sm~w~stwatd from the ARCO N{mhwe,q~ F. ileen 1 and may separate accumulations in thc West Sa~ area on thc south l~m thvse on th~ north. Th, structur~ devie~d north the ~ileen fault is generalized, and hydrocarbon trapping pears to ~ misted 1o ihult closures or stratigraphy or ~th, However, because of the lack of adequate well contel, these accumulations am difficult to Ltt~ologies and Sedimentation ~Three sand momars, Prudhoe Bay, Alask= 309 .&'O ! 0 5 !0 Mrles L .... J :£ --- ,.li~ 0 8 t6 Kilometers A.R.Co. W. ~k Mub:hPh;!l,p$ Ye. 7-';~.72 '~iabcon.'i: Fine Gra.ne¢. ~ri,~c, ne ICe, ] Prudhee + I FIG, J, 9--A. Fence diagram, guparu~, River Formation, Shows relationship of lower, middle, and upper Kupuruk diagram index. H. C. Jarnl,on, L., D, Brt ,ett, iq, A, M¢lnto,h 0 5 ~0 Mil~s 0 i~ 16 Kilom~t~r~ $1~it ¢~1~iI# $t. ~. , Unt~ W, SAK AREA A¢ WELL CONTROl. ~_~ OI$COVEPt¥ WELi,$ /~a $~'-~ Prudhoe gay Unit R6E FIG, 20---Structure map of top o~' Kuparuk River Formation. Star symbols indica~ wells thai have discovered hydrocarbons. Sub,ca contoue~ in for'really termed the "Upper, Middle and Lower Sands," se, para/ed by shales and silty shale,~, are the primary Kuparuk res- ervoirs of the Prudhoe Bay Complex (Fig. 17), The formation is unconformably overlain by an unnamed Lower Cretaceous shale, The "Lower Sand' is the most widespread of the sand mem- bers and can be correlated throughout most of thc mapped area (Fig.. t9), It ranges in thickness t¥om about 35 to 75 t't (10.7 to 22.9 m), with average porosities ranging bctween 20 and 27% an~ permeabilities ap to 500 md. The "Lower Sand" differs from the "Upper and Middle Sands" in tl~at it exhibits exten- sive .sedimentary structures c haracteristic of current and wave action, Low-angle crossbeds and planar or horizontal lamina- tions are common, as well as ripples, Silt and clay layers indi- cate changing environmental energies, The "Lower' Sand" oc- curs as either two or three el~ctric-log benches probably formed by the: interfingering of two or more sand bodies, Fine sand and sUt are the predominant constituents with less than 20% discontinuous shale layers.. The lens-shaped shale faycrs ~r¢ commonly a few millimeters to several centimeter.~ thick. Characteristics el: the "Lower Sand," such ,us planar tuminae and ripples, clay laminae, and variable development o[ the benche.~, indicate that it was deposited in a ncarshom emtiron- mcnt, possibly adjacent to an emergent area east of Prudhoe It~y, The "Lower Sand" ov¢rlics an interbedded sillstone and dark gray, pyritic shale mem~r thai becomes shallot toward the base with t'~wer and fewer interbcds of silt and very fine sand. Overlying the "Lower Sand" is an interval of thinly in- terbedded cyclic sands, silts and shales probably deposited in a tidal ~nvironment, Shale layers I to 2 cm thick are draped over lenses and thin beds of silt and sand that are ripple and planar laminated. Normally, the lenses are I to 3 cm thick and 3 to 7 cm long. The sands are very fine to fine-grained and corn, inertly contain thin laminae of clay, Worm burrows are com- mon in the shales and mollusk burrows, although uncommon, are present, The sands and silts in this interval are oil sat'urn- ted, arid chef:et'ore, may contribute to a small degree to the pro- ductivity of the Kuparuk, The "Middle and Upper Sands" differ f'¥om the "Lower Sand" in that they are glauconitic and lack sedimentary strut- tums. Biologic activity or turbulence at the ~[te of depo,sition could have prevented formation of or destroyed sedimentary strutting. The "Middle and Upper Sands" are similar litholo- gically, bm differ in thickness and distribution (Fig, t9). Both sands are very fine to medium grained, glauconitic, and fie- qucnfly moderately to poorly' sorted. Glauconite is considered an excellent indicator of marine conditions and frequently oc- curs as an alternation of fecal pellets, This appears to be the ca~e in thc Kuparuk sands and suggests that bioturbation is the cause of the lack of sedimentary structures, Of the three sands, the "Middle Sand" is thinnest and ranges 5 lO MHe,~ "t 16 KilOmeters Prudhoe Bay, Alaska OCT 0 ~ ~-. H& ...... INTERSECTION WITH $1AEE PERMAFROST Pru(iho~ ~l~ tJ~it~ 311 CONTINENTAl. FACIES FITS. 2J--Structure map of top of' W~st SGk $~nd~. Eubsea ¢ontour~ Jr~ feet, from less than 10 ft (3 m) to almost 20 fl (6 m) thick. Average porosity range~ between 20 to 25% with permeabilities up to 525 md, At present, the "Middle Sand" is ti~ought ~o have been de.sited as a sobtidal shoal. The fine groin size and bioturbation suggest that the "Middle Sand" was deposited in a relatively low ~nergy environment, The "U ~r Sand"sleuths thickness of mom ..... ~,p ............... a than 150 ft (46'm) in the Hamilm~'~i'h'~F~"~oi~'t '~'~;~-i~fi' ~I'I':""AV~ -- ' ...... ' ........ ~ .................. * ............~ 'r age ~ros~ty raDg~'from 20 to 22~: w~th ~rmea~0e.s up to 266 md, !t has been truncated to the south and southeast and shale~ out to the no~hwest, suggesting a southerly or south.. easterly source (Fig. 19), Between the "Middle" and "Up~r Sand' is a silty shale mem~r which exhibit~ a transitional change twin shale al its base to silts at the top, The silts, in turn, grade into the "Upper Sand" with no visible bre~ in deposition, Bedding tends to- ward planar rather than lenticular. The lower shaly part is not extensive, occumng only in the ARCO West Sak River State and Northwest Eileen 1 wells, The silt pan is found wherever "Up~r Sand" is present, An unconformity appears to be present ~tween the silt and shade, Overlying the "Upper Sand" is bioturbated, silty, muddy shale, ~ge~Tabben and Bennett (1976) identified the Kuparuk River ~rmation in the ARCO We. st Sak River State 1 as being NeoeomJan in age, Thirty-four microplankton .s~cies were cumentefl from conventiona] cores obtained l~om this well, The Neocomian assemblage can be correlated wilh sediments from southern Alaska and northern Canada, However, Foraminifera presenl in the Kuparuk River For- mation are of mixed Late lurassic and Early Cretaceous ages and can be con'elated with surface sections collected by the U,S, Geological Survey in northeastern Alaska, The fauna l¥om these sections has been called a transitional fauna by Bergquist (Detterman et al, 1975), suggesting that the Kaparuk repmsenls continuous deposition beginning Late Jurassic and extending into the Early Cretaceous. The reason that the faunas are mixed is not clear. Reworking is not considered likely be- cause Jurassic species occur in great abundance and outnumber Cretaceous species 2 to 1; and, additionally, the mixed assem- blase occurs in every Kuparuk well ex,mined in the area. Pos- sibly the Jurassic and Cretaceous species which occur in these sands have a longer range than previously thought, Exploration History~In 1969 after the discovery a~ Prudhoe Bay in 1968, the industry drilled numerous wells in the region between the Colville and Canning Rivers to evaluate acreage to be ieased in the Se. ptembea:.lg_6.~,.lease t~ul¢, During this spurt activity, Sinclair discovered the pro~iuctiv¢ Kup~ruk "Lower Sand" in th.e__Ugnu Stat~ t_w' ..h. ich.les, ted.. 1,0.5..6. h/.~.fff..oii,;... ARCO's Northwest Eileen I recovered small amounc,~ droll frolr~ the "Middle and Upper Sands" and Mobil ~s West paruk.,}-..} ~- 11 te~tE..d...'.2. ,...2._2_0......b_/..d. U., "Ex,, ploration activity remained high in the Kupar~k area into 1970 as various COmpanies continued to evaluate "Sadlerochit" and/or Lisburne ,~tructural anomalies on their existing and Suite 6a) 1~1 W~s~ 4~h A~,~nue STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: In the Matter of the Application ) of ARCO Alaska, Inc. and BP ) Exploration (Alaska) Inc., Filed ) Pursuant to AS 31.05 for ) the purpose of forming the ) Pt. McIntyre Participating Area ) and Expanding the Prudhoe Bay ) Unit Area. ) ) Conservation File No. NOTICE OF APPEARANCE OF EXXON CORPORATION Exxon Corporation hereby gives notice of its appearance as an interested party in this proceeding. Exxon appears in its capacity as lessee and working interest owner of certain affected state oil and gas leases and, independently, as a party to the Prudhoe Bay Unit Agreement and lessee and working interest owner of certain other state oil and gas leases within the Prudhoe Bay Unit. The leases owned by Exxon Corporation that are directly affected by the petition because they would be included in the proposed Pt. McIntyre Participating Area are the .following: ADL 28297, ADL 28298, ADL 34622, ADL 34624, and ADL 34627. RE EIVED 0 CT - 7' 199 Alaska Oil & Gas Cons. Comm'tsstoo Anchorage Suite 1031 West 4th A~ot'nue (~0 Exxon Corporation supports the plan of unitization as set out in the Arco/BP petition and urges the Commission to grant it according to its terms. For the record, Exxon reserves its right to protest and oppose any alternative proposal that might be presented whereby the proposed Participating Area would be approved subject to terms or conditions different than those set forth in the petition, or any proposal that might be presented to establish a separate unit outside of the Prudhoe Bay Unit for production of the Pt. McIntyre and Stump Island reservoirs. For the record, Exxon Corporation notes that the matters addressed Paragraphs 23 and 24 of the.Petition filed by ARCO Alaska, Inc. and BP Exploration (Alaska), Inc., are legally immaterial to the Petition and are not within the scope of the legal authority exercised by the Commission. Exxon Corporation has no objection to any agreement that any other lessee may choose to make with the State or any other party. However, Exxon does not join or concur in such agreements or acknowledge that such agreements have any relevance whatsoever to the Commission's consideration of the pending Petition. Exxon Corporation reserves its rights to participate in any and all hearings, conferences and other proceedings in this matter. NOTICE OF APPEARANCE OF EXXON CORPORATION PAGE 2 RECEIVED OCT - 7 Alaska Oil & Gas Anchorage Bo~~A~ Suite 600 liB1 West 4th A~enue (~T/') 276.4557 All notices, pleadings, correspondence and other documents .should be served upon Exxon Corporation through the undersigned counsel. Dated this ? ~ day of October, 1993, at Anchorage, Alaska. Gary E. Baker Exxon Corporation Law Department P.O. Box 2180 Houston, Texas 77001 (713)656-3431 - Phone (713)656-6123 - Facsimile BOGLE & GATES 1031 W. Fourth Avenue, Suite 600 Anchorage, Alaska 99501 (907)276-4557 - Phone (907)276-4152 - Facsimile Jame~ N. Reeves NOTICE OF APPEARANCE OF EXXON CORPORATION PAGE 3 RECEIV[ OCT - 7 199 Alaska O~I & uas Oo;",s. Anchorage Su/tc 1931 West 4th A~nuc (ffiT) 2764557 Re: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of the Application ) of ARCO Alaska, Inc. and BP ) Exploration (Alaska) Inc., Filed ) Pursuant to AS 31.05 for ) the purpose of forming the ) Pt. McIntyre Participating Area ) and Expanding the Prudhoe Bay ) Unit Area. ) ) Conservation File No. AFFIDAVIT OF SERVICE STATE OF ALASKA THIRD JUDICIAL DISTRICT Cathy Symonds, being first duly sworn, states and deposes as follows: 1. I am a secretary with the firm of Bogle & Gates; 2. On October 7, 1993, I caused a true and correct copy of NOTICE OF APPEARANCE OF EXXON CORPORATION in the above-captioned case to be served by first class mail on the following: Daniel G. Rodgers, Esq. Senior Attorney ARCO Alaska, Inc. 700 G Street Box 100360 Anchorage, Alaska 99510-0360 0 CT -- ? Alaska Oil & Gas Cons. (,;urnmissio,, Anchorage BOG~AT~ Suite riO0 10~1 W~t 4th (907) 2764557 Marcia R. Davis, Esq. BP Exploration (Alaska) Inc. 900 E. Benson Blvd., Box 196612 Anchorage, Alaska 99519-6612 Harry Noah Commissioner Alaska Department of Natural Resources 400 Willoughby Avenue Juneau, Alaska 99801-1724 James Eason Director Alaska Department of Natural Resources Division of Oil and Gas P.O. Box 107034 Anchorage, Alaska 99510-0734 of FURTHER YOUR AFFIANT SAYETH/N~UGHT...../~-Q~ II W~BSCRIBED AND SWORN to or aff'~rmed before me this 6..}E,~'~.~ , ~ ~ ~ 3. Nota~V Publi~ for AFFIDAVIT OF SERVICE PAGE 2 0 CT - ? ~99~ Alaska Oil & Gas Cons. L;omm'~ssto~' 'Anchorage day ARCO Alaska, Inc.('` Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 276 1215 September 24, 1993 ORIGINAL Mr. Harry Noah, Commissioner State of Alaska Department of Natural Resources 4Q0 Willoughby Avenue, 5th Floor Juneau, AK 99801-1724 RE: Appeal From the August 18, 1993 Decision and Findings of the Director of the Division of Oil and Gas Regarding the Application for the Third Expansion of the Unit Area and Fromation of the Pt. McIntyre Participating Area, Prudhoe Bay Unit Dear Commissioner Noah: Enclosed is ARCO Alaska, Inc.'s ("ARCO") appeal of the above- referenced decision of the Director of the Division of Oil and Gas. ARCO is filing this appeal in order to preserve its appeal rights. We'remain hopeful that the parties will be able to reach an agreement and that Pt. McIntyre will be included in the Prudhoe Bay Unit through the voluntary unitization process. If the parties are able to reach such an agreement, ARCO will, of course, withdraw this appeal. Very truly yours, Andrew D. Simon /cs Enclosure c: Anchorage Office of DNR Commissioner (w/encl.) Mr. James Eason, Divison of Oil and Gas (w/encl.) Mr. David Johnston, Chairman, Alaska Oil and Gas Conservation Commission RECEIVED noah924.1tr s E P 2 4 1993 Alaska Oil & Gas Cons. Anti. rage ARCO Alaska. Inc. is a Subsidiary of AtlanticRichfieldCompany AR38-6003-C RECEIVED STATE OF ALASKA S EP 2 4 AlaSka l)il & G~s Cons. ~mmission BEFORE THE DEPARTMENT OF NATURAL RESOURCES Appeal from the August 18, 1993 Decision and Findings of the Director of the Division of Oil and Gas Regarding the Application for the Third Expansion of the Unit Area and Formation of the Pt. McIntyre Participating Area, Prudhoe Bay Unit. SPECIFICATION OF DECISION BEING APPEALED 11 AAC 02.030(a) (5) ARCO Alaska, Inc. ("ARCO") and BP Exploration (Alaska) Inc. ("BP"), as operators of the Prudhoe Bay Unit, and ARCO, BP and Exxon Corporation (,,Exxon,,),1 in their separate capacities as leaseholders ("Leaseholders"), hereby appeal from the August 18, 1993 Decision and Findings of the Director of the Division of Oil and Gas regarding the Application for the Third Expansion of the Unit Area and Formation of the Pt. McIntyre Participating Area, Prudhoe Bay Unit (the "Decision"). A copy of the Decision is attached as Exhibit A to this appeal. This appeal is made pursuant to 11 AAC 02.010(c). II SPECIFICATION OF REMEDY REQUESTED 11 AAC 02.030(a).(6) On March 18, 1993, Leaseholders filed with the Division of Oil and Gas their Application to Expand the Prudhoe Bay Unit and Form the Pt. McIntyre Participating Area within the Prudhoe Bay Unit, consisting of Alaska State Lease Numbers: ADL 28297, ADL 28298, ADL 34622, ADL 34624, ADL 34627, and ADL 365548 ("Application"). The Director's Decision denies Leaseholders' Application. Leaseholders request that the Director's Decision be reversed and that the Pt. McIntyre Participating Area be formed and the Prudhoe Bay Unit be expanded in accordance with Leaseholders' Application. 1Exxon is filing a supplemental appeal in this matter. III SPECIFICATION OF GROUNDS ON WHICH APPEAL IS BASED 11 A3~C 02.030(a)(6) The Decision fails to recognize or apply the State's obligations and Leaseholders' rights under the DL-1 lease contracts between the State and Leaseholders and constitutes a breach of those contracts. · The Decision fails to recognize or apply the State's obligations and Leaseholders' rights under the 1980 Settlement Agreement between the State and Leaseholders and constitutes a breach of that contract. The Department of Natural Resources ("Department") did not comply with the statutory requirements for enactment of a regulation (AS 44.62.010 - 44.62.650) when it adopted its rule that producers must give up any claim that DL-1 leases do not bear field costs before the State will approve an application for a voluntary unit. · The Decision is an attempt to compel Leaseholders to forego their contractual and other rights by the improper exercise of economic duress. · The Decision exceeds the statutory authority of the Director and of the Department. · The Director has ignored or failed to act upon the factors that should properly have governed his decision and has utilized his decision-making authority to achieve an improper purpose. · The Decision constitutes an improper taking of property rights and denies Leaseholders due process of law. · The Decision constitutes an abuse of the State's authority as sovereign in order to advance its proprietary interests. · The Decision recites and relies upon language in lease contracts other than DL-1 leases and improperly applies that language to govern DL-1 lease contracts. 10. The Decision fails to recognize that the public interest is served when the State fulfills its contract rights and is disserved when the State breaches, attempts to evade or abrogates its contractual obligations. The Decision violates APPEAL - 2 - public policy and constitutional prohibitions against the impairment of contracts. 11. The Decision fails to follow the mandates and guidelines of the regulations governing unit expansion which require that the requested expansion be granted on the facts in this case. 12. The Decision fails to apply or follow the terms of the Prudhoe Bay Unit Agreement which provide that the requested unit expansion should be granted in this case. 13. The Decision improperly applies regulations or criteria promulgated after the State entered the lease contracts at issue here and after its entry into the Prudhoe Bay Unit Aqreement. Retroactive application of those regulations and criteria violates the State's governing contractual obligations. 14. The Decision erroneously concludes and provides no authority for its assertion that expansion of the Prudhoe Bay Unit was not intended to extend to expansion to include reservoirs or pools not discovered in 1977. 15. The requested expansion (1) promotes the conservation of all natural resources, (2) promotes the prevention of economic and physical waste, and (3) provides for the protection of all parties of interest, including the State. The State interests subject to protection do not include a right to avoid its contractual obligations. 16. The Decision correctly concludes that Pt. McIntyre operations, resource conservation and the reduction of environmental impacts will be facilitated if the Pt. McIntyre Participating Area is able to share in the use of Lisburne facilities and Prudhoe Bay Unit infrastructure, but erroneously concludes that creating a separate Pt. McIntyre unit would be as effective in accomplishing those goals as allowing expansion of the Prudhoe Bay Unit. 17. The Decision correctly concludes that expanding the Prudhoe Bay Unit will prevent economic and physical waste, but erroneously concludes that creating a separate unit under terms more favorable to the State would accomplish the same goals. The Decision abuses and exceeds any discretion and authority the Department has in conservation matters to force an unfair economic and proprietary advantage. 18. The Department may not utilize whatever sovereign authority it has over unitization and conservation matters to compel its lessees to forego their contractual rights or to extract from APPEAL - 3 - its lessees proprietary economic advantage. The exercise of such economic duress abuses and exceeds the Department's constitutional and statutory authority and constitutes a taking of property without due process of law. 19. The Decision erroneously concludes that the ability of the Pt. McIntyre lessees to utilize Lisburne facilities and Prudhoe Bay infrastructure is the same if the Pt. McIntyre leases are in a separate unit as opposed to being included in the Prudhoe Bay Unit. The ability of Leaseholders to use Lisburne facilities and Prudhoe Bay Unit infrastructure to conduct Pt. McIntyre operations is the result of facility sharing agreements that took years to negotiate. These facility sharing agreements were based on the premise that Pt. McIntyre would be produced as part of the Prudhoe Bay Unit. No agreements exist for the sharing of Lisburne and Prudhoe Bay Unit facilities with Pt. McIntyre if Pt. McIntyre is formed as a separate unit. 20. The Decision improperly attempts to apply the terms of statutes as subsequently amended, including both AS 38.05.180(f) and AS 31.05.110, to abrogate or avoid its preexisting contractual obligations. 21. The State improperly relies on the provisions of later lease and unit agreement forms as a basis for establishing policy and construing its rights under the DL-1 lease form and the Prudhoe Bay Unit Agreement. 22. The Decision misstates both facts and law in presenting arguments on issues now pending before the Superior Court in the ANS Royalty Litiqation. The Director has improperly attempted to use whatever discretion and authority he has on the issue of unit expansion to distort the record and influence the outcome of that litigation. 23. The Decision improperly recites the 1979 Compton memorandum, which was never finalized as an order or decision and was superseded by the 1980 Settlement Agreement as the result of a Final Judgment entered by Judge Compton. The Director's attempt to use the Compton memorandum as authority for his position violates the State's agreements as part of the 1980 Settlement. 24. The Decision is based on an incorrect assertion that the State has consistently taken the position that its royalty share is free of field costs under its DL-1 leases. 25. The Decision fails to acknowledge that Paragraph 32 of the DL- 1 Lease form and AS 38.05.180(p), upon which the Decision APPEAL - 4 - relies, requires the consent of the lessees to change royalty obligations. The Department cannot properly extract consent by the use of economic duress or by the abuse of its status as a sovereign. 26. The Director has incorrectly characterized the 1980 Settlement Agreement and has improperly attempted to use any authority of the Department with respect to unitization to avoid or compel changes in the terms of the 1980 Settlement. 27. The Director has improperly attempted to use any authority that the Department may have with respect to unitization to extract a "share" of "benefits" not otherwise held by the State. 28. T~e Decision improperly rejects an allocation of production and costs using a value based method as provided by 11 AAC 83.371. 29. The Decision improperly attempts to require that production be allocated more heavily to leases providing for a higher royalty percentage and less heavily to leases providing for a lower royalty percentage. 30. The Decision improperly attempts to base decisions on unitization on the interests of the State and its royalty in kind buyers under their royalty in kind contracts. 31. The Decision improperly attempts to use any authority the Department may have regarding unitization as a device to preclude judicial determination of the State's contractual rights and obligations. 32. The Department improperly delayed its determination that the Application was complete. 33. The Department predetermined the outcome of this matter as evidenced by its direction of its royalty in kind purcharers' nominations for commingled Pt. McIntyre production at the Lisburne Production Center LACT meter to TAPS and as evidenced by its correspondence to ARCO regarding Pt. McIntyre pipeline nominations. 34. As a result of its direction of its royalty in kind purchasers' nomination practices and as a result of prejudging . the outcome of this matter, the Department wrongfully created a disincentive to its granting of the Application. APPEAL - 5 - IV STATEMENT OF ADDRESS FOR NOTICES OR DECISIONS 11 AAC 02.030(a) (7) Daniel G. Rodgers ARCO Alaska, Inc. P. O. Box 100360 Anchorage, AK 99510-0360 (907) 265-1354 (907) 265-6998 (Fax) Gary Baker Law Department Exxon Company, U.S.A. P. O. Box 2180 Houston, TX 77252-2180 (713) 656-3431 (713) 656-6123 (Fax) Marcia R. Davis BP Exploration (Alaska) Inc. Box 196612 Anchorage, AK 99519-6612 (907) 564-5018 (907) 564-4031 (Fax) IDENTIFICATION OF AFFECTED LEASES AND LANDS 11 AAC 02.030(a) (8) This appeal affects the following leases and lands: Tract No. Description PBU Expansion Area ADL Serial No. T12N-R15E, Sec. 18: Ail 34627 T12N-R14E, Sec. 13: Ail Sec. 14: Ail 34624 115 T12N-R14E, Sec. 15: Ail Sec. 16: Ail Sec. 21: N1/2 NE1/4 T12N-R14E, Sec. 17: N1/2, N1/2 SE1/4, NE1/4 SW1/4 excluding U.S. Survey 4044 28297 28298 APPEAL - 6 - Tract No. 116 Description T12N-R14E, Sec. 3: Ail Sec. 4: Ail Sec. 9: Ail Sec. 10: Ail ADL Serial No. 34622 117 Those Lands in Block 605 lying northerly of the north boundary of Section 3, T12N, R14E, UM, AK. (Identical with line 4-5 on Block 605) and lying easterly of the west boundary of Sections 2 and 11, T12N, R14E, UM, AK (identical with line 5-6 on Block 605) and lying northerly of the south boundary of Section 11 and 12, T12N, R14E, UM, AK and lying northerly of the south boundary of Section 7, T12N, R15E, UM, AK (identical with line 6-7 on Block 605), within the offshore three-mile arc lines listed as State Area on the "Supplemental Official O.C.S. Block Diagram approved 12/2/79. 365548 VI REQUEST FOR HEARING 11 AAC 02. 030 (a) (9) Leaseholders request a hearing to make presentations concerning the legal and factual issues involved in the appeal. The issues that need to be decided are whether the Pt. McIntyre Participating Area should be formed and the Prudhoe Bay Unit Area should be expanded in accordance with the Application. Many of the grounds specified in Section III involve factual issues that need to be resolved. In accordance with 11 AAC 02.050(b), Leaseholders request that the hearing process include such normal due process procedures as the right to present oral testimony, cross-examine witnesses, and file post hearing briefs. APPEAL - 7 - VII NOTICE OF INTENT TO FILE ADDITIONAL MATERIALS 11 AAC 02. 030(b) Leaseholders intend to file a brief and/or additional written materials, which may include exhibits, in support of this appeal. Leaseholders reserve the right to supplement their factual and legal claims in this appeal after all relevant records have been made available. DATED this 2~=~day of September 1993 at Anchorage, Alaska. ARCO A.laska, Inc. Exxon Corporation Joel W. Kiker Production Manager, Alaska Interest Organization Exxon Company, U.S.A., a Division of Exxon Corporation Andrew D. Simon Manager, Lisburne and Pt. McIntyre ARCO Alaska, Inc. BP Exploration (Alaska) Inc. By: Manager, Lisburne and New Development APPEAL - 8 - Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission RIGINAL Re: The application of ARCO Alaska, Inc. and BP Exploration (Alaska), Inc. filed pursuant to AS 31.05 for the stated purpose of forming the Pt. McIntyre participating area and expanding the Prudhoe Bay Unit area. NOTICE IS HEREBY GIVEN THAT ARCO Alaska, Inc. and BP Exploration (Alaska), Inc. have petitioned the Alaska Oil and Gas Conservation Commission under AS 31.05.110 to order formation of a Pt. McIntyre participating area and expansion of the Pmdhoe Bay Unit area in accordance with a Plan of Unitization submitted with their petition; and that a hearing on this petition will be held in conformance with 20 AAC 25.540 at the Z. J. Loussac Library, Assembly Chambers, 3600 Denali Street, Anchorage, Alaska, at 9:00 AM, on November 2, 1993. All parties and other interested persons are invited to attend the hearing and present testimony. Commission consideration of this petition will not necessarily be limited to the question of granting or denying the petition as presented but may also include consideration of alternative means of unitizing all or a portion of the Pt. Mclntyre and Stump Island pools such as a creation of a new unit. Parties and other interested persons accordingly will be afforded the opportunity to address any such alternatives in their testimony and comments. A pre-hearing conference will be held at the Alaska Oil and Gas Conservation Commission, 3001 Porcupine Drive, Anchorage, Alaska 99501, at 9:00 AM, on October 14, 1993, phone (907) 279-1433. Persons wishing to participate in the hearing are invited to attend the pre-hearing conference and address the following subjects: 1. Briefing 2. Procedures for presenting testimony 3. Procedures for presenting exhibits 4. Estimated length of the hearing 5. Handling of information claimed to be confidential 6. Conduct of the hearing 7. Other matter--hearing conference D avid W'_ _J ~hnst o n,~C hhirman ' Alaska Oil 8~' as C nservation Commission Published September 24, 1993 ARCO Alaska, Inc. Post Office Box ]00360 Anchorage, Alaska 99510-0360 Telephone 907 265 6375 James D. Weeks Senior Vice President September 8, 1993 Mr. David W. Johnston, chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, Alaska 99501-3192 Re: Petition of ARCO and BP - Pt. McIntyre Dear Chairman Johnston: Enclosed for filing please find an original and two copies of ARCO's and BP's joint petition requesting the Commission to order expansion of the Prudhoe Bay Unit to include the proposed Pt. McIntyre Participating Area. Although we are filing this petition with the Commission, we are continuing to work closely with Exxon and the Department of Natural Resources to resolve differences and form a voluntary unit. We remain hopeful that the parties will be able to reach an agreement and that Pt. McIntyre will be included in the Prudhoe Bay Unit through the voluntary unitization process. We are filing this petition in order to start the clock on the compulsory unitization process. If the parties are unable to voluntarily unitize Pt. McIntyre, we would like to proceed with the compulsory unitization proceedings without further delay so that the field can be brought on production as soon as possible. Commissioner Noah requested a two week deferral of the September 9 show cause hearing' to allow the parties the opportunity to resolve their differences. We believe that the parties can use the time between now and the date set for the compulsory unitization hearing to resolve their differences and come to agreement on voluntary unitization. Very truly yours, enclosure ARCO Alaska, Inc. is a Subsidiary of Atlantic Richfield Company RECEIVED S E P - 8 199 Alaska 0ii & Gas Cons,. Com~tSs~.o.a ~nch0.rag,ei //' Mr. David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission September 8, 1993 Page 2 - cc: Mr. Harry Noah, Commissioner (w/encl.) Department of Natural Resources Mr. James Eason, Director (w/encl.) Division of Oil and Gas Mr. Jack Golden, BP (w/encl.) Mr. Tom Theriot, Exxon (w/encl.) RECEIVED Alaska Oil & Gas Cons. Commission Anchorage :!'?,. E P - 8 199,3 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: In the Matter of the Application ) of ARCO Alaska, Inc. and BP ) Exploration (Alaska) Inc. Filed ) Pursuant to AS 31.05 for the ) Stated Purpose of Forming the ) Conservation File No.__ Pt. McIntyre Participating Area ) and Expanding the Prudhoe Bay ) Unit Area. ) ) Petition of ARCO Alaska, Inc. and BP Exploration (Alaska) Inc. INTRODUCTION 1. This Petition is filed jointly by ARCO Alaska, Inc. ("ARCO") and BP Exploration (Alaska) Inc. ("BP") as unit operators of the Prudhoe Bay Unit and as working interest owners of certain State of Alaska oil and gas leases located in the proposed Pt. McIntyre Participating Area. ARCO is a working interest owner in ADL 34627 ("Tract 6"), ADL 34624 ("Tract 7"), ADL 28297 ("Tract 8"), and ADL 28298 ("Tract 115"). BP is the working interest owner of ADL 365548 ("Tract 117"). In addition, ARCO is operator of the proposed Pt. McIntyre Participating Area. 2. In this petition, ARCO and BP ask that the Pt. McIntyre Participating Area be formed to include those portions of Tract 6, Tract 7, Tract 8, Tract 115, ADL 34622 ("Tract 116") and Tract 117, identified on Exhibit A. ARCO and BP also ask that the Prudhoe Bay Unit be expanded to include those portions of Tracts 6, 7, 8, 115, 116 and 117, identified on Exhibit A. 3. ARCO and Exxon Corporation ("Exxon") each own an undivided one-half working interest in Tracts 6, 7, 8, and 115. Exxon owns an undivided 100% working interest in Tract 116. BP owns an undivided 100% working interest in Tract 117. The State of Alaska is the sole royalty owner of Tracts 6, 7, 8, 115, 116 and 117. There are no overriding royalty interest owners, carried interests, mortgages, or lien claimants as to Tracts 6, 7, 8, 115, 116 and 117. BACKGROUND 4. The Department of Natural Resources ("DNR") approved the Prudhoe Bay Unit Agreement effective April 1, 1977. It was approved pursuant to AS 31.05.110 and AS 38.05. At that time, the Prudhoe Bay Unit Area included 111 oil and gas leases covering approximately 245,767 acres. 5. The Prudhoe Bay Unit Area has been expanded on two occasions to include additional leases. See "Decision and Findings of the Commissioner, Department of Natural Resources" dated February 29, 1984 and "Decision and Findings of the Commissioner, Alaska Department of Natural Resources" dated February 21, 1986. 6. The Initial Participating Area ("IPA"), which includes two participating areas, the Oil Rim and Gas Cap, consists of the leases and portions of leases within the Prudhoe Bay Unit that have been determined to be capable of producing or PETITION OF ARCO AND BP Page 2. contributing to production of hydrocarbons from the Prudhoe Bay Reservoir (Permo-Triassic) in paying quantities. 7. A third participating area within the Prudhoe Bay Unit, the Lisburne Participating Area, was approved by DNR effective December 1, 1986. 8. A fourth participating area within the Prudhoe Bay Unit, the West Beach Participating Area, was approved by DNR effective February 22, 1993. 9. On March 18, 1993, ARCO, BP and Exxon filed an application with DNR to form a fifth participating area within the Prudhoe Bay Unit, the Pt. McIntyre Participating Area. The application also requested an expansion of the Prudhoe Bay Unit Area to include all of the Pt. McIntyre Participating Area. The proposed Pt. McIntyre Participating Area includes the Pt. McIntyre reservoir and the Stump Island reservoir. This Application is filed as Attachment I to Exhibit C to this Petition. 10. On April 14, 1993, the Director of the Division of Oil and Gas, DNR, ordered a contraction of the Prudhoe Bay Unit Area, effective April 1, 1993. Pursuant to the Director's order, the contracted Prudhoe Bay Unit Area would exclude ADL 34626 ("Tract 5") and portions of Tracts 6, 7 and 8. The portions of Tracts 6, 7 and 8 purportedly contracted from the Prudhoe Bay Unit Area are part of the Pt. McIntyre Participating Area proposed by ARCO, BP and Exxon in their March 18, 1993 application. ARCO and Exxon have appealed the Director's unit contraction decision to the PETITION OF ARCO AND BP Page 3. Commissioner of DNR. That appeal is presently pending. The contraction is stayed while the appeal is pending. 11. On July 2, 1993, the Alaska Oil and Gas Conservation Commission ("Commission") issued Conservation Order No. 317, which establishes pool rules for the development of the Pt. McIntyre reservoir and the Stump Island reservoir. 12. On August 18, 1993, the Director of the Division of Oil and Gas rendered his Decision and Findings denying the application of ARCO, BP and Exxon to expand the Prudhoe Bay Unit and form the Pt. McIntyre Participating Area. 13. As a result of DNR's denial, the working interest owners and the royalty owner of Tracts 6, 7, 8, 115, 116 and 177 ("Expansion Tracts") have not been able to voluntarily integrate their interests. JURISDICTION OF THE COMMISSION 14. The Commission has jurisdiction of this matter pursuant to AS 31.05.027 and AS 31.05.110. AS 31.05.110(o) provides in material part that the unit area of a unit may be enlarged to include adjoining portions of the same pool "in the same manner, upon the same conditions and subject to the same limitations as provided with respect to the creation of a unit in the first instance." 15. AS 31.05.110(a) provides that where the parties have not agreed to integrate their interests, upon petition by a party, the Commission has jurisdiction, power and authority, and it is its PETITION OF ARCO AND BP Page 4. duty to make and enforce orders and do the things necessary or proper to carry out the purposes of subsection 110. COMPULSORY UNITIZATION 16. Expansion of the Prudhoe Bay Unit to include the Expansion Tracts and formation of a Pt. McIntyre Participating Area within the Prudhoe Bay Unit is reasonably necessary in order to effectively carry on pressure control, pressure-maintenance, cycling operations, water flooding operations, and combinations thereof, together with other forms of joint effort which are calculated to substantially increase the ultimate recovery of oil from the Pt. McIntyre and Stump Island oil reservoirs. AS 31.05. 110 (b)(1). 17. Expansion of the Prudhoe Bay Unit to include the Expansion Tracts and formation of a Pt. McIntyre Participating Area within the Prudhoe Bay Unit is feasible, will prevent waste and will, with reasonable probability, result in the increased recovery of substantially more oil and gas from the Pt. McIntyre and Stump Island reservoirs than would otherwise be recovered. AS 31.05. 110 (b)(2). 18. The estimated additional cost of conducting unitized methods of operation in a Pt. McIntyre Participating Area formed within an expanded Prudhoe Bay Unit will not exceed the value of additional oil and gas so recovered. AS 31.05.110(b) (3). 19. Expansion of the Prudhoe Bay Unit to include the Expansion Tracts and formation of a Pt. McIntyre Participating Area PETITION OF ARCO AND BP Page 5. within the Prudhoe Bay Unit is for the common good. AS 31.05. 110 (b)(4). DESCRIPTION OF PROPOSED EXPkNSION AREA 20. A plot depicting the proposed expansion of the Prudhoe Bay Unit Area and the proposed Pt. McIntyre Participating Area is attached as Exhibit B. RECOMMENDED PLAN OF UNITIZATION 21. ARCO and BP's proposed plan of unitization for the Expansion Tracts is attached as Exhibit C. This proposed plan of unitization is fair, reasonable and equitable. 22. As stated above, expansion of the Prudhoe Bay Unit to include the Expansion Tracts and formation of a Pt. McIntyre Participating Area within the Prudhoe Bay Unit is for the common good. 23. Although the Director concluded in his August 18, 1993 Findings and Decision that expansion of the Prudhoe Bay Unit to include a Pt. McIntyre Participating Area would promote the conservation of natural resources and prevent economic and physical waste, he nevertheless concluded that such an expansion was not in the State's best interest. ARCO and BP disagree with the Director's conclusion and therefore will appeal his decision to the Commissioner of DNR. 24. Despite their disagreement with the Director's conclusion, ARCO and BP, in order to avoid the costs of further PETITION OF ARCO AND BP Page 6. delay, are willing to agree to the following if the Prudhoe Bay Unit is expanded to include the Pt. McIntyre Participating Area: a. With the exception of those portions of Tracts 6, 7, and 8 that were purportedly contracted out of the Prudhoe Bay Unit by the Director's April 14, 1993 decision, ARCO and BP will waive application of the 1980 Settlement Agreement1 to the Expansion Tracts. b. With the exception of those portions of Tracts 6, 7 and 8 that will remain subject to the 1980 Settlement Agreement, ARCO waives its rights to a field cost deduction from the royalty share of oil and gas produced from the Expansion Tracts. The BP lease in the proposed Pt. McIntyre Participating Area, ADL 365548 (Tract 117), is on Form DO2G 24-84. BP acknowledges that the State's royalty share of oil and gas produced from Tract 117 shall be free of field costs. c. BP and ARCO will work with DNR and its royalty in kind purchasers to facilitate transition with respect to the incremental takes caused by start-up of Pt. McIntyre production. 1On April 1, 1980, ARCO, BP, Exxon and the other North Slope producers entered into an agreement with the State of Alaska settling some of the "upstream" royalty issues ("1980 Settlement Agreement") in the so-called Amerada Hess litigation (civil Action No. 77-847, First Judicial District at Juneau). The 1980 Settlement Agreement provided for a field cost allowance for Prudhoe Bay Unit leases covered by the Agreement. PETITION OF ARCO AND BP Page 7. 9 SENT BY' 8-93 ;8'13AM ; BPXA L.tt~ DEPT-, ~2656B~8;# 2/ 2 25. ARCO and BP request 5ha~ th~ Commission order formation of th~ Pt. McIntyre ParticipaTing Area and expansion of the Pru~hoe Bay Uni~ Area in accordance ~i~h the Plan of Unitization submitted herewith. DATED this ~4~dag of geptember0 1~92, at Anchorage, alaska. ATTORNEYS FOR ARCO AND BP ARCO ALASKA, INC. BP EXPLORATION (ALASK2~) INC. PETITION OF ~RCO AND BP Page 8. Exhibit A PBU Expansion Are_a Tract No. T12N-R15E, Sec. 18: All T12N'R14E, Sec. 13: All Sec. 14: All Working No. of ADL Serial Ballc Le~lee of Interelt 1280 34627 1/8 34624 1/8 ARCO Exxon ARCO Exxon ARCO-50% Exxon-50% ARCO-50% Exxon-50% T12N-R14E, Sec. 15: Sec. 16: Sec. 21- Ali All Nl/2 NE1/4 1360 28297 1/8 ARCO Exxon ARCO-50% Exxon -50% 115 116 117 T12N-R14E, Sec. 17: N1/2, N1/2 SE1/4, NE1/4 SWl/4 excluding U.S. Survey 4044 T12N-R14E, Sec. 3: All Sec. 4: All Sec. 9: All Sec. 10: All Those Lands in Block 605 lying no.he~y of ~e north boundary of Section 3, T12N, R14E, UM, AK. (Identical with line 4-5 on Block 605) and lying easterly of the west boundary of Seclions 2 and 11, T12N, R14E, UM, AK (Identical with line 5-6 on Block 605) and lying northerly of lhe soulh boundary of Section 11 and 12, T12N, R14E, UM, AK, and lying northerly of the Soulh boundary of Section 7, T12N, R15E, UM, AK (Identical with line 6-7 on Block 605), within lhe offshore throe-mile arc lines-listed as Stale Area on the "Supplemental Official O.C.S. Block Diagram approved 12/9/~. 312 2560 3601 28298 1/8 34622 1/8 ARCO 365548 1/6 BPX ARCO-50% Exxon-50% Exxon-lO0% BPX-IO0% Exhibit B ~ Prudhoe Bay Unit Expansion Area A/E 34623 Proposed Pt. Mclntyre Participating Area AAI 375136 ':...:.':.":'i'./:.'.':".':~:'/?.. '-."i!:'. '.':-.'.'~.....i... '.'i '!.':' ~:'. ..." "i.!'i.':!. . .:..' ". '.:"i '. PBu ExPansion'Area .:. ·. . ........... . ...... .......... . . . : .... ....... . . .. ........ ..... . ·...: ...... : ...... ''.:.".' .. · ..' .. ..... ~ . · .... .. .... · .. .. · . ....... · ' .. '.... ... ...... · BPx 365548 .Tract 117 · . · : .. . . .. PBU .Boundary Lease Lines ~1 Tract 115 ~ t Tract 8 AJE 28298 A/E 28297 Shoreline Tract 7 A/E 34624 Tract 6 A/E 34627 Exhibit B-1 Prudhoe Bay Unit Expansion Area NE 34623 Proposed Pt. Mclntyre Participating Area ~,~..'!~ '. ~' .. ~.? ".~. · ? .... '.:'-:'.~-: "" PBU Expansion Area ?.:',~:':, .". :.": ¥'i'?.".:.~'.~". ?.:.?' ". .ii~'. i"~'.i · ' ....'. · .... ..... " · . .. · ....'... . · ..?.,,...:.<~ ..:...~ .:... · .: . · .' '.. " · . ... . .... · . ~ L~ :'.:' ~ .' .. i .. ~.'... , .. · '" ..PBU Boundary, f:.::::..~l~ ...~ Lease Lines --~1 Tract 115 ~ ~ Tract8 A/E 28298 NE 28297 I. Shoreline Tract 7 AJE 34624 Tract 6 A/E 34627 Exhibit C PROPOSED PLAN OF UNITIZATION 1. The Prudhoe Bay Unit Area shall be expanded to include all of the Pt. McIntyre Participating Area. Exhibit A to the Petition lists those portions of Tracts 6, 7, 8, 115, 116 and 117 ("Expansion Tracts") to be included in the Pt. McIntyre Participating Area and Prudhoe Bay Unit Area, as expanded. Exhibit B to the Petition is a plot depicting the Pt. McIntyre Participating Area and the Prudhoe Bay Unit Area, as expanded. 2. The Pt. McIntyre Participating Area includes the Pt. McIntyre reservoir and the Stump Island reservoir. 3. The Pt. McIntyre Participating Area shall be subject to the Prudhoe Bay Unit Agreement. 4. Attachment I to this Exhibit C is a copy of the March 18, 1993 Application to Expand the Prudhoe Bay Unit and Form the Pt. McIntyre Participating Area within the Prudhoe Bay Unit ("Application") filed with the Department of Natural Resources by ARCO, BP and Exxon Corporation. Unitized operation of the Pt. McIntyre Participating Area shall be conducted in accordance with the Application. 5. Attachment II to this Exhibit C is a copy of the "Pt. McIntyre Special Supplemental Provisions to Unit Operating Agreement, March 1, 1993" ("Pt. McIntyre Provisions"). Unitized operation of the Pt. McIntyre Participating Area shall be conducted in accordance with the General Provisions of the Prudhoe Bay Unit Operating Agreement (Articles 1 through 25) and the Pt. McIntyre Provisions. 6. Included in the Pt. McIntyre Provisions is Exhibit 76-B as amended and corrected. Amended Exhibit 76-B specifies the final tract allocations for all the tracts in the Pt. McIntyre Participating Area. 7. Attachment III to this Exhibit C is a copy of Conservation Order No. 317, dated July 2, 1993. Unitized operation of the Pt. McIntyre Participating Area shall be conducted in accordance with Conservation Order No. 317, including any amendments. exC.do~ EXHIBIT C - 2 - ~RCO AlasKa. il" ,=dSt Office ~cx ~C0360 Anchorac=e. AlasKa 99510-0360 Teteonone 307 265 6375 James O. ';leeks Senior Vtce Prestaen! March 18, 1993 Mr. James E. Eason Division of Oil and Gas Alaska Department of Natural Resources P.O. Box 107034 Anchorage, AK 99510 Ct3 RE: Application to Expand the Prudhoe Bay Unit and FOrm the Pt. Mclntyre Participating Area within the Prudhoe Bay Unit, consisting of Alaska State Lease Numbers: ADL 28297, ADL 28298, ADL 34622, ADL 34624, ADL 34627, and ADL 365548 Dear Mr. Eason: Pursuant to the provisions of Section 5.3 and Section 9.1 of the Prudhoe Bay Unit Agreement ("PBUA") and 11 AAC 83.351 and 11 AAC 83.356, ARCO Alaska, inc. ("ARCO'), for itself and on behalf of Exxon Corporation ("Exxon") and BP Exploration (Alaska), Inc. ('BP'), hereby petitions the Department of Natural Resources ("DNR") to expand the boundaries of the Prudhoe Bay Unit and approve the formation of the Pt. Mclntyre Participating Area ("PMPA') within the Prudhoe Bay Unit with ARCO as operator. ARCO, Exxon and BP are the only Working Interest Ownem in the proposed PMPA. The requested effective date for the expansion and the PMPA is July 1, 1993. Pursuant to Section 9.1 of the PBUA, ARCO, as operator of the Prudhoe Bay Unit ('PBU'), prepared a Notice of Proposed Expansion of the Prudhoe Bay Unit. On December 11, 1992, ARCO sent a copy of said Notice by mail to the Director, Division of Oil and Gas, the DNR, and to each of the Working Interest Owners, and Royalty Interest Owners, at their last known addresses, and to all parties believed by ARCO to own any Oil and Gas Rights in the lands included in the PBU Exl3ansion Area. The Notice described the leases to be inoluded in the PBU Expansion Area, the reason for expansion, ancl the effective date of the expansion. The Notice provided each notified party with a thirty (30) day period after receipt of the Notice in which to file with PBU Operators a written objection to the proposed PBU expansion. ARCO received a letter objecting to the PBU expansion from Phillips Petroleum Company ("Phillips"). Phillips subsequently sent a letter in support of the PBU expansion. A 96.66% affirmative vote was received from the PBU working interest owners, which is sufficient to approve the ballot agreement allowing for the PBU Expansion pursuant to the PBU Operating Agreement. An Affidavit of Mailing, attached hereto as Attachment 1, contains a copy of said Notice and the correspondence received with reference to said Notice. Attachment 2 is a lease map depicting the proposed PBU Expansion Area. The proposed PMPA encompasses two producing Reservoirs, the Pt. Mclntyre Reservoir (Kul~aruk and Kalubik Formations) and the Stump Island Reservoir (Seabee Formation), both of which currently lie partially within the PBU. Occurrence of the Stump Island Reservoir is unpredictable and has been encountered infrequently. The attached documents demonstrated that the Reservoirs: (i) have been reasonably proven capable of producing or contributing to the production of hydrocarPons in paying quantities sufficient to justify clevelopment and production; (ii) are currently partially within the PBU Area; and (iii) extend on to the lands included in the PBU Expansion. In addition, the Pt. Mclntyre No. 3, No. 4, No. 5, and No. 7 have each been certified capable of proclucing in paying quantities by DNR. ATTACHMENT I aRCO Ala,~a, Inc. ;RCO AlasKa. ~ ~ost Office mcx Ancnorace. AlasKa ~9510-0360 -eleonone e07 ;ames O. WeeKs ~enlor vice i~resloen! 18. 1993 Mr. Division Alaska P.O. Box 1 Anchorage, Al RE: E. Eason and Gas of Natural Resources A within the Pt ADL 28298, 99510 ...... the Prudhoe Bay Unit and Bay Unit, consisting of 34622, APL 34624, ADL the Pt. Mclntyre Participating Area State Lease Numbers: ADL 28297, and APL 365548 Dear Mr. Eason: Pursuant to the provisions ("PBUA") and 11 AAC 83.351 behalf of Exxon Corporation the Department of Natural and approve the formation of the Bay Unit with ARCO as operator. tl~e proposed PMPA. The 1993. 9.1 of the Prudhoe Bay Unit Agreement 11 AAC Alaska. Inc. for itself and on and Exploration (Alaska), ("BP'), herelm/petitions to expand the bo of the Prudhoe Bay Unit ntyre Partici ('PMPA') within the Prudltoe are the only Working Interest Owne~ in date for the expansion and the PMPA is July 1, Pursuant to Section 9.1 of prepared a Notice of Prol ARCO sent a co0Y of said each of the Working and to all parties PBU Exoansion Area. Area, the reason Expansion by mail to Owners, and by ARCO to each O~ the Lnsion, and the effective a thirty (30) day period after Irator of the Prudhoe Bay Unit ('PBU'), Prudhoe On December 11, 19~2, of Oil and Gas, the DNR, and to at their last known and Gas Rights in the lands included in to be inc.,tu~l in the PBU ~ of the expansion. The Notice p~ of the Notice in which to file with PBU a objection to the proposed PBU expa ARCO from Phillips Petroleum company ("Phillios"). subsequently sent a letter in support the PBU expansion. A 96.66% affirmative was received from the PBU working owners, which is sufficient to approve ballot agreement allowing for the PBU Expansmn ~ursuant to the PBU Opera~ ~t. An Affidavit of Mailing, attached h~reto as 1, contains a copy of said N( Ind the corres0ondence received"~ith reference to said Attachment 2 is a lease ma ep~cting the prol Expansion Area. PMPA encompasses two producing Reservoirs, rre Reservoir ~(uparuk and Kalubik Formatlons) and the Stump Island Reservoir ormation), both of which currently lie partIally w~thin the PBU. Occurrel Island Reservoir is unpreaictaDle and has peen encountered in The attached documents demonstrated that the Reservoirs: (i) have been reasonably proven ca0aDle of producing or contributing to the production of hydrocarbons in paying quantities sufficient to lustily development and production: (ii) are currently partially within the PBU Area; ancl (iii) extend on to the lands included in the PBU Expansion. In addition, the Pt. Mcintyre No. 3. No. 4. No. 5. and No. 7 have each been certified capable of producing in paying quantities by DNR. ~qCO ~l&$11, a. InC. ,5 . ,.tU051C:1~1~ O! Atl4nllc ~lCrllleld Com~v Mr. James E. Eason March 18.1993 Page 2 ARCO respectfully submits that the expansion of the PBU ancl the formation of the proposed PMPA meets the cnteria of 11 AAC 83.303, because it will: ao promote the conservation of oil and gas by providing an efficient, integrated approach to development of the reservoirs while reducing the environmental impact of that procluction by utilizing existing production facilities; bo promote the prevention of economic and physical waste by setting forth a diligent development plan which allows maximization of physical and economic recovery as well as efficient use. of existing facilities; and Co provide for the protection of the interests of all parties including the State of Alaska by equitably allocating production to lease tracts and maximizing hydrocarbon recovery under state leases. In evaluating the above criteria, the DNR will consider, among other items, the economic benefits to the State. The State's direct economic benefit resulting from the expansion of Prudhoe Bay Unit is estimated to be approximately $800 million over the life of the Pt. Mclntyre Field as shown in Attachment 3. The following additional attachments are provided in support of this application for the expansion of the Prudhoe Bay Unit and formation of the PMPA: Attachment 4 Attachment 5 Attachment 6 Attachment 7 Attachment 8 Attachment 9 Attachment 10 Attachment 11 Attachment 12 Attachment 13 Pt. Mclntyre Plan of Development and Operations Interim PMPA Tract Participation Factors Pt. Mclntyre 3 Type Log Pt. Mclntyre 11 Type Log Interim Top Structure Map of Kuparuk Formation Interim Gross Sand Isochore of Kuparuk Formation Interim Hydrocarbon Pore Foot Map of Kuparuk Formation Production Allocation Methodology Testimony as Presented at the West Beach Field Rules Heanng Production Reporting Forms ~ Third Amendment to Lisbume Special Supplemental Provisions in the PBUOA Attachment 11 sets forth the proposed production allocation methodology among the Usburne, Pt. Mcintyre and West Beach Participating Areas based on well testing. This proposed production allocation methodology is consistent with the DOR ruling of February, 1991, the Alaska Oil and Gas Conservation Commission approved West Beach Reid Rules and the West Beach participating area application. Attachment 12 sets forth the proposed allocation reports. Attachment 13 sets forth the provisions for the sharing of the Lisbume production facilities and seawater supplied from the Initial Participating Area among the Lisbume, Pt. Mclntyre, Niakuk and West Beach Working interest Owners. ARCO, Exxon and BP are prepanng Special Supplemental Provisions to the PBUOA for the PMPA. These Special Supplemental Provisions will be submitted to DNR before they take effect. Enclosed are an original and five copies of the nonconfidential portions of this application, two copies containing the confidential portions of this application and ten copies of the unit plan of operations. ARCO, Exxon. and BP recluest that the geological, geophysical, and engineering portions of this application be kept confidential under AS 38.05.035(9)(C). Mr. James E. Eason March 18. 1993 Page 3 If you have any questions or require additional information, ptease contact: Mr.' Andrew Simon ARCO Alaska Inc. P.O. Box 100360 Anchorage, Alaska 99510-0360 (907) 263-4275 ARCO, Exxon and BP would appreciate your approval of this application for formation of the Pt. Mclntyre Participating Area and expansion of the Prudhoe Bay Unit. Sim~erely, J. D. Weeks Senior Vice President SMR/ADS:tg Attachments Joinder by Exxon Corporation in the Application by ARCO Alaska, Inc. to Expand the Prudhoe Bay Unit and Form the Point McIntyre Participating Area Within the Prudhoe Bay Unit Consisting of Alaska State Lease Numbers ADL's 28297, 28298, 34622, 34623, 34624, 34627, 365548 and 375136 Mr. James E. Eason Director Division of Oil and Gas Alaska Department of National Resources P. O. Box 107034 Anchorage, Alaska 99510 Dear Mr. Eason: Exxon Corporation, as a Working Interest Owner in the Prudhoe Bay Unit and Working Interest Owner in the area requested to be included in the Point McIntyre Participating Area on behalf of itself, joins in and supports the application filed by ARCO Alaska, Inc. for expansion of the Prudhoe Bay Unit and formation of the Point McIntyre Participating Area. Exxon will participate, as appropriate, in proceedings before the Department of Natural Resources relating to expansion of the Unit and formation of the Participating Area. It is requested that copies of all correspondence concerning this application and all notices issued by he Department of Natural Resources be sent to Exxon's counsel of record as set out below. day of , 1993. Gary E. Baker Exxon Company, U.S.A. P. O. Box 2180 Houston, Texas 77252-2180 Telephone (713) 656-3431 Fax (713) 656-6123 William F. Cronin Bogle & Gates Two Union Square 601 Union Street Seattle, Washington 98101-2346 Telephone (206) 682-5151 Fax (206) 621-2660 Attorneys for Exxon Corporation Gary ~er C® Ms. R. M. Jacobsen ARCO Alaska, Inc. Legal Department P. O. Box 100360 Anchorage, Alaska 99510-0360 Mr. John A. Reeder BP Exploration (Alaska) Inc. P. O. Box 196612 Anchorage, Alaska 99519-6612 .TTACHMENT 1 TO THE DEPARTMENT OF NATURAL RESOURCES Before the Commissioners of the Department of Natural Resources in the Matter of the Petition of the Prudhoe Bay Unit Operators to ~xDand the Prudhoe Bay Unit, VERIFICATION OF FACTS AND AFFIDAVIT OF JAMES R. WINEGARNER STATE OF ALASKA THIRD JUDICIAL DISTRICT SS. James R. Winega'rner, being first duly sworn, upon oath, deposes and states as follows: 1. My name is James R. Winegarner. I am over 19 years old and have personal knowledge of the matters set forth herein. 2. lam a Senior Landman for ARCO Alaska, Inc. ("ARCO"), operator of the Prudhoe Bay Unit. 3. Pursuant to Section 9.1 of the Prudhoe Bay Unit Agreement, ARCO prepared a Notice of Proposed Expansion of the Prudhoe Bay Unit. A copy of this notice is attached.- hereto. 4. On December 11, 1992, pursuant to the notice procedures described in Section 9.1 of the Prudhoe Bay Unit Agreement, ARCO sent a copy of said Notice by mail to the Director, Division of Oil and Gas, Department of Natural Resources, and to each of the Working Interest Owners, and Royalty Interest Owners, at their last known addresses, and to all parties believed by ARCO to own any Oil and Gas Rights in the lands included in t' Prudhoe Bay Unit Expansion Area. These names and addresses are set forth on ti,,. attached distibution list. 5. The Notice described the leases to be included in the Prudhoe Bay Unit expansion, the reason for expansion, and the effective date of the expansion. 6. The Notice provided each notified party with a thirty (30) day period after receipt of the Notice in which to file with Prudhoe-Bay Unit Operators a written objection to the proposed expansion. 7. ARCO received correspondence from Phillips Petroleum Company initially objecting to the PBU expansion and subsequently supporting the PBU expansion. Copies of all correspondence regarding the PBU expansion are also attached hereto. Subscribed and sworn to on March 15, 1993. ~~es R. Win/eg~/ner STATE OF ALASKA , THIRD JUDICIAL DISTRICT ~,/ /... The foregoing instrument was/acknowledged before me on March 15, R. Winegarner. 1993, by James OFFICIAL SEAL STATE OF ALASKA Linda Sellner NOTARY PUBLIC My Corem r~-x~,~e$ October 3. 199,5 Noktary Public, State of Alaska My Commission Expires: 2O 3, RCO AlasKa. ~ ~ost Oftl~.~ dox Teleono~e 50? 255 £.~ ."_'- James ~). ',"Jeezs Settlor Vice Presloen~ December 8, 1992 PRUDHOE BAY UNIT WORKING INTEREST OWNERS REPRESENTATIVES AND ALTERNATES Re: Notice of Intent to Expand the Prudhoe Bay Unit to Encompass tl~e Pt. Mclntyre Participating Area Gentlemen: Pursuant to Section 9.1 of the Prudhoe Bay Unit Agreement, ARCO Alaska, Inc. and BP Exploration (Alaska) Inc., acting in their capacity as Operators of the Prudhoe Bay Unit, .hereby give notice of the proposed enlargement of the Prudhoe Bay Unit Area to encompass the proposed Pt. Mctntyre Participating Area. The contemplated leases and portion of leases for inclusion in the Prudhoe Bay Unit Area ("Expansion Area") are listed on Exhibit A and depicted on Exhibit B, both of which are attached hereto and incorporated herein. Because delineation drilling is not yet complete, some uncertainty remains about the ultimate size of the Expansion Area, but it should be no larger than the area shown. As required by Section 9.1 of the Prudhoe Bay Unit Agreement, the tracts included in the Expansion Area have been reasonably determined to be within the Pt. Mclntyre Reservoir, a portion of which is already within the Prudhoe Bay Unit Area. The inclusion of the Expansion Area in the Prudhoe Bay Unit Area will enable the timely development of the Pt. Mclntyre Reservoir by facilitating the sharing of existing Prudhoe Bay Unit facilities. The expansion of the Prudhoe Bay Unit Area to include the Expansion Area will promote conservation of natural resources, promote the prevention of economic and physical waste, and will protect all parties, including the State of Alaska. It provides for the protection of the environment through planned development which optimizes the use of existing facilities and prevents unnecessary duplication of facilities. The effective date of the expansion of the Prudhoe Bay Unit Area to include the Expansion Area will be June 1, 1993, upon approval of the Director of the Alaska Department of Natural Resources. Pursuant to Subsection 9.1 (b) of the Prudhoe Bay Unit Agreement, each Prudhoe Bay Unit Working Interest Owner and any parties of interest may file with the Unit Operators written objections, and reasons therefor, to the proposed enlargement within thirty (30) days of the date this Notice was mailed. If you have any comments or questions, please contact Mr. Keith Weiser at (907) 263-4713. ..~.~ce re ly, James D. Weeks Senior Vice President, Prudhoe/Lisburne Inc. ~s Tract No, Description T12N-R15E, Sec. 18: Sec. 19: All N1/2 Exh!blt A PBU EXPANSION AREA Working No. of ADL Serial Basic Lessee of Interest Acres No. J~ Record Ownersh!p 875 34627 1/8 ARCO Exxon ARCO-50% Exxon-50% T12N-R14E, Sec. 13: Sec. 14: Sec. 23: Sec. 24: All All N1/2 NWl/4, N1/2 NE 1/4, SW1/4 NWl/4 N1/2 1800 34624 1/8 ARCO Exxon ARCO-50% Exxon-50% T12N-R14E, Sec. 15: Sec. 16: Sec. 21: Sec. 22: All All N1/2 NE1/4 N1/2 680 28297 1/8 ARCO Exxon ARCO-50% Exxon-50% 115 T12N-R14E, Sec. 17: N1/2, N1/2 SE1/4, NE1/4 SW1/4 excluding U.S. Survey 4044 312 28298 1/8 ARCO Exxon ARCO-50% Exxon-50% 116 T12N-R14E, U.S. Survey 4044 lying within: Sec. 8: Sl/2 Sec. 17: NWl/4, NE1/4SW1/4 204 375136 1/8 ARCO ARCO-100% 117 T12N-R14E, Sec. 8: Sl/2 excluding U.S. Survey 4044 245 34623 1/8 ARCO Exxon ARCO-50% Exxon-50% Tract 118 119 T12N-R14E, Sec. 3: All Sec. 4: All Sec. 9: All Sec. 10: All Those Lands in Block 605 lying norlherly o! lhe norlh boundary of Section 3, T12N, R14E, UM, AK. (Idenlical wilh line 4-5 on Block 605) and lying easlerl¥ of lhe wesl boundary ol Seclions 2 and 11, T12N, R14E, UM, AK (Identical wilh line 5-6 on Block 605) and lying norlherly o! lhe soulh boundary of Seclion 11 and 12, T12N, R14E, UM, AK, and lying norlherly ol Ihe Soulh boundary o! Section 7, T12N, R15E, UM, AK (Identical wilh line 6-7 on Block 605), wilhin Ihe offshore lhree-mile am lines lisled as Slale Area on lhe "Supplemenlal Ollicial O.C.S. Block Diagram approved 12/9/79. No. of 2560 3601 ADL Serial _ No, __ 34622 365548 Basic 1/8 1/6 Lessee of Exxon BPX Working Inleresl Exxon-100% 8PX-100% PRUDHOE BAY UNIT EXPANSION AREA Exhibit B ADL 34623 A-E ;,: :.. :.: DEW ~ SITE AAI 375136 ADL 28298 A-E ADL 34622 EXXON AD 29 L 365548 BPX ~? ADL 34624' A-E IBPX ADL 365549 II'C.. ADL 34627 A-E EXISTING U BOUNDRY DISTRIBUTION LIST Notice of Intent to Expand the Prudhoe Bay Unit to Encomc)ass the Pt. Mclntvre ParticiDatina Area J. D. Weeks ARCO Alaska, Inc. 700 G. Street (ATO-2100) 99501 P. O. Box 100360 Anchorage, AK 99510-0360 M. W. Sellers Chevron U.S.A. Inc. Houston Chevron Tower Bldg. 1301 McKinney Houston TX 77010 G. T. Theriot Exxon Corporation 800 Bell Ave., Room 3052 P. O. Box 2180 Houston, TX 77252-2180 L. R. Dartez Marathon Oil Company 3201 "C" St., Suite 800, 99508 P. O. Box 190168 Anchorage, AK 99519 N. H. Smith, Jr. Mobil Oil Corporation 12450 Greenspoint Drive Houston, TX 77060-1991 M. R. Williams Shell Western E&P Inc. Alaska Division, WCK 4550 - P. O. Box 576 '" Houston, TX 77001 J. K. Fetters hillips Petroleum Company r-'. O. Box 1967 Houston, TX 77251-1967 R. W. Hill Texaco USA 4601 DTC Blvd., 80237 P. O. Box 46555 Denver, CO 80201-6555 R. L. Nesvold Phillips Petroleum Company P. O. Box 1967 Houston, TX 77251-1 967 R. W. Mullins Amerada Hess Corporation 218 West 6th Street, 74119 P. O. Box 2040 Tulsa, OK 74101 J. E. Orth, The Louisiana Land and Exploration Company Suite 1200, One Civic Center 1560 Broadway Denver, CO 80202 James Eason, Director State of Alaska, Div. of Oil and Ga= P. O. Box 107034 Anchorage, AK 99510-7034 A. R. Berger (Mgmt Forum) Exxon Company, U.S.A. P. O. Box 2180 Houston TX 77252-2180 D. J. Pritchard BP Exploration (Alaska)Inc. P. O. Box 196612 Anchorage, AK 99519-6612 PHILLIPS PETROLEUM HOUSTON, TF_XAS 77251.1957 BOX 1967 NORTH AMERICA EXPLORATION AND PRODUCTION COMPANY BELLAIRE, TEX, 6330 WEST LOOP SOUTH :~HILLIP5 BUILDING January 25, 1993 Mr. Dave Pritchard Senior Vice President Prudhoe Bay Unit BP Exploration (Alaska) Inc. 900 East Benson Boulevard P. O. Box 196612 Anchorage, Alaska 99519-6612 Mr. James D. Weeks Senior Vice President ARCO Alaska, .Inc. P. O. Box 100360 ~i..A,~KA Anchorage, Alaska 995 I0-0360 SUBJECT: PRUDHOE BAY UNIT EXPANSION TO INCLUDE THE PT. MC INTYRE PA. IPA BALLOT g92-154 Dear Messrs. Pritchard and Weeks: The January 21st Management Forum .meeting was very informative. Your staffs presented an excellent overview of the intent of the proposed Unit expansion and of the outstanding facility sharing issues. As you are aware, our concern was that expanding the Unit to include the Pt. Mclntyre PA would eventually lead to Pt. Mclntym competing for existing PBU production facilities and potentially inhibit development of smaller pools within the PBU. However, since the intent of the expansion, as outlined in the Management Forum meeting, is only to facilitate sharing of IPA support facilities, source water, power and communications, Phillips has approved the attached Unit expansion ballot. Sincerely, RLN:Iss Attachment (IPA Ballot g92-154) c: ./M~.K. Fetters ~ Janet McCart (BP Explorauon (Alaska) Inc.) '26 w[o RECEIVED - - - 1993 JAMES O WEEF:S ARCO Alasi(a. ~ Post Office Box 100360 Anc.~torage. Alasi(a 99510-0360 Telephone 907 265 6375 James D. Weeks Semor Vice Preslclen! January 18, 1993 Mr. R. L. Nesvold Manager, Partnership Operations Alaska Group 'Phillips Petroleum Company P.O. Box 1967 Houston, Texas 77251-1967 RE: Response to Phillips Petroleum ComDany's Objections to IPA Ballot N°'. 92-154 (Ballot Agreement Approving Expansion of the Pruahoe Bay Unit) Dear Mr. Nesvold: This letter responds to concerns you expressed on behalf of Phillips Petroleum Company in stating an objection to the above-referenced ballot agreement. In particular, you expressed a desire to understand how the Pt. Mclntyre Participating Area ("PMPA") will share Prudhoe Bay Unit ("PBU") facilities, how the PMPA will impact small field development within the PBU and how the facility sharing for the PMPA relates to the development of a general framework for shanng of existing north slope facilities. We hope the following information resolves whatever concerns you may have. First, because the PMPA will process its fluids through Lisburne Participating Area ("LPA") facilities, not through Initial Participating Area ("IPA") facilities, the PMPA will pdmadly share LPA facilities, not IPA facilities. It follows that the PMPA will not use any of the IPA's production capacity, and that its operations can have no adverse impact on the availability of IPA production capacity for any small field that may want to avail itself of facility shanng with the IPA. To enable the sharing of LPA facilities by the PMPA, the Lisburne owners amended the Lisburne Special Supplemental Provisions and agreed that Pt. Mclntyre production would be processed through LPA facilities. Second, the PMPA will share some IPA facilities not directly related to fluid processing. These include infrastructure already being shared with the LPA, the cuttings grinder, CC-2A disposal well, power, communications, some vertical support members, and source water. Mr. R. L. Nesvotd January 18, 1993 Page 2 Finally, the Pt. Mclntyre owners believe that production of the Pt. Mclntyre reservoir will enhance, not hinder, development of other small fields in the PBU area, by increasing TAPS throughput and therefore lowering TAPS tariff rates, increasing each producer's netback value, and extending the economic life of TAPS and all fields that transport production to market through TAPS. Please call either myself, Randy Brush (907-263-4672) or Steve Renke (907-265-6894) with any questions or comments. Further, please feel free to attend the Management Forum meeting on January 21st, at which time the IPA, LPA and Pt. Mctntyre facility-shanng agreements will be thoroughly discussed. Sincerely, ~. D. Weeks J. M. McCart Secretary, Prudhoe Bay Unit PBU Working Interest Owners PHILLIPS PETROLEUM COMPANY )~XJ~'TON, TEXAS 7725~-IN? tK~ 19~T 8E~L~AJRE. ' P~ILUPS BUI January 7, 1993 PRUDHOE BAY UNIT .UNIT OPERATORS RE: Ballot Agreement Approving Expansion of the Prud~oe Bay Unit - IPA Ballot No. 92-154 Gentlemen: Phillips has reviewed the proposed ballo= and objects the expansion o£ cae Prudhoe Bay Unit to encompass the proposed PC. McInCyre Participating Area. There is no explanation in the ballot as to specifically how the Pt. McIntyre Par=icipaCin~ Area would share in the existin~ Prudhoe Bay Unit facilities as referenced in the Attachment 1 to the ballot. Without an understanding of Chose sharing arrangements, we are concerned that the Pt. McIntyre production volume~ would hinder development of other small fields in the Prudhoe Bay UniC area in that any special treatment of the Pt. McZnCyre production will interfere with the PBU Facilities Sharing Agreemen~ currently being drafted. P~. McInCyre development should be Created in a manner consistent with an encompassing PBU Facilities Sharing Agreement. Sincerely, R. L. Nesv01d Manager, ParCnership Operations Alaska Group cc= J. M. McCar= Secretary, Prudhoe Bay Unit PBU Working Interest O~ners Prudhoe Bay Unit Expansion Area Attachment 2 AJE 34623 Proposed Pl. Mclnlyre Participating Area AAI 375136 :':'::'::: EXX 24622 ... : ::: . . . 'i:-: - . :3: - - PBU Expansion Area ii!!i~i ~;ii 1. ::. . ]. :: . -': 1: . :'. :: :'. - ' - i:!:::~:} "ii:- .::- :: .'..' : - i- i;) ! !::- ' :: :5: .. },. :-.:::!:'2i ' 1: '. 12: · ::::: :: ... Lease Lines A/E 28298 A/E 28297 A/E 34624 Shoreline AJE 34627 ATTACHMENT st~mabon of Alaska's Direct Ec(onomic Benefit from Pt. McIntyre Field Development ASSUMPTIONS Estimated gross recoverable reserves: Average State royalty interest: Crude oil price: Crude oil field cost allowance: 340 MMBO 13.3% $14.07/bbl * $0.79/bbl * Estimated tract allocation to ADL 365548: 32.63 % Average severance tax rate over field life: 5.0% ROYALTY BENEFIT Uninflated, undiscounted State royalty over the life of Pt. Mch~e Field: Gross Revenue from Pt. Mclntyre Field: 340 MMBO X $14.07/BO = $4,783,800,000 Royalty Calculation: 340 MMBO X $14.07/BO X 0.133 = $636,245,400 340 MMBO X 0.133 (1-.3263) X $0,79/BO = Total royalty - $24,067,124 $612.178.276 SEVERANCE TAX BENEFIT Uninflated, undiscounted State severance tax over the life of Pt. Mdntyre Field: Severance Tax: ($4,783,800,000- $636,245,400) X 0.05= [TOTAL BENEFIT $207.377.730 $819.556,006 1) These calculations do not include the economic benefit to the State from prolonging the economic life of the other fields that produce through the Lisburne Production Center, thereby increasing their ultimate oil recovery.' ~ ~ * Lisbume Field- February 1993 POINT McINTYRE PLAN OF DEVELOPMENT AND OPERATIONS Initial development of the Point McIntvre Reservoir includes drilling of 80-acre spacing wells directionallv drilled from two drill sties, PM-1 and PM-2. The planned start-up date is August 1993. Waterflood operations will be implemented in the down-structure portion of the reservoir after field start-up. Produced gas in excess of lift and fuel gas requirements will be injected into the Point McIn~re gas cap or sold. Point McIntyre production will be commingled with Lisburne production at the Lisburne Production Center ("LPC"). The production will be allocated to Point McIntyre in accordance with conditions approved by the Commissioner of the Alaska Department of Revenue, the Alaska Department of Natural Resources, and Alaska Oil and Gas Conservation Commission. Sharing existing production facilities is possible due to the excess LPC capacity. Wells Twenty Point McIntyre wells have been drilled to date (Attachment 4a). Additional- development wells are being drilled to an expected nominal spacing of 80-acres. Drill Sites Point Mclntyre drill site locations have been selected to take advantage of existing gravel to minimize new gravel placement. PM-1 is located at the existing Point Mclntyre exploration pad. PM-2 is located at the existing West Dock Causeway. Dockhead #3 is being expanded to accommodate drill site facilities and maintain barge docking functions (Attachment 4b). Power to drill sites will be provided by extending existing Lisburne power lines to Point Mc, Intyre drill sites. ; Water will be injected at both drill sites for waterflood operations. Produced gas in excess of lift and fuel gas requirements will be injected into the Point McIntyre reservoir at the PM-1 drill site. Lift gas will be used at both drill sites. PM-1 will have 24 well slots and PM-2 will ultimately have approximately 60 total well slots. The Point McIntyre produced gas will be reinjected at PM-1 utilizing one gas injection well initially, with the potential need for an additional gas injection well in the future. Pipelines Production will flow from PM-1 and PM-2 to the LPC via 18" and 24" pipelines, respectively. An 18" water injection pipeline and a 14" high pressure gas pipeline will carry water and gas, respectively, from the LPC to each drill site (Attachment lb). Corrosion resistant materials will be used where appropriate for Point McIntyre pipelines. Lisburne Production Center There is excess facilitv capacity at the LPC. The original design liquid and gas handling capacities are approximately 100,000 stock tank barrels per dav (STB/D) of liquid and 440 million standard cubic feet per day gas. Facility expansion of the LPC is planned to increase the liquid handling capacity to 200,000 STB/D. The planned LPC modifications include additional water separation capacity, inlet header modifications, and produced water treating and pumping capacity. Prudhoe Bay Unit Initial Participating Area ("IPA") source water will be used for the Point McIntyre waterflood. There is a potential to convert to the use of produced water at a later date. Possible future LPC modifications include expansion of the existing gas handling capacity. Support Facilities Point.McIntyre will share North Slope infrastructure with the Lisbume Participating Area ("LPA") and the IPA to minimize duplication of facilities. These include the co- user camp core facilities, potable water and waste disposal facilities, shop and maintenance facilities, certain roads and bridges, crawlers, operations vehicles, module movement and placement equipment, airstrip, construction pad, storage and warehouse space, fire fighting equipment, medical facilities, oily waste disposal facilities, living quarters, and telecommunications systems. Production Allocation The production of oil and gas, including those hydrocarbon liquids reported as NGL's by the producer, will be allocated to the Point McIntyre Participating Area in accordance with conditions approved by the Alaska Department of Natural Resources, Alaska Department of Revenue, and Alaska Oil and Gas Conservation Commission. One test separator at PM-1 and two test separators at PM-2 will be utilized. Gas Sales Point McIntyre gas sales would utilize a gas flow line in which the LPA has pre- invested for connection into a future gas processing facility. The timing of gas sales is dependent upon market demands and the availability of a transportation system. Prior to initiation of gas sales, the Pt. McIntyre produced gas will be used or consumed for Unit Operations, or injected into another formation underlying the Unit Area as dictated by the desirability from a reservoir standpoint and the availability of such facilities. Fuel will be provided to the LPC as per the LPC facility sharing provisions. Enhanced Recovery Techniques Enhanced recovery techniques such as miscible gas injection will be evaluated in the future to determine the potential of increasing the economic recovery of the Point McIntvre Reservoir hydrocarbons. The source of the miscible injectant may be from processed Pt. McIntyre gas or by purchase from an outside source. Existing Wells in the ProposedAttachmenPt. tM4Calntyre Particil~ating, III ! I I I I I II · I I I A/£ 34623 EXX 34622 BPX 365548 · PM9 ~ P2-5! · P2-55 · P2-4o Proposud Pl. Mclnlyre Pariicipafing Area ~ · PM 7 · PM6 ~' Pl-16 · PI-11 · PM13 , '"' "~*'~ ~_L ~ · Pl-14 · PMI1 J PM 4 P2-30 . , - : .......... ! O PI-Gl ~t PM3 · PM5 AAI 375136 ~~ 1>2 50 Lease l i~ms ~ , '~ ..... 2829U ~ Exisll(~9 Wells " ~ Curr~nlly D~ilhng I Shof~lne~~ Existing Wells in the Proposed Pt. Mclntyre Participating Area ____ Attachment 4a A/E 34623 Proposed Pl. Mclnlyre Participaling Area EXX 34622 · P2-55 P2-51 1-16 BPX 365548 · PUg · PM6 O P2-49 ~ PM13 AAI375136 ~P1-14 ~L~1-20 · P1-G~ PM3 PM 4 PM10 P2-30 Lease Lines~ A/E 28298 A/E 28297 Existing Wells Currently Drilling NE 34624 POINT MclI',ITYRE I EXPI.ORATIOH PAD! DRILLSITE PM! I Attachment 4b POINT MclNTYRE DEVELOPMENT PLAN DRILLSITE AND PIPELINE CONFIGURATION JW ........ ! - - 11_ I_J .... WEST DOCK : CAUSEWAY i! E3 LEGEND EXISTING FACILITY EXISTING PIPELINES FUTURE PIPELINES EXISTING ROADS FUTURE DRILLSITES CENTER SOURCE WAT ,. INJECTION PL,,,~ r ~ Tract No. T12N-R15E, Sec. 18: Sec. 19: ATrACHMENT 5 TRACTS WITHIN THE POINT Mc!NTYRE PARTICIPAT!I~ AND POINT McNTYRE TRACT PARTICIPATIOI~ No. of ADL Serial Basic Lesse Acres Ho. Bgy. al~ Flecc All 875 34627 1/8 ARC Nll2 Exxon I=:xxon-bU% Pt Mclntyre Tract participation % T12N-R14E, Sec. 13: Sec. 14: Sec. 23: Sec. 24: All All Nll2 NWll4, N1/2 NE 114, SWll4 NWll4 Nll2 1800 34624 1/8 ARCO Exxon ARCO-50% Exxon-50% 32.12 T12N-R14E, Sec. 15: Sec. 16: Sec. 21: Sec. 22: All All Nll2 NE1/4 Nll2 1680 28297 118 ARCO Exxon ARCO-50% Exxon -50% 22.65 115 T12N-R14E, Sec. 17: Nll2, N1/2 SE1/4, NE1/4 SW114 excluding U.S. Survey 4044 312 28298 1/8 ARCO Exxon ARCO-50% Exxon-50% 0.05 116 T12N-R14E, Sec. 3: All Sec. 4: All Sec. 9: All .. Sec. 10: All 2560 34622 118 Exxon Exxon- 100% 7.90 A'n'ACHMENT 5 (continued) TRACTS WITHIN THE POINT M¢INTYRE PARTICIPATING AREA AND POINT McNTYRE TRACT PARTICIPATION Tract No; Description Working Pt Mclntyre No. of ADL Serial Basic Lessee of Interest Tract Acres No, Royalty Record Ownership partici_~ation % 117 Those Lands in Block 605 lying northerly of the 3601 north boundary of Section 3, T12N, R14E, UM, AK. (Identical with line 4-5 on Block 605) and lying easterly of the west boundary of Sections 2 and 11, T12N, R14E, UM, AK (Identical with line 5-6 on Block 605) and lying northerly of the south boundary of Section 11 and 12, T12N, R14E, UM, AK, and lying northerly of , the south boundary of Section 7, T12N, R15E, UM, AK (identical with line 6-7 on Block 605), within the offshore three-mile am lines listed as Slate Area on the 'Supplemental Official O.CS. Block Diagram approved 12/9/79. 365548 1/6 BPX BPX-100% 32.63 Pt Mclntyre Field Stump Island Reservoir Type Log Pt Mclntyre #3 sw MY $P MY m ! ,,e --~-:~~~- · ;. -:.."~--',.--~-.: ~o .._~ .... ;__.~___:___~-.-~. ! i _ ..... ~--~.,..,~-~~ -,: ~ .._~_~ ..... :i,2_~.:.~ ; ; ~ · , , ,. .. ,,, ~e--i--. :t'-T-'~-. -- .._.~; _. _. ~.-.,~, ~-.-- - ~:.. - ... : : ,,,- ~:-:~..~---? --d,---+--~: ~-_~ --~_.~' {,.: 4,.;:: ~'.,..: : : , .--~ .... ~.:1-'-., ,.~e.;,,;---.~ ...... .... . _~WI.~;' e~..,/. : ..~.,.__,._~ ,~.:.+_~'_....~i.:.:.-:-..t:,- i - · ..~&~'.-,:--~., --~ : : : ~-"='?.:'-' '- ~-~ ..... '.--.4---..i. 7- 9200 ...~---; ...... ~--.~e--~---e-4,'--. _- ._.i_..2 ...........[ :- ...... -.' ..............-~..5.1-..* .... 4 .... ~- ._: ..... : ...... ~ ..... i .... i.....~:~-.-...-- .... ~ ..... ~ ..... ~----+---:~t .... !---!-.~- '. ~ i '. . : : .... , .... ~ ..... 4- ................ .'.~t; .............. . · i ' : r"~- I' i ..... ; .... i ...... I ..... ; ..... ; ..... ; .... ~ ...... i ...... i .... - ::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: ~ ~:~: : ~ : : ~ ::; :~ .~-'-'~"'~'~~~~'~-'-~ S.~, , ~ i~'i ~ i it~:;'~'~:~: ~ : : :~~ : ~::: . - 1..:,; : : , . ~-- ; : : : 1: · ' ~ '' { ..... . I ::..I: I ~:'- : ' :' '~-' , '-'~; : : ; ~';l:: -,,--'~ · :...; ; : ;::1l"~~ m , ';i ' ~&~;~:~'... ... '_. · ' m ' ") i -- : : ~: : : : : ~!: ..... ." ~ . ~,, ~ -gH~ ... : . . 1:. ~....;~.~.{; ;a---~"'M';;+~ ;~ ...... ~ .--;-~-~F ..... ~'{';Z~';~ .... ~--;.~4; ~Z .... ...i.t.~,~t~ ..... .~..~.;,~.--z~.;.~.~, ~, ...... ~~ :;;;: : n ~ ii:ii : : :~i:" ,...:..,~,,l, ..... ~k. ............. :4-' 'i~ ...... ',{ ,_~ ,.~ :l.,'Tz : . ,~,_~, : , ;: ~ i i~H{: ~ : : ,;:l~ _ . :~1:~ ..4.[.~[~ ...... ~...~..~4~ ..... ~..~.~.~.~ ..... ...4.t.~;~ ...... ~...~..:.;,~}~ ..... ;..,..~+~i1~, ..... ...;.~.~i~ ...... L.J..L;,}~ .... ,..,.i.~.~,~, ..... :~:::::: ~ ~ : :"911 i ; ;'':-~: ATTACHMENT 6 8759' M~ -8200'TVDS: leabee Fm = = ~' 8930'..'M. -8370'TVDS HRZ 8993'A4 -8432.~ ?-= TVD?'~ Kuparuk _.= Fm ~: ~ 9288'A,i -8724' TVDS~ Vliluveach Fm Al(J2 1104~ AO0 Landm 0 Pt Mclntyre Field Pt Mclntyre Reservoir Type Log Pt Mcintyre #11 ATTACHMENT - btj :- .ILKI2 1104~ C~ ~ II I ~tl,. I West Beach Field Rule~ Testimony - Production Allocation ATTACHMENT VI. Production Allocation My name is Ronald Oba. I am an Engineering Director for ARCO Alaska, Inc., currently supervising the Lisburne/Point Melntyre Operations Engineering Group. I received a Bachelor of Science Degree in Mechanical Engineering in 1972 and a Master of Science Degree in Mechanics in 1974 from the University of Colorado. I have 19 years of experience in the petroleum industry working in the areas of production research, operations engineering, and reservoir engineering. I have been working in Alaska since 1984. My work efforts in Alaska have been directed towards the development of the Lisburne, Point McIntyre, and West Beach accumulations. In my testimony today, I will discuss the incentives for commingled production, the concept of well test based production allocation, and the details of production allocation activities for West Beach and all of the other fields which will be producing fluids for processing at the Lt~. Successful implementation of commingled production from several producing....- fields is necessary for the development of small hydrocarbon accumulations on the North Slope. By the term commingled production, I mean the production of fluid streams from individual wells and separate fields which is combined prior to treatment at a common processing fa~iity. At these common processing facilities, the oil, water, and gas are physically separated before measurement. Prior to any sales, the oil and gas streams are metered through standard custody transfer sale meters. Commingled production promotes North Slope resource development by enabling the Producers to reduce capital investments and per barrel operating costs via more complete utilization of existing facilities. Small hydrocarbon accumulations that would otherwise be non-developable resources, become economic reserves because of the lower cost structure resulting from commingled production. An integral part of a successful implementation of commingled production is the allocation of the produced fluids back to the originating field for revenue and reservoir management purp/mes. An analysis completed by ARCO indicates that the conunin~ of production from the Lisburne, Point Mdntyre, Niakuk, and West Beach accumulations will result in the additional recovery of 100-150 million barrels. One reason for this additional recovery is illustrated graphically, in Exhibit VI-25. Ail facilities have a minimum physical throughput rate limit which is determined by the installed equipment. As shown in this exhibit, the commingling of production from multiple fields extends the useful life of each individual field by allowing each field to produce at lower rates while still satisfying the minimum production rate required by the facility. This extension of field life results in additional resource recovery. 21 ,14 January 13,1993 i,',~ West Beach lq el d~.~ u les Testimony - Procl~ion Alloca~on In a similar manner, commingled production also extends the economic lives of both the common processing facility and the associated fields by spreading the daily operating costs over a larger number of produced barrels. Since the base operating costs for a common facility are generally not directly proportional to fuid rates, the cost to proceSs twice as much fluid is not necessarily twice the initial cost. Since comrr~ngled fields can share th~s base cost over a larger number of barrels, their per barrel costs are lower and the economic field life for each commingled field is extended to recover additionai oil. The overall result of commingled production is a prolonged field life for each commingled field. In some cases, however, commingling of production not only prolongs the field life but is in fact the key to the development of small accumulations tha~ cannot support the costs of standalone development. Commingled production is in the best interest of the State of Alaska as well as the Producers. The State of Alaska gains from the additional revenue resulting from the royalties and taxes associated with the additional resource recovery. Based upon ARCO's estimate of additional recovery, this revenue increase amounts to the equivalent of 13-20 million barrels. Aside from the direct monetary gains to the State of Alaska, the extension of productive field lives will slow the decline in long- term employment and prolong the continued purchases of goods and services. These activities will provide a major benefit to the Alaskan economy. The Producers gain from commingled production by the reduction in the investment and the long-term operating costs required to bring the hydrocarbons to market. Another significant benefit of commingled production is the reduction of future environmental impacts. The essence of commingled production is utilizing the existing facilities, gravel pads, and infrastructure to minimize the addition of new major facilities. By reducing the need for additional major processing facilities, future surface and atmospheric impacts will be minimized. ARCO, in conjunction with various other lease Owners, ,has developed a plan to commingle production from several small hydrocarbon accumulations on the North Slope and process the fluids at the LPC. This plan is possible for several reasons. First, the Lisburne infrastructure is centrally located. As shown in Exhibit VI-26, all planned developments are within five miles of existing Lisburne surface production fadlities. This central location allows the development of these known accumulations with minimal additional surface facility modifications. Second, the LPC has excess capacity. The facility was designed as part of a Lisburne development plan which envisioned a much larger reservoir than actually materialized. Thus, certain process components are currently being under-utilized, while others, such as the gas handling equipment, are operating at full capacity. Specifically, the liquid processing equipment is currently operating at less than half of the design capacity. As currently forecasted, commingled production will bring all the production streams more into line with the design capacities of this 22 West Beach Field Rule5 Testimony - Production Allocation January 13, 1993 equipment. This is not to say that additions to the LPC will not be made. Funding has already been approved by the Owners to expand the LPC liquid handling system to more closely match forecasted commingled production rates. This plan will provide for a more effective utilization of all of the LPC equipment on the North Slope. Finally, the LPC is a relatively new facility. Commissioned in 1986, the LPC is one of the newest major facilities on the North Slope. It was designed and built as a standalone processing facility with state-of-the-art equipment. By standalone, we mean that the LPC does not rely on any other facility to completely process production. It has its own electrical power generation equipment and provides its own gas reinjection compression. This is a fairly unique processing facility on the North Slope as the' initial design incorporated state-of-the-art corrosion-resistant duplex stainless steel to mitigate corrosion concerns. Additionally, throughout the short operating life of the LPC, significant modifications and upgrades have been made to maintain equipment quality. Over $7 million has been spent on upgrades to the major equipment, and almost $3 million was recently spent to upgrade the overall metering systems in preparation for anticipated commingled production. Details of these metering upgrades are discussed in Exhibit VI-32. As with any development of hydrocarbons, the quantification of produced oil, water, and gas volumes is important for both revenue accounting purposes and reservoir management activities under commingled production operations. However, when production from several fields is commingled prior to final processing and metering, separate direct measurements of the oil, water, and gas volumes at standard conditions for each producing field are not possible witl existing metering technology. Thus, a production allocation methodology must be adopted. ARCO is requesting that the commingled production from West Beach and all of the other fields producing into the LPC be allocated with a well test based production allocation methodology. In general, the proposed well test based production allocation methodology focuses on individual well rates from each well producing into the commingled system. The production from an individual well is determined from a combination of periodic well tests and the producing history of that individual well. For example, as shown in Exhibit VI-27, knowing the rate at which a well produces oil, water, and gas and knowing the amount of time that well is on production, it is possible to calculate how much volume that well produced on a daily basis. Summing this calculated daily production volume for all wells in a commingled field provides an estimate of that field's daily production. Rarely does the sum of the calculated daily field production volumes for all commingled fields exactly equal the volume measured by the final custody transfer meters. Therefore, calculation of allocation factors is required to maintain a proper field split of the produced fluids. Exhibit VI-28 shows in equation form the general calculations used to determine the allocation factors. Variations in well producing 23 Jantmry, 13, 1993 West Beach Field Rules Testimony - Proctu~tion Allocanor, rates are the main cause for the discrepancies between the calculated production volumes and the sales volumes. These rate variations result from a variety, of causes ranging from natural well production decline to changing surface system conditions. A detailed step-by-step summary of this allocation methodology is presented as Exhibit VI-29. It is worth noting at this time that although daily production allocations are made, only monthly allocated production volumes are generally reported. The accurate allocation of production between fields depends upon the ability of the Operator to recreate the production rate history for each well producing into the common facility. An aspect of determining each well's production history is the frequency of sample points available from the well testing process. Well test frequency should, be derived by the production characteristics of individual wells and should not be set as an arbitrary requirement for all wells. Exhibits VI-30 and VI-31 illustrate this point with two production rate versus time plots taken from two different Lisburne wells. For a Type A well, shown in Exhibit VI-30, production is very stable, predictable, and very few sample points are required to define the "shape" of the production curve. For a Type B well, shown in Exhibit VI-31, the decline changes over time. Clearly, the Type B well would need to be tested more frequently than the Type A well to preserve the same degree of accuracy in estimating produced volumes. Successful implementation of well test based production allocations will depend upon the Operator having the ability to adjust well testing frequency based upon observed well performance. Well tests should be obtained as uniformly as possible and test separator usage should be maximized within operational constraints to ensure adequate definition of the production decline curves. For the above examples, if a minimum frequency of well tests is stipulated for all wells, then less testing time will be available for the Operator to obtain additional sampling points for wells, such as the Type B wells, which might benefit from the extra data points. In order to build comfort and confidence for all parties involved in the well test based production allocation process, we suggest that a minimum requirement of two well tests per month be established for a period of one year. At the end of that time, this minimum well test frequency stipulation should be evaluated at a production allocation process review conducted between the Operator and the State. The process of well test based production allocation is not new to operations on the North Slope. It has been used for years for the purposes of reservoir management in Lisburne and other fields with a range of allocation factors of 0.90 to 1.10, with 1.00 representing the ideal case where the calculated theoretical and actual production volumes match. An evaluation of the impact that this historic range of allocation factors would have on the State of Alaska and the field Producers' total revenue has been completed and indicates minimal or no risk to all parties involved. Since in reality over-payments are just as likely as under-payments, there is limited expected risk over the cumulative 30-year producing life of the commingled fields. We must emphasize that well test based production allocation 24 West Beach Field Rule~ '"~timonv - Production Allocation January. 13, 1993 will never be as accurate as direct custody transfer' metering. However, by comparing the minimal potential risk to the State of Alaska with the much larger State development benefits derived from commingled production of an additional 13-20 million barrels, one can quickly determine that the slight reduction in accuracy assodated with this methodology is completely overshadowed by the losses resulting from potential non-development. Recognizing the need to reduce as much potential error as possible, the Lisburne Owners over the past year have invested nearly $3 million to upgrade the critical meters used for the allocation of production. The focus of these upgrades was the installation of state-of-the-art mass flow meters and online water cut metering at all drill site test separators. A mass flow meter calibration station has been constructed and installed at the'LPC to allow for onsite calibration checks. This onsite station will allow for cost effective meter calibration and provide an opportunity for third party witnessing. Maintenance schedules have been established and operator train, lng has been undertaken. All of this has been done to ensure accurate equipment is available for well testing. Additionally, well testing guidelines such as stabilization time, test duration, and testing frequency continue to be updated as existing well performances dictate. Similar guidelines will be established as commingled fields start production. As presented, both the State of Alaska as well as the Producers have a vested interest in commingled production and well test based production allocation. It is important that all parties have a firm understanding of the allocation process. It is with this in mind that ARCO fully supports efforts by the State of Alaska to designate a single lead agency to address metering and well test based production allocation issues for the State. We envision that as commingled production begins, all parties should play an active role in determining the appropriateness of the actions taken within the allocation process and should focus on ways to streamline the methodology while meeting the needs of all involved. It is via this partnership that the most efficient, accurate, and fair allocation of commingled production can be achieved. Specifically addressing West Beach development, ARCO is' proposing that production be commingled prior to separation at the LPC and that oil, water, and gas production be allocated back to the producing fields by utilizing well test based production allocations. Exhibit VI-32 is a report describing the details of the proposed implementation of well test based production allocations for commingled production being processed through the LPC. In brief, the proposed implementation involves the following features: 1. Periodic production testing for all wells producing into the LPC. 2. Well test frequency will be maximized using all available test separator capacity at each drill site, within the constraints imposed by operating conditions. 25 48 March t-~ 1993 i' West Beach FieldiP 'les Tesnmonv - P:~duc::on Aitocanon 3. The stabilization period and test period duration of each well test will be optimized bv the Operator to obtain a representative test. 4. The Operator will attempt to obtain well tests at uniform intervals. 5. Well and field operating condition information required for the construction of a field production history will be maintained. 6. XGLs will be allocated based on gas volume produced and computer simulated process yields. 7. Major test separator meters, major gas system meters, and major water production meters will be installed and maintained according to industry recommended practices or standards. 8. The Operator will maintain records that permit verification of the satisfactory execution of the approved production allocation methodologies. 9. The Operator will submit the Production and Injection Report per 20 AAC 25.230 and 20 AAC 24.432 by the 20th of the month following the reporting period. .,;~- 10. The Operator's allocation activities will be reviewed on a periodic basis. 11. Metering installations for any field whose production will be commingled for processing in LPC Will have to meet the same industry standards for metering that Lisburne installations currently meet, and where possible, installation of similar meters ,,viii be required. West Beach will initially be tested at DS-L1 so there will not be any new metering required to bring West Beach into the LPC. In summary, we believe that commingled production prior to final separation and custody transfer metering will benefit-both the State of' Alaska as ``veil as the Producers. Waste of resources will be prevented and cost effective, environmentally sound development of North Slope resources ``viii be achieved. Coupled with commingled production is the allocation of that production. Well test based production allocation is a complex activity requiring continuous application, development, and refinement. While not exact, the proposed allocation methodology provides for the fair treatment of all produced fluids. Any potential misallocations associated with this methodology are completely outweighed by the benefits derived by all parties involved. From a practical operating viewpoint, commingling and well test based production allocation activities for West Beach and all other fields producing into the LPC need to be conducted in a similar manner. Thank vou for vour attention. This concludes nay testimony on Production Allocation. Now I would like to turn the floor over to Andy Simon who will summarize our testimony. 26 49 100000 9O000 80000 70000 60000 50000 40000 3O000 20000 10000 Rate vs. Time for Two Generic Fields With Separate Facilities and Two Generic Fields Commingled at a Single Facility with a 10,000 BOPD Minimum Rate Facility Limit Facility Rate ' ~ .... Shutin Commingled Fields A and ! !i ' Shutin -Field-~ }'~ 1993 1998 2003 2008 2013 2018 2023 2028 ' : ::JJ?-:?.CAUSEWAY .:.... ..: · POINT MclNTYRE EXPLORATION PAD DRILLSITE PM1 LEGEND I i i i i ii W. BEACH PIPELINES Pl. Mc. DRILLSITES Pt. Mc. PIPEUNES EXISTING FACILITY EXISTING PIPELINES EXISTING ROADS DOCKHEAD 3 DRILLSITE PM2 WEST BEACH' LISBURNE'!:/ POINT MclNTYRE · . .. . WEST BEACH " . . - DS*LIlLGI : . . . !3: '- . .:::. -. . . ::::': ..- PRUDHOE · . · , ., DS-L5 LISBURNE PRODUCTION CENTER DS-L3 SOURCE WATER INJECTION PLANT . . DS-L4 Approximalely 1 Mile I I Well Tests and Event History for a Generic Well 2000 - , 1800 1600 1400 ~' 1200 "-' 1000 i5 ~oo 6O0 400 200 was ShutinI~~ ....... . . Time Theoretical Pror~---flon [] Well Tests Allocation Factor Calculations Allocation Factor Aq~.. al Produced Volume Theoretical Volume (T_, Well Tests) Oil Factor Water Factor TAPS Volume- NGL Volume- TAPS BS&W- Exploratory Fluids + Unrecoverable Oil- Load Crude/Diesel ±Slop Oil Tank Movement I; Well Test Oil Rates Injected Water Volume - External Water + TAPS BS&W +_. Slop Oil Tank Movement T_, Well Test Water Rates Gas Factor [_PC Fuel + Injected Gas + DS Fuel- DS Lift Gas Usage +NGI Shrinkage + Flare Assist + Flare (est) - PBU Fuel T_, Wells Test Gas Rates JanuaLy-13, 1993 Lisburne/Point Mclntyre/West Beach Allocation Methodol°gy 1. Conduct well tests to determine production rates for each well. Cdteda for determining what wells to test: · Known well pedormance · Significant Events Pre and post well work tests Diagnostic work (i.e. temperature and pressure changes) Tests for engineering purposes · Date of last test 2. Review well tests for validity. ; How does this well test compare with past well tests for this well · Was the stabilization period long enough · Was the test duration long enough · Did the flowing tubing pressure change significantly dudng the test · Did the lift gas rate change during the test 3. Review the significant events for each well. · Examine the event history for shutins, openings, gas lift gas changes and choke changes. · Examine the drill site operator shift change notes for why a well was shutin and other items of interest that might have an impact on the oil, water and gas rates of the wells. This includes, flowing tubing pressure and temperature trends, he' oiling, hot gassing, methanol treatments, LPC back pressure, field prorations, etc. 4. Calculate each well's theoretical monthly production by combining well test rates with significant events for that well. Allocating with no significant events: · Allocate from the beginning of one well test to the beginning of the next well test. Allocating with significant events: · Instead of extrapolating as a well is shutin or extrapolating for flush production when a well is brought online, it is assumed that the last well test rates are constant from the beginning of the last well test until the end of the event and that the current well test rates are constant from the end of the event until the beginning of the next well test or event. 5. Sum the theoretical monthly production volumes for all wells in all fields. Exhibit VI-29 January 13, 1993 6. Calculate an allocation factor which compares the sum of theoretical monthly production volumes for all wells In all fields to the "Total Sales" volume as determined by the critical meters. Allocation Factor 'Total Sales' Volurpe Sum Of Theoretical Monthly Production Volumes For All Wells 7. Calculate each well's allocated monthly production volume as' Allocated Production Theoretical Production Volume X Volume = Allocation Factor 8. Sum allocated production volumes for each well In each field to determine the amount of production derived from each field. .%5 Exhibit VI-SO oooo o o o o ~ o o o ~:::r~,-.~ ~00 0 0 0 0 ~ ~ ~ ~ ~ Exhibit EXHIBIT VI-32 West Beach Field Rules Testimony Supporting Documentation Well Test Based Production Allocation ECONOMIC PERSPECTIVES Commingling of production will benefit the State of Alaska by preventing waste of the State's hydrocarbon resources by facilitating production of resources that would not be produced otherwise. West Beach is a good example of this, the reservoir size would not support a standalone facility so its resources would never be produced. Another reason that commingling .prevents waste of the State's hydrocarbon resources is shown in Exhibit 1. All facilities have a minimum throughput rate that is determined by the turndown rates of the specific equipment installed in the facility. When that minimum throughput is reached then the fadlity and all of the fields produdng into that facility will'have to be shutdown. In the example shown in Exhibit 1, which assumes a minimum facility throughput of 10,000 BOPD, Field A is shut down in the year 2013 and Field B is shut down in the year 2007. However, the commingled fields are not shut down until the year 2026. Being able to produce each field to a lower facility limit allows more reserves to be produced. For Lisburne, West Beach, Point Mclntyre and Niakuk the additional recovery is estimated to be 100 to 150 million barrels, of which the State of Alaska should receive 13-20 million barrels of this oil in Royalty and Severance Taxes. Beyond the deferring the attainment of the physical minimum rate limits of a facility. commingled production also extends the economic life of a processing facility and the associated fields by spreading the daily operating costs over a larger number of barrels. Generally, the base operating costs for a faciliw are not directly proportional to rate, and thus the cost to process 20,000 BOPD is not tv~ice the cost to process 10,000 BOPD. The cost to process 5,000 BOPD is more than, half the cost to process 10,000 BOPD. Thus, commingled production allows two fields to produce at 10,000 BOPD production rates while benefiting from lower processing costs that separate fields would have to produce at 20,000 BOPD rates to obtain. The bottom line result is a prolonged economic field life for each commingled field and thus a greater recovery of the resources in place. Commingling of production allows oil from fields that could not support the capital investments required for their own standalone facility to be produced and additional oil to be produced due to the facility minimum throughput benefits and economic life extensions discussed previously. Implied with commingled production is the allocation of that production. Currently, there is no accepted technology available to directly measure the production from the individual commingled fields. Thus, a well test based production allocation method is proposed. The process of well test based production allocation is not new to operations on the North Slope. It has been used for years for the purposes of reservoir management in Lisburne and other fields with a range of allocation factors of 0.90 to 1.1, with 1.00 representing the ideal case Where the theoretical and actual production volumes match. An evaluation of the impact that this historic range of allocation factors would have on the State of Alaska and the fielci Page 1 1/13/93 Producers' total revenue has been completed and in ...ates minimal or no risk to all parties involved. Since in reality over-payments are just as likely as under-payments, there is limited expected risk to the State over the cumulative 30-year producing life of the commingled fields. We must emphasize that well test based production allocation will never be as accurate as direct custody transfer metering. However, by comparing the potential risk to the State of Alaska with the State's benefits derived from commingled production of an additional 13-20 million barrels, one can quickly determine that the slight reduction in accuracy associated with this methodology is completely overshadowed by the losses resulting from non-development. DATA GATHERING SYSTEM · The Lisburne Data Gathering System (LDGS) provides access to information from almost every part of the field. LDGS maintains an event history for each well. Access to flowing tubing pressure and temperature provides a way for the allocation engineer to verify that all of the shut ins were recorded in the event history. · LDGS keeps on line the last 12 well tests for each well. · Having LDGS go down does not cause well test data to be lost. · A month-end backup of LDGS is permanently stored offsite. The LDGS is an automated data gathering system for the Lisburne production system. LDGS provides access to information from almost every part of the field. Data collected and stored by LDGS is divided into two parts: analog data that is collected every minute and meter data that is accumulated every five minutes. Data.from several analog points are usually combined to calculate the meter rates. For example, gas rate would be calculated from the differential pressure across an orifice plate, the static pressure and the temperature. Some of the LDGS data that is used for production allocation is; well test oil, water and gas rates, lift gas rate, choke position, flowing tubing pressure and temperature, plant inlet pressure, separator pressure, and temperature and header pressures and temperatures. The operational data is kept for 44 days so all of this data is available on the month-end backup. LDGS also provides a place to store notes and observations from the field operations personnel for the allocation engineer and the drill site engineers. LDGS also maintains an event history for each well. The event history records when a well was opened or shut in and any choke and gas lift rate changes. Since Lisburne does not have automated chokes to shut in wells and automated valving to divert wells in and out of test, all of this is done manually by the drill site operator. The event history is kept for 44 days so all of this data is available on the month-end backup. Additionally, having access to flowing tubing pressure and temperature provides a way Page 2 1/13/93 59 for the allocation ..,tgineer to v. erify that all of the shu, ins were recorded m the event history. If for some reason the LDGS goes down because of a communication failure, a shutdown to install new programs, an unexpected crash, etc:, well testing will not b, adverselv affected. At the drill sites, data is collected by the Bailey process control system, and then that data is transferred to LDGS; so if the LDGS goes down, the Bailey is still collecting data. Once back on line, LDGS can continue with the well testing in place. LDGS is backed up with the following schedule: daily backups for one week, weekly backups for four weeks, and then a monthly backup. The monthly backup is taken after all of the production allocation for the month is completed and it contains the official results for that month. The month-end backup is kept offsite and is kept permanently. The monthly backup can be loaded onto an alternate system and all of the data for that month accessed. DETAILED PRODUCTION ALLOCATION PROCESS · Conduct well tests to determine production rates for each well. · Review well tests for validity. · Review the significant events for each well. · Using data from the following month will help to eliminate the "wedge" effect an, improve production allocation accuracy. · Calculate each well's theoretical monthly production by combining well test rates with significant events for that well. · Sum the theoretical monthly production volumes for all wells in all fields. · Calculate an allocation factor which divides the "Total Sales" volume by the sum of the theoretical monthly production volumes for all wells in all fields. · Calculate each well's allocated monthly production volume by multiplying the theoretical production by the allocation factor. · Sum the allocated production volumes for each well in each field to determine the amount of production derived from each field. Once well tests are obtained, the allocation process begins. Exhibit 2 shows the methodology used in allocating production. The steps used in allocating production are straight forward and leave little room for subjectivity. The only steps that are open to subjective treatment are Steps 2 and 3, reviewing the well test for validity and Page 3 1/13~93 combining well ~est rates with significant events. { ,ne rest of the steps used are programmed into the LDGS and are out of the control of the allocation eng4neer. The first step of allocating after the well tests are obtained is to examine the quality, of the well test; was the stabilization period long enough, did the flowing tubing pressure change significantly during test, did the lift gas rate change during the test, etc. The significant events are combined with the well test data to determine each well's theoretical production. Significant events include shut ins, lift gas changes, choke changes, hot gassing, hot oiling, flowing tubing pressure and temperature changes, plant pressure changes, field prorations, etc. LDGS maintains an event history for each well, the event history keeps track of when a well was brought on line, when it was shut in and the time of any lift gas or choke changes. The drill site operators also maintain shift change notes. These shift change notes are used to pass in.formation of what was done and what needs to be done to the other shift. The shift change notes are a valuable tool for determining why a well was shut in or what work a well had done to it. Other pieces of information that are available on LDGS are the flowing tubing pressure and temperature, the plant inlet pressure, and the drill site header pressures and temperatures. Sometimes events are missed in the event history or the times might be off be a couple... of hours. A way to verify the shut in times is to examine the flowing tubing pressure. The flowing tubing pressure will almost always change immediately when a well is shut in. If a missing event is found, retroactive events can be entered on LDGS to correct the mistake. If nothing happened since the last well test, then the well production rates are interpolated from the beginning of the previous well test to the beginning of the current well test, as illustrated in Exhibit 3. For cases where a shut in or other significant event occurred between the last test and the current test, the rates are assumed to be equal to the last well test rates and the rates are assumed to be constant from the beginning of the last well test until the end of the-significant event..Then from the end of the significant event until the beginning of the current well test, the rates are assumed to be equal to the current well test rates. This is illustrated in Exhibit 4. There is some potential error built into these basic assumptions. For example, if the event is a shut in, there could be some flush production assodated with bringing that well back on line. This could be a positive or negative rate impact which varies well by well, from shut in to shut in, and with the length of the shut in period. Only having well established production performance can help to determine this type of impact, but it is subjective in nature. Since there is no dean, simple, way to consistently estimate the flush production behavior of a well, we have chosen to handle these events by assuming the well was producing at the same rates as the most recent well test. By making this assumption, consistency is maintained in the treatment of all flush production events for all wells, which eliminates the ability of the allocation engineer to introduce a field bias into the allocation factor data. The same assumptions are made for gas lift rate changes, choke changes, wells dying, etc. Page 4 1/13/93 Overall, the abilit-: .o do retroactive adjustments after ~....,mges in the flowing conditions of ,,,,'ells have occurred allows the allocation engineer to handle a variety of situations. For example, if the LPC system pressure increased by a significant amount, causing the rio,,,,- rates to change on all of the wells, aggressive testing of all the wells could be conducted at the higher pressure. By coupling these new test results with retroactive ad~tstments, accurate production allocations could be maintained for the period after the system pressure changed. In determining the theoretical monthlv production from a well, all data is used. Specifically, well test data from the past months as well as data from the first part of the following month can be incorporated in the analysis. By using the data from the next month, the "wedge" effect can be reduced. Exhibit 5 illustrates this situation. During the month of October 1992, the "wedge" effect accounted for a 3°70 change in Lisburne's monthly oil allocation factor. Therefore, extension of the month-end doseout of all data will improve the allocation process. Thus, final allocated production rates will be reported by the 20th day of the following month. An example of additional supporting data to be reported is shown in Exhibit 6. After the theoretical volumes are determined for all of the wells by combining the well tests with the significant events, all of the theoretical monthly volumes are summed for all of the wells in all of the fields. An allocation factor is then calculated by dividing the known "Sales" volume by the sum of all of the wells theoretical monthly volumes. Each wells allocated monthly production is then calculated by multipl,ving that wells theoretical monthly volume by the allocation factor. The allocated monthly volumes for all of the wells in a field are then summed to determine that fields' monthly production. WELL TEST FREQUENCY · Frequency should be determined by' well behavior--some require less frequent testing and others more frequent testing. · Well test selection is based on known well performance, significant events, and date of last well test. ° Currently in Lisburne, test separator usage is 80% - 90%. · Any minimum monthly well testing frequency requirement might not be met under certain circumstances (e.g., pipeline prorations, plant problems, and well failures). ° West Beach development will initially be one well and will be tested at DS-L1. Therefore, there will be no significant impacts on well testing frequency at DS-L1 Accurate allocation of production between fields depends upon the ability of the operator to recreate the production rate history for eacia well producing into the common facility. One aspect of accurately simulating each well's production history is Page 5 1/13/93 the 'frequency of"~ample points available from the ~._il testing process. Well test frequency should be determined by the production decline characteristics of an individual well and should not be set as an arbitrary across-the-board testing frequency requirement for all wells. Exhibit 7 and 8 illustrate this point with two production rates versus time plots taken from two different Lisburne wells. For a Type A well, the decline is clearly very stable and predictable and very few sample points are required to define the "shape" of the production curve. In Lisburne, some Type A wells are so stable and predictable that they need only be tested infrequently to satisfy curiosity and verify that production remains on t~e expected trend. (;3 For a Type B well, the decline changes more over time and requires more sample points ' to define the "shap. e" of the production curve. Clearly, the Type B well would need to be tested more frequently than the Type A well to preserve the same degree of accuracy in estimating produced volumes. In lOoking at Lisburne historical well test data, we have categorized all wells into three general groups based upon well performance characteristics. Currently, Lisburne wells are evenly divided within these groups. We have examined the impacts of varying well test frequency on the calculated production volume for wells in each category, as shown ..-' in Exhibit 21. As can be seen in this exhibit, Type A wells need less frequent testing in order to maintain deviations comparable to highly variable Type B wells. Operator flexibility is a key issue that will greatly impact the ability of the operator to successfully implement well test based production allocations. Well tests should be obtained as uniformly as possible and test separator usage should be maximized within operational constraints to ensure adequate definition of the production decline curves. For the above examples, if a minimum frequency, of well tests is established for all wells, then less testing time is available for the operator to obtain additional sampling points for wells, such as the Type B wells, which might benefit from the extra data points. The criteria for determination of which wells to test at any one time varies. Under normal circumstances, the primary driver for well test selection is known well performance. As production history is established, confidence in the well test frequency for individual wells improves. Thus, the establishment of rigid guidelines prior to acquisition of any production history is inappropriate. Secondary drivers in determining which wells to test are significant events and the date of the last test. Significant events include pre- and post-wellwork tests, diagnostic evaluations (when temperature and pressure changes), and tests for engineering purposes (production optimization). One of the operational constraints on well testing is the drill site operators' time. Unlike other North Slope Fields, the Lisburne system does not have automated well testing capabilities. Future developments are not expected to have this capability either. This means that the LDGS cannot automatically divert wells into and out of the test separator; the drill site operator must do it manually. Currently Lisburne has five day-shift and two night-shift drill site operators in order to maintain efficient Page 6 1/13/93 operations. Durir,o me day there is one lead operator ~..at roazns the field and performs numerous tasks. There is a drill site operator at DS-L2, a drill site operator at DS-L4, a drill site operator that watches DS-L3 and DS-L5 together, and a drill site operator that watches DS-L1 and DS-LGI together. At night there are two operators: one for drill sites DS-L1, DS-LGI, and DS-L2, and another operator for drill sites DS-LB, DS-L4, and DS-L5. Drill site manning levels are expected to be similar for future operations. Having the drill site operators spread out like this makes it difficult to achieve 100%o utilization of available testing equipment. For example, the drill site operator could be busy doing remedial work on a well or at another drill site when a well test ends. It could be some time before he is able to manually divert another well to the test separator. However, even with one drill site operator covering several drill sites, Lisburne has been able to achieve test separator usage in the range of 80% - 90% (allocatable well testing usage in the range of 70°/,, - 80%) of total available equipment time. This relatively' high percentage of allocable well tests is a result of the operators and the engineers ability to monitor wells thru LDGS as they are tested and respond to any anomalies. It is felt that even with the addition of more drill site operators, this equipment utilization cannot be significantly improved. An inherent problem with establishing any minimum testing frequency is that there are several scenarios that would cause the operator to not meet these requirements. Operation problems such as pipeline prorations, plant upsets, and mechanical well failures are unavoidable. Problems like these are usually unexpected and require the immediate shut in of wells. By establishing arbitrary well test frequencies, the operator will have increased difficulty in accurately predicting produced volumes during and after these upset conditions since valuable testing time could be wasted testing wells solely to meet frequency requirements. In the case of a mechanical well failure, the well might have to be shut in for safety reasons prior to meeting any minimum requirements. Current operations, as well as future operations, will require wells to be cycled in order to maximize total offtake. Currently, this is due to gas handling constraints. For example, in November 1992 Lisburne .had two wells which tested higher than the permissible GOR; one well was online for 15 hours and the other for 8 hours. Both wells had only one test and were shut in for the majority of the month. It would be a waste of effort and a reduction of total off-take to bring these types of wells back into the system solely to meet arbitrary testing requirements. Initial development of West Beach calls for one well to be commingled at DS-L1. The one West Beach well combined with the ten currently producing DS-L1 wells will not present any well testing frequency problems. If more wells are necessary for full West Beach development, the option of an additional test separator at West Beach will be explored. It is currently estimated that the addition of test separation fadlities and associated piping would cost the Owners approximately $10 million. Page 7 1/13/93 WELL TEST STABi~.IZATION AND DURATION · Optimum well test stabilization and duration times vary from well to well and rnav vary over time. · Well testing guidelines for Lisburne wells have been established based on total flow rate and total gas liquid rat/o. These guidelines are periodically reviewed. · Well testing guidelines for West Beach, and any other commingled field, w/il be examined after start-up. In well test based product/on allocation, it is important that representative well tests be obtained. Some of the more important aspects of well testing are well stabilization time, test duration, and the frequency of well testing. Optimization of each of these aspects will vary from well to well and over time for a given well. As more production history is obtained for any given well, more confidence in test stabilization and duration time can be achieved. Thus establishing rigid guidelines prior to obtaining any production history is inappropriate. Exhibit 9 shows typical well stabilization behavior; the gas rate stabilizes first, then total liquid rate stabilizes, and finally the water cut stabilizes. This type of behavior is reflective of the physical process of flushing out the testing flowlines and the test separator and is highly dependent upon the producing characteristics of the well being tested and its distance from the test separator. Generally, the higher the producing rate the shorter the required stabilization and testing period. Conversely, low GOR, low flow rate, and intermittently gas lifted wells tend to require longer stabilization and testing times. Additionally, the slugging characteristics of the well plays a key role. This is best understood by looking at Exhibits 10 and 11 which show plots of production rate versus time for two types of wells. Exhibit 10 shows a well with the flow rate relatively constant, and therefore a representative value can be acquired by measuring production rates over a short period of time. Exhibit 11 shows a well with the flow rate varying significantly with time. This well must be tested for' a longer period of time to obtain a value that is representative of the well's average production rate. Based upon these general well performance characteristics, generic well testing guidelines for Lisburne wells have been established. By examining stabilization time versus flow rate data, such as shown in Exhibit 12, we have determined with a high level of confidence that a stabilization period of one hour is sufficient for a well producing >1,300 BLPD, four hours is sufficient for a well produdng between 300 and 1,300 BLPD, and eight hours is sufficient for a well producing <300 BLPD. In a similar manner, we have established guidelines for test duration as a function of gas liquid ratio (GLR); if the GLR is <15,000 SCF/STB then the well test duration is eight hours, and if the GLR is >15,000 SCF/STB then the well test duration is four hours. These testing guidelines are reviewed and updated periodically as well performance and field operating condit/ons change over time. For example, with the installation of online water cut meters, Lisburne is evaluating the resulting data to determine if a significant refinement of the existing testing guidelines is possible. These testing Page 8 1/13/93 guidelines a_re ut..~zed as a starting point for well tes,..,g duration and the ~_ctual welt · tests are monitored during and after the test to ensure representative flows are obtained. Well testing stabilization and duration times for West Beach and any other com_nfingled fields will be examined after start-up. WELL TEST BACKPRESSURE ADJUSTMENTS Testing wells in a test separator imposes an incremental backpressure on a well. This backpressure will cause the well to test at slightly different rates than the normal production rates. The impact of the back pressure effect is determined by the productivi ,t-y index of a well. · If there are large errors introduced by the backpressure effect, then the well test rates can be corrected. It is anticipated that the backpressure effects for West Beach and Lisburne will be relatively small and that no adjustments will be necessary. During the execution of a well test, the production from a well is redirected from the normal production piping system into a test piping system. Generally, this change imposes an incremental backpressure of 0-20 psi on the well as it is being tested and will result in the measurement of a production rate that is slightly different (lower) than the normal production rate. The magnitude of the incremental backpressure is determined by the size of the test equipment and towlines and the relative amounts Of oil, water, and gas being measured. The overall impact of this incremental backpressure is determined by the individual well's productivity, index. Productivity, index is defined as the change in well producing rate with a change in pressure. In the case where the combination crf well productivity index and incremental backpressure exerted by the test separator are significant, the raw well test rates could be adjusted using the well's productivity index. The productivity index would be determined via additional well tests performed at several different backpressure conditions on a periodic basis, as dictated by changing well performance characteristics (such as GOR, water cut, or total fluid rate). A typical productivity index range for wells produdng into the LPC will be on the order of less than one to five barrels per day per psi of pressure change. Due to the combination of small well productivity indices and small well test incremental backpressures, the current backpressure impacts in Lisburne are relatively small, and it is anticipated that the backpressure impact for West Beach will also be relatively small. No adjustments are anticipated. Other fields that are commingled into the LPC will be examined for backpressure impacts. As production histories are established, future backpressure adjustments may be made. Additionally, tests are currently underway to operationally' reduce the magnitude of the backpressure when a welJ is in test. Page 9 1/13/93 GENERAL ME4_-,ING AND ALLOCA.~ON EQUA~ .,.)NS · There are 46 values involved in the calculation of the oil, water, and gas allocation factors. · Original Lisburne metering design was for reservoir management purposes which required less meter accuracy During 1992, approximatelv $3 million ,,vas spent to upgrade the test separator liquid meters, the gas injection meters, and the LPC fuel meter and to install master artificial lift gas meters. · Any field that will be commingled into the LPC will have to meet the same industry standards' for metering. · Since West Beach will be commingled at DS-L1, no additional metering will be required. · Lisburne has developed a specific flow measurement' manual and trained a meter calibration group. · To facilitate the calibration of the mass meters, a gravimetric proving skid has been installed at the LPC. An important part of well test based production allocation is accurate metering of the produced and disposed of fluids. Lisburne facilities were originally designed with a reservoir management basis for determining metering requirements. This design basis resulted in generally requiring less measurement accuracy. Metering emphasis has now shifted from a reservoir management basis to a revenue determination basis. Therefore, in 1992 the Lisburne Owners spent nearly $3 million to upgrade several critical meter stations. The test separator meters were upgraded from turbine meters to mass flow meters. Online microwave water cut meters were installed to augment periodic well test shakeout samples. Plans are underway to install a new metering run on the produced water line. All liquid metering stations should fully meet accepted standards. There are currently 46 values used for the calculation of the oil, water, and gas allocation factors. Exhibit 13 shows all of the critical meters for Lisburne production allocation. Exhibit 14 shows the equations used in the calculations of the oil, water ,and gas allocation factors. The LGI injection gas meters and the LPC fuel gas meter were upgraded and new drill site master gas lift meters were installed. With these gas meter upgrades, meters responsible for measuring 99.5% of the produced gas processed by the Lisburne production system meet AGA-3 and API standards. The remaining 0.5% of the total produced gas is associated with the five drill site fuel meters, the flare assist'meter, and the high and low pressure flare volumes. Page 10 1/13/93 The low and hib. pressure flare volumes are est ..... ated by examining the plant conditions before, during, and after a flare event. Direct measurement of these flare volumes is not feasible since a very wide range in potential rates would need to be covered and varying amounts of liquid carryover would need to be handled. Attempts to improve the measurement of these flare gas volumes would significantly impair primary safety relief functions of the flare systems. Since May 1991, the historical gas volumes invoived in flare situations, including flare assist gas, has been less than 0.1% of the total gas processed at the LPC. While the five Lisburne drill site fuel gas meters and the flare assist gas meter were not upgraded, their accuracv is still +2% and the volume of gas they measure less than 0.$% of the total produced g~s processed by the Lisburne production system. No upgrades for these meters are planned since their impact on gas allocation is extremely small. It is anticipated that metering installations for any field whose production will be commingled for processing in the LPC will have to meet the same industry, standards for metering that Lisburne currently meets, and where possible, installation of similar meters will be required. West Beach will initially be tested at DS-L1, so there will not be any new metering required to bring West Beach into the LPC. Concurrent with upgrading of the physical instrumentation used in the production allocation process, the Lisburne Maintenance Group has accepted the responsibility for meter calibration and maintenance. Wl'dle the Prudhoe Bay Flow Measurement Group will continue to be available as a technical information resource, the primary responsibility will reside with Lisburne Operations. This group is developing a flow measurement manual that outlines everything relating to flow measurement including required training for personnel, calibration equipment, calibration frequency, anc calibration procedures. Increased training for personnel includes several industry and internal courses including the International School of Hydrocarbon Measurement and the API- PETEX School of Liquid Measurement. Calibration frequency for all critical meters is currently planned on a monthly basis. However, this could change as more field performance data is received. - : To facilitate the calibration of the mass meters, a gravimetric proving skid has been installed at the LPC. A schematic is included as Exhibit 15. This gravimetric proving skid duplicates the same calibration procedures that the manufacturer uses to calibrate all of the mass meters that it produces. Having the gravimetric skid at the LPC allows us to more easily verify the accuracy of the mass meters and eliminates continually shipping meters back to the factory for calibration. Simply stated, the gravimetric skid works by pumping water from a holding tank, through the mass meter and onto a very accurate scale. The weight of the water on the scale is then compared to the weight of water measured by the mass flow meter. The resulting meter factor is then calculated. The weights used to calibrate the scales are certified by the National Institute of Standards and Testing and ,,vill be recertified with the State of Alaska Division of Weights and Measurements every two years. Page 11 1/13/93 68 o(n ( The density porti ' of Lhe mass meter is verified with a ,wo-point test, one point wiLh air and one point with water, md a linear densiw is assumed between Lhe air and water densities. This is also the same procedure used by the manufacturer for densitv calibrations. OIL METERING AND ALLOCATION · The TAPS sales volume is accepted as "truth" and is measured with a t'arbine meter proved da.ily and compensated for BS&W by a 24-hour composite sampler. · The test separator total liquids are measured with Micro Motion mass flow meters. The water cut is measured with Phase Dynamics water cut meters. · The tmstabilized NGL volume is measured with a Micro Motion mass flow meter. · Load crude and diesel volumes will be tracked by well, allowing each field to be charged for its usage. Exploratory fluids and unrecoverable oil volumes have been insignificant but are accounted for. The calculation of the oil allocation factor uses the actual produced volume sold to TAPS and the sum of the individual well tests. The actual produced volume sold to TAPS is corrected for the TAPS BS&W volume, the stabilized NGL volume, the load crude and load diesel volumes, the exploratory oil volume, and the unrecoverable oil volume. The actual numerical equation used in the allocation of oil production is shown in Exhibit 14. The TAPS volume is measured by Alyeska with a turbine meter, which is proved daily and has an accuracy of _+0.10%. The values measured by the TAPS meter are taken as the ground truth for the well test based oil production allocation process. The unstabilized NGL volumes are measured by a Micro Motion mass flow meter with an accuracy of _+0.20%, and the stabilized NGL volumes are determined from a computer process simulation to be discussed in detail later. The TAIX3 BS&W volume is determine by Alyeska at Pump Station No. I and reported to the LPC each day. The TAPS BS&W is determined from a 24-hour composite sampler at Pump Station No. 1 and is typically less than 0.02%. Exploratory fluids are produced during testing of exploratory wells in the area and the fluids typically are trucked to the LPC and added to the Slop Oil Tank. Exploratory fluids are typically measured very accurately during well testing. Additional volume measurements are made as the fluid is transferred from the truck and as the Slop Oil Tank level changes. Since LPC start-up, the exploratory oil volume has been insignificant. Page 12 1/13/93 69 Unrecoverable oil ..~dudes spilled oil and oil that cannt~ oe processed a~nd is sent offsite for disposal. If the un_recoverable oil is due to a spill, then the volume can only be estimated. If the oil is taken to offsite for disposal, then the Slop Oil Tank level and the truck volumes are used to calculate the volume. Since LPC start-up, the unrecoverable oil volume has been insignificant. Load crude comes from Pmdhoe Bav Flow Station No. 1 (metered at ±! %.) and is used in wells for remedial treatments such as hot oil jobs and stimulations. Load diesel (metered at _+0.5%) comes from the Crude Oil Topping plant and is used as a remedial treatment fluid and to freeze-protect wells and towlines. The total load ~ude and load diesel volumes are subtracted from the total sales volume at the end of each month. Individual field usage will be accounted for. Since October 1991, the load crude and diesel was less than 0.25% of the total oil processed by the LPC. The sum of the individual well tests from all fields provides the denominator for the numeric allocation factor equation shown in Exhibit 14. The test separator meters provide the cornerstone for these measurements. The test separator fluid measurement meters have been upgraded to Micro Motion mass flow meters (_-+0.2%). The mass meter was tested against a tm-bine meter at DS-L2 prior to installing the mass meters at all of the drill sites. Exhibit 16 shows an overlay of the mass meter and turbine meter rates. Phase Dynamics microwave water cut meters (+0.5 to 1.0%) provide online water production measurements and are supplemented by periodic shakeout sampling. The water cut meter performance was verified at DS-L2 prior to installing them at all of the drill sites. W-orking in combination, these two meters accurately measure the amount of oil and water produced during a well test. Thus, the oil allocation factor is derived from the calculation of an adjusted sales volume divided by the produced volume derived from the well testing program. WATER METERING AND ALLOCATION · The meter on the disposal well will soon be upgraded to an ultrasonic meter in order to provide more reliable, long-term, consistent service. · External water would include water from pit dewatering and exploratory water. · The test separator total liquids are measured with Micro Motion mass flow meters and the water cut is measured with Phase Dynamics water cut meters. · Well test shakeouts will supplement online water cut measurements. The calculation of the water allocation factor uses the actual disposed or injected volume and the sum of the individual well tests. The actual disposed or injected volume is corrected for the TAPS BS&W volume and the external water added to the slop oil tank volume. The actual numerical equation used in the allocation of water production is sho,.,m in Ex_hibit 14. Page 13 1/13/93 7O The metering on ~he water disposal line is analogous me TAPS oil sales meter and is considered to be "truth." The accuracy of the t'~bine meter currently installed on the production water disposal line is ±5.0Fo. Recognizing that additional accuracy is required in future operations, the Lisburne Owners plan to install a new ultrasonic meter run during earl,,,, 1993. The accurac'v of the new replacement ultrasonic meter is ,22%. The mai.n advantage to this upgrade is that the ultrasonic meter should provide more reliable, long-term, consistent service due to it not being affected by entrained The TAPS BS&W volume is determine by Alyeska at Pump Station No. i and reported to the LPC each day. The TAPS BS&W is determined from a 24-hour composite sampler at l:h. unp Station No. 1 and is typically less than 0.02%. External water could be from several sources including exploratory wells or pit dewatering during breakup. External water is usually trucked to the LPC and added to the slop oil tank. If the water is exploratory water, then exploratory volumes are typically measured at the well very accurately. If not, the level control on the slop oil tank'and the volume of the trucks used to transport the fluid a.re used to determine the volume. Since LPC start-up, the external water volume has been insignificant. The sum of the individual well tests from all fields provides the denominator for the numeric allocation factor equation shown in Exhibit 14. The test separator meters provide the cornerstone for these measurements. The test separator fluid measurement meters have been upgraded to Micro Motion mass flow meters (_-+-0.2%). The mass flow meter ,,vas tested against a turbine meter at DS-L2 prior to installing the mass flow meters at all of the drill sites. Phase Dynamics microwave water cut meters (+0.5 to 1.0%) provide online water production measurements and are supplemented by periodic shakeout sampling. The water cut meter performance was verified at DS-L2. prior to installing them at all of the drill sites. Data collected since the water cut meters were installed shows very good agreement between the shakeouts and the water cut meter readings and is shown in Exhibit 17. Shakeouts will be used as a backup if something unforeseen should happen 'to the water cut meter. To ensure that the shakeouts are of as high a quality as possible, new sample ports were installed in order to obtain a representative production sample. GAS METERING AND ALLOCATION · In the calculation of the gas allocation factor, there is not a single meter that provides a direct total produced gas measurement analogous to the oil "sales" meter. The test separator gas meters, the LPC fuel gas meter, the IPA fuel gas meter, and the artificial lift master meters meet current AGA-3 and API standards for sales orifice meters and are responsible for measuring 99.5% of the produced gas processed by the Lisburne production system. · The NGL shrinkage volume is calculated by the same computer facility process simulator that calculates the stabilized NGL volume. Page 14 1/13/93 · The flare vol Les are estimated and are historica . ./uite small. The five drill site fuel and the flare assist meters do not meet current industry standards for sales meters. However, these meters handle less than 0.5% of the total gas processed by the Lisburne production system. In the calculation of the gas allocation factor, there is not a single meter that provides a direct total produced gas measurement analogous to the oil "sales" meter. In Lisburne, there are currently 0._20 meters or calculated volumes that are used to perform the gas allocation. There are six gas injection meters, the LPC fuel meter, the five drill site fuel meters, the high and low pressure flare volumes, the NGL shrinkage volume, the five master gas lift meters, the flare assist meter and the IFA fuel meter. These critical meters and volumes are shown in the critical metering diagram. The actual numerical equation used in the'allocation of gas production is shown in Exhibit 14. The five test separator gas meters, the LPC fuel meter, the six gas injection meters and the IPA fuel gas meter have recently been upgraded and meet current AGA-3 and A.PI standard for orifice meters and are accurate to +0.5%. These meters are responsible for measuring 99.5% of the produced gas processed by the Lisburne production system. It is currently antidpated that these meters will be calibrated monthly. However, as more field performance data is gathered, the timing of the calibrations might change. .. The NGL shrinkage volume is calculated by the same facility process simulator computer program that calculates the stabilized NGL volume. This will be discussed in detail in another section. The flare volumes are estimated by examining the plant conditions before, during, and after a flare event. Direct measurement of these flare volumes is not feasible since a very, wide range in potential rates would need to be covered and varying amounts of liquid carryover would need to be handled. Attempts to improve the measurement of these flare gas volumes could significantly impair the primary safety relief functions of the flare systems. Since May 1991, fhe historical gas volumes involved in flare situations, including flare assist gas, has been less than 0.1% of the total gas processed at the LPC. Exhibits 18 and 19 show the number of flare events, the size of the flare events and the flare gas percentage of the total gas processed at LPC. The five Lisburne drill site fuel gas meters a.nd the flare assist gas meter do not meet current industry standards for sales meters. These meters are flange fitting orifice meters with online pressure and temperature compensation. The accuracy of the drill site fuel and the flare assist meters is in the range of +_2%. The volume of gas these meters measure is less than 0.5% of the total produced gas processed by the Lisburne production system. NGL MEASUREMENT Field NGL volumes trill be determined by the field's volume o£ produced gas and field NGL yield factors. Page 15 1/13/93 · The methodolco~ used for NGL stabilization caicul~ ins wil! remain the same. Field NGL yield factors will be calculated based upon field conditions and process simulation. As shown in Exhibit 20, unstabilized crude enters the crude oil surge drum where light hydrocarbons are flashed to achieve the true vapor pressure spedfication requested by Alyeska. The surge drum off-gas was originally contained in the unstabitized crude entering the surge tank from the treaters and the unstabilized NGI_.s antering from the NGL plant. Since the exact volume of stabilized NGLs cannot be directly metered, a process simulation's program (Simulation Sdence's PROCESS) is used to determine the amount of stabilized NGLs contained in the liquid sales volume leaving the LPC. This program is an industry accepted tool for modeling plant operations and uses thermodynamic data' and equations of state to predict plant behavior. A field test conducted in April of 1992, during which the NGL plant was taken offiine and all other ~ and field conditions were kept constant, verified the volume of NGLs predicted by the current methodology used to calculate stabilized NGLs. When the NGL plant was taken offiine, the total rate to TAPS decreased by the volume that the process model was calculating. L.i~burne Stabilized NGL Volume Determination (Current) A process model of the LPC has been developed that matches the rates and compositions observed at the LPC. The model is run twice for a given set of operating conditions, once with the NGL stream blended with the crude, and once with no NGLs blended in. The difference in the calculated sales liquid rate is the amount of NGLs that stabilize with the crude. A simulation derived Stabilization Factor (SF) is then calculated as the ratio of stabilized NGLs over total unstabilized NGLs. This SF is then applied to Meter 660 (actual plant unstabilized NGL rate from the depropanizer to the crude surge drum) to determine actual stabilized NGL rate. Meter 660 is a Micro Motion mass flow meter capable of _+0.2% accuracy. The shrinkage volume is the amount of gas equivalent to the stabilized, NGL volume. SF and Shrinkage Factors (SFIF) have been determined for several different plant conditions covering the normal operating range of the LPC and are entered into lookup tables in LDGS. LDGS interpolates the SF by taking hourly averages of slug catcher pressure, depropanizer pressure, and reboiler temperature and reading from lookup tables generated from process data. The following list and example show how the SF and total stabilized NGL volume are currently determined at the LPC. The actual data gathering and calculations are automatically done on LDGS. The numbers used are for illustration purposes only. 1. Record hourly averages of pertinent plant operating conditions. 2. Calculate hourly SF and SI-IF based on operating conditions. Page 16 1/13/93 3. Calculate the [. ,f houri,,' and daily stabilized NGL(' d shrinkage Hourly NC..L(5773) = (Meter 660) x Hourly Shrinkage (.MSCF) = (:Meter 660) x (SF) x (SI-IF) Daily Total NGL (DTN?) = Sum of hourly NGL volumes Daily Total Shrinkage (DTS) = Sum of hourly Shrinkage volumes Total rate to TAPS including ."JGLs *: Total rate to TAPS without NGL plant *: Stabilized NGLs blended with crude: Total tmstabilized NGL rate out of depropanizer*: NGL SF: Actual hourly NGL rate blended with crude: Daily Total NGL 'volume (DTN): Total produced gas to injection without NGL plant *: Total produced gas to injection with NGL plant *: Equivalent NGL gas Volume *: St-IF: Actual hourly Shrinkage Volume: 36,O00 STB / D 31.500 STB / D (36,000-31,500) = 4,500 STB/D 8,300 AB / D (4,500/8,300) = .542 = 54.22% (Meter 660) X (Si) Sum of hourly NGL volumes 45O,OOO M. SCFD 442,000 MSCFD (450,000-442,000) = 8,000 MSCFD (8,000/4500) = 1.77 MSCF/STB (Meter 660) X (SF) X (St-IF) * Note: This value has been calculated by process simulator. NGL Volume Determination (Commingling Lisburne and West Beach) The Daily Total NGL (DTN) and Shrinkage (DTS) volumes will be calculated as they are currently when multiple fields are commingled into the LPC. However, in order to calculate the contribution of each field (Lisburne and West Beach) to the stabilized and un. stabilized NGL volumes, it is necessary that the components making up each reservoir be labeled and tracked separately. Thus, the Lisburne methane component will be labeled as LISC1, the West Beach methane component as WBC1 with the remaining components being similarly labeled (LIS(ED LISC3, ..., WBC2, WBC3, ..., etc.). In this way, the model is able to differentiate the makeup of each stream by component and the field that produced that component. From this data, NGL yield tables (Stabilized STB NGL/MMSCF produced gas) are developed for each field over the operating range of the LPC. These yield tables are used in combination with the current methodology to deterrrdne the volume of stabilized NGLs for each field. The following list shows the steps involved and how the methodology would apply for calculating the stabilized NGL volumes for a two field case (Lisburne and West Beach). The same approach will be used when additional fields are commingled. Current 1. Record hourly averages of pertinent plant operating conditions. 2. Calculate houri}, SF and St-{F based on operating conditions. 3. Calculate the LPC hourly and daily stabilized NGL and shrinkage volumes: Page 17 1/13/93 74 Mom~' NGL(STB) = (Meter 660) x (SF) Hourly Shrinkage (>,~SCF) = O,,Ieter 660) × (SIr) x (S~L1::) Daily Total NGL (DTN) = Sum of hourly NGL volumes Daily Total Shrinkage (DTS) = Sum of hourly Shr-inkage vo!mmes Additional Calculations Due to Commin~ing . Calculate average daily yield (YLis, YWB, etc.) for each field based on L°C operating conditions. . Calculate Apparent and Total Apparent NGL (AaNLis, ANWB, each field based on daily yidd and gas rates: TAN) volumes for ANLis (STB) = (YLis) x (GasLis) ANWB (STB) = (YWB) x (GaswB) TAN (STt3) = ANLis + ANWB 6. Allocate stabilized NGL and Shrinkage volumes for each field: (ANLis) NGLLis (STB) = TAN x DTN AN Where: TAN - NGL Fraction by Field NGLWB (STB)= (ANWB) TAN x DTN ShrinkLis (MSCFD) = (ANUs) TAN x D'IS ShrinkWB (MSCFD)= (ANWB) TAN x DTS USAGE OF MISCELLANEOUS FLUIDS · LPC fuel and flare gas and drill site fuel and flare gas will be divided among the produdng fields based on each field's fraction of gas being handled at that fadlity. · Load crude and diesel will be tracked by well so that the load crude and diesel can be properly charged to the field that used it. · Unrecoverable oil '.Mil be split among fields based on each field's fraction of the oil produced at the faciIity where the oil was lost. Page 18 1114~93 75 External water'v,.~ll ~ sub,ri'acted from the water diI~..~sal meter. · Exploration oil will be subtracted from the TAPS sales oil and will be 7edited to the exploration Owner(s). LPC fuel and flare gas ,.,,'ill be divided among producing fields based ,avon the gas fraction produced through the LPC by each field. At the LPC, 86% of the fuel is used to run the gas compressors that handle the produced gas. Drill site fuel and flare gas will be divided among the fields producing into each drill site based upon the gas fraction produced through that drill site. All of the drill site fuel is used to run the drill site heaters. The major reason for adding heat to the drill site fluid before it is sent to the LPC is the cooling caused by the entrained gas. The flare gas at the LPC and the drill sites will be divided among fields producing based upon the fraction of gas each field produced through that facility. 76 Page 19 1/14/93 100000 90000 80000 70000 60000 50000 40000 3OOO0 20000 10000 1993 Rate vs. Time for Two Generic Fields With Separate Facilities and Two Generic Fields Commingled at a Single Facility with a 10,000 BOPD Minimum Rate Facility Limit ..... Minumum Facility RateI ' ' Fields A and B IShutin C°mmingled ............. 1 \ 1008 2003 2008 2013 2018 2O23 ?02P Lisburne/Point Mc!ntyre/West Seach Allocation Methodology 1. Conduct well tests to determine production rates for each ',veil. Cdteda for determining what wells to test: · Known well pedormance · Significant Events Pre and post well work tests Diagnostic work (i.e. temperature and pressure changes) Tests for engineering purposes · Date of last test' 2. Review well tests for validity. · How does this well test compare with past well tests for this well · Was the stabilization period long enough · Was the test duration long enough · Did the flowing tubing pressure change significantly during the test · Did the lift gas rate change during the test 3. Review the significant events for each well. · Examine the event history for shutins, openings, gas lift gas changes and choke changes. · Examine the drill site operator shift change notes for why a well was shutin and other items of interest that might have an impact on the oil, water and gas rates of the wells. This includes, flowing tubing pressure and temperature trends, hot oiling, hot gassing, methanol treatments, LPC back pressure, field prorations, etc. 4. Calculate each well's theoretical monthly production by combining well test rates with significant events for that well. Allocating with no significant events: · Allocate from the beginning of one well test to the beginning of the next well test. Allocating with significant events: · Instead of extrapolating as a well is shutin or extrapolating for flush production when a well is brought online, it is assumed that the last well test rates are constant from the beginning of the last well test until the end of the event and that the current well test rates are constant from the end of the event until the beginning of the next wall test or event. 5. Sum the theoretical monthly production volumes for all wells in all fields. Exhibit 2 78 Januar4' 13, 1993 6. Calculate an allocation factor which compares the sum of theoretlca~ monthly production volumes for ali wells in all fields to the "Totr~ Sales" volume as determined by the critical meters. Allocation Factor "Total Sales" Volume Sum Of Theoretical Monthly Production Volumes For All Wells 7. Calculate each well's allocated monthly production volume as: Allocated Production Theoretical Production Volume X Volume = Allocation Factor 8. 'Sum allocated production volumes for each well in each field to determine the amount of production derived from each field. 2000 1800 1600 1400 1200 1000 800 6OO 400 200 Production Allocation - How a Typical Well is Handled Time " Theoretical Production [] Well Tests How Allocations Are Typically Handled: · Allocate from beginning of test to beginning of test Production Allocation - How a Shutin is Handled ~ooo !i 1600 ...i! 1400 1200 / la.si well Is.si rate from tho la.st / ......... 800 ~ {well tesl until lbo well was shulin./ ' .................................................... '' :1 '' ' ......... , ........................... · ; ................... ~ · 600 4OO 200 Well was ...... ~ · '1' Well opened - Slraight line wilh the new well tesl tale from when the well was opened until lhe new well test. , , , i J__ Time Theoretical Production M Well Tests I~low Allocations for Shutin's and Other Similar Events Handled: Beginning of Well Test to Event, Event to Event or Event to Beginning of Well Test - Typical Events Include: Shut-ins, Hot Oiling, Hot Gassing, Choke Changes, Gas Lift Changes, gnificant Slugcatcher Increases/Decreases Pressure. land Temperature'Trends. The Month End "Wedge" Eflect 1600 1400 il- ' - -~ .............. . 1200 '~- 1000 800 minimum of 4 tests for allocations in that month. .................. ~ "[_:Pr°ducti°r~Trend i The Month End "Wedge" Effect I I I I I I I I I I. I I I I IM°nll~'End -Boundaries : I I I I I I I I I date to meel reporting requiremenls ',lx_0_. ool The "Wedge" effecl is the error 400 - inlroduced in the allocalion laclor caused by not being able to inlerpolate between well tests that cross the month end boundaries 200 ~- t [ ~ . I~-'--" " ' I ' ' ~ ~ ..... 'j III Ii I I I I ~'~ .'?'~1 I I I I I I I 4/1~ 2 4,/11/92 4/21/92 5/1/9 2 5/11/92 5/21/92 ,. 5/31/92 6210/92 6,~20!92 _. 6/30/92 MONTH END SUPPORTING DATA · Well Test Data WELL TEST REPORT ..... TESTED RATES EXPECTED .... D AVG AVG AVG TOTAL LIFT FORM TOTAL TOTAL SYAB TEST FORM T T A F F OI~IFC WEI,L DATE TIHE STRT C}{K WELL FTP SEP OIL WTR GAS GAS % GOR GOR GI~R TIME TIME OIL GOR % S Y I, l, L DIA HO. COI4P COHP TIHE POS TEMP TEST PRES STBD BPD MSCFD MSCFD WTR SCF/B SCF/B SCF/B fIRS }{RS'STBD SCF/B w'rl~ T P IJ {; G IHCIIES Event Summary PROCESSING FACILITY 1 EVENT SUMMARY REPORT FOR 12-0~-92 TO 12-31-92 SI~H'F-IH WELL DAYS HOURS REASON OIL TOTAL RATE GOR TOTAL GAS START OF EVENT END OF EVENT RATE H~-DD-YY I{HMM HIH-DD-YY PROCESSING FACILITY 1 CHOKE & GAS LIFT CHANGE SUMMARY REPORT CURRENT PREVIOUS CURRENT PREVIOUS EVENT TIME CHOKE CHOKE LIFT GAS LIFT GAS WELL H~-DD-YY HHMH SETTING SETTI t~O ~A'r E RATE · Monthly Oil, Water and Gas Allocation Factors . Nu,.,i3er o'f Well Tests per Well by Drill..re and Test Separator Usage Stati C::I::DO~D 0 0 0 c:::Z:::XZX~ 0 0 o°° (DO0 0 (DO 0 0 Exhibit 7 $5 ooooo o o o oo o o ~ooo o o o ~~ ~ ~ ~ Exhibit Q 350.00 ~' 300.00 ~ 250.00 200.00 .~' 150.00 .,.. 100.00 Typical Well Test Stabilization 400.00 ..................................... : ............................................................. 50.00 - -- ..., 0.00 · , 12/21/92 15:32 12/21/92 16:44 12/21192 17:56 · · I · · I I 12/21192 19.08 12/21192 20:20 6500.00 4000.00 Typical Well Test for a Stable Well 3000.0 2500.0 ~- 2000.0 1500.0 1000.0 - i , i . i i i i ~ ...................... * .................................... t ............................. i .......................................................... $ .................................. ~ ..................... ' 4500 Water 0.0 12/17/92 12:00 12/17/92 13:12 12/17/92 14:24 12/17/92 15:36 i · ~ · ! ! I ! · J'--I [ I · ! ![ · ! · ! ~[[ ! i i i I i i[[~ ['[l~ 1~---! I I i ! ! m "7192 16:48 1~17/92 18:00 12/17/92 19:"~2 12/17/92 20:24 5O0O - 3500 30OO Typical Well Test for a Slugging Well 500 ii __i' 400O 450 '~ .............. ; ...................................... I ............. ." .......... ~. ....... ~ ............................... .~ ....... , ~ 3000 350 10000 30o ~o 1...~ -[-~ooo _ ~oo ........ : ........................... .. ......................... "~ ....... ~ .: ......... .._ ~ ................ : 'w~o~'-'--~ooo ~oo ............................ 5O -5000 0 -$000 12/17/92 12/16/92 12/16/92 12./16/92 12/18/92 12/18/92 12/19/92 12/18/92 12/16/92 12/18/92 22:50 0:02 1:14 2:26 3:38 4:50 6:02 7:14 8:26 9:36 Llsburne Well Test Stabilization Time Guideline 8.00 · 3.00- 7.00 - . ............................................................ 6.00 -.t- ..................... ! ....................... .: ............................................... ~ ..... 5.00 T ........................ I ....................... ! ..................................................... i .................... ~, ............................................... i .......... 2.00 ---- · i iii i i_ · · ' · --qk" · · m · -11-- I I I~B~ I I I" I " I II · 1.00 - 0.00 - 0 500 1000 1500 I I I I Li ' Rate, BLPD, 2000 ~ il i iiii I i i · 11 LISBURNE, POINT MCINTYRE AND WEST BEACH CRITICAL METERING DIAGRAM 1 LISBURNE WELLS Test Separat~x IPA FUEL Test Separator PT. UC,.~RE. WELLS ~ _ Te~t Sepmat¢~ EXPLORATORY FLUIDS & EXTERNAL WATER UNRECOVERABL OIL. !LPCFUEL i LOADCRUDE& NGL SHRINKAGE GAS (estimated) & HP & LP FLARE (esUmated) LPC LPC-0! WATER INJECTOR ~ TAPS (OIL + NGL'S) FUTURE ' DRILL SITE ARTIFICIAL LIFT FUTURE POINT ( WEST ~ LISBURNE POINT WEST MClNTYRE IEACHJ DRILL SITE FUEL LISBURNE PT. MCINTYRE FUTURE ~ , WEST · BEACH GAS REINJECTION Allocation Factor Calculations Allocation Factor Actual Produced Volume Theoretical Volume (Z Well Tests) Oil Factor Water Factor TAPS Volume - NGL Volume - TAPS BS&W - Exploratory Fluids + Unrecoverable Oil- Load Crude/Diesel _+Sloo Oil Tank Movement z, Well Test Oil Rates Injected Water Volume - External Water + .TAPS BS&W + Slop Oil Tank Movement T_, Well Test Water Rates Gas Factor LPC Fuel + Injected Gas + DS Fuel- DS Lift Gas Usage +NGL Shrinkage + Flare Assist + Flare (est)- PBU F. ue! z: Wells Test Gas Rates BFiTCH TRI~ I 6.000 O' ~ TPt,,a~ C IROJ_FiT lNG ~ tip VI:~I~BI_[ .~:~£D FLEX JOINT ! &' ~ ~ fllal, oilOTlOi ArT ! e/".~J I~_~x JOINT RIEVI,GF._D I I - i8-D~> 1400 1200 1000 DS-L2 Micro Motion Mess Meter versus Turbine Meter :!_ I II · 4,/6/92 10:30 4/8/92 11:IX) 4/6/92 11:30 4/8/92 12:00 4/8/92 12:30 4/8/92 13:00 · · i 4/8/92 13:30 Turbh. ~ter ~i Mass Meter 100.0 90.0 80.0 70.0 60.0 50.0 40.0 30.0 20.0 10.0 0.0 Lisburne Shakeout vs. Water Cut Met.er Data ! · 0.0 10.0 20.0 30.0 4O.O 5O.0 60.0 Water Cut Meter Water Cut (%) 70.0 80.0 90.0 100.0 All Drill Sites Ideal 45 Deg,.Une ;-%~-~-~- ...... - Least Squares Fit I m I i ii i i i i Flare Frequency and Average Flare Volumes for Lisburne (5/91-11/92) 9 - ~ ~': i ': ' ': i '!" i ' ~ ~ ~ ~ ~ ' " ..... i i ~ ~ 18000 i ! -.---_-'--",j ' ! ....... ! ............. i ............. , ......... ~ ....... ~ : ! ' ' i ..... i- - '- '"" : ; -'I ~._~,,:--,:.. ..... ~: .......... , ..... ii! !.~$:~ : · ::! . -..- . . - -,.. i! ; i'~'`-':' : : :: "' .... i 12000 ~ 5 "- '; .i~: ~ ~"; ',. x!.t .............. ~ ............. ~-- ~ ' F...,*.~. ,_ ,~ ~ ~'~! . ...... ; o,,, 4 · .i-,;!;;-i~--i- ~%,..i !~-,,, '~f "* ; '- ~ : -- aooo . *; -% : ........ i .... ~ ~ ~., - ,. ':' "~' !' - ..... ' ~,] _ ~_--._c'-.,?; ~ ~g :~ ~ .i ...... .~ ........... L--: ,i - I - - ; .:_,{-::,:] !.- -~¢: ~.;- 4. .i.- 4. .~: ! ~.; ~.~-:':t~ ~;~-ii i i i i '**" o -_i iL-*.::.!.ii ~ .... ~, ~ ~ i .: ~i i iii_ i i .t.~if~.i i ~i i ~*~:-;': ~i~ ~ i.;';.: ~li~i: : ii?:?.-~:,i~, : C3 Number of I~'~m IEv®n~ [] Ave~ ~:lar~ Volume ............ -=- .... Overall Average Flare VolumeI Total Flare Volumes and Total Flare Volume As A Percent of Total Produced Gas for Lisburne (5/91 - 11/92) 42000 i .... ~ .; ~ .; ~' '~ ~ ~ "'~ ~ .: ~ ~ ' ~ '~ ~ ~ 0.35% : ~ [ i : · i i i : ' 36000 . .. .: .,: ~,,,~ ................................. : : ~ .........~ .~ ~ i -. i-- - ~ .... 0.30% -., : : i . 0 30000 ................... . : ! : 24000 ................................. : (1) : [~,,,..,..: : : -- ~ ~';~,'! .i .............. ':-~ o 1~ooo ' "~.o' ........... 0 1 5 % -" '..-,,,... ..... :, ..'.i~:.: : : ~.,~:-: . . : .-~..- .-.~ - ~ ~. ~ I! E~:.~:': : · ~ : ' .... '12000 : : ~.~.~ i ~ ~ ~ : !i~ i;-i ·" i ~ .... , .... 0. o 5 % o :'~-~:'"?~; : ' ' ' : ' ' - : Ii'~ ~1[ - " o. 0.00% ,, ~ Tolsl Fla[~ Volome · Monthly Flare ¥olom® As a % o! ..... Tolal Flare Volome As a % ot Produced Gas Produced Gas · ~, i i j ~ ~ ', ,LPC NG~ PLANT SIMPLIFIED F.LOW DIAGRAM OIL, GAS & WATER IN OIL OUT GAS OUT :~.'~ ......... :~z~~ =~'~.~~reat~r Flash Drum Crudo Hoator ................................... UNSTABILIZED OIL GAS TO REINJECi~N l ,, UNSTABILIZED NGLS GAS FLASHED OFF (NGL AND CRUDE) 'TVP Analyzer Oil Surge Drum Meter 51 STABILIZED OIL AND NGL TO TAPS 35.00 30.00 25.00 20.00 15.00 10.00 5.00 0.00 -5.00 -10.00 -15.00 -20.00 -25.00 -30.00 -35.00 o Percent Deviation vs Days Between Well Tests for High, Medium and Low Variance Wells Volume Wilh All Tests ,, I The Low VarianCeandWell is a Type A Well~ ............................... tThe High Variance Well is a Type B 10 20 30 40 50 60 70 Average Number of Days Between Well Tests Low Low · Medium ..... Medium · High High ATTACH.~ t E.." Production Reporting Forms SAMPLE PRODUCTION ALLOCA-I-ION/OFFTAKE SCIIEDULE AltCO Al ASI(A, INC. Iq I()i)llC1 ION AI_I.OCATION I OFFTAKI- SCI lEI)Ill E PFIODUC'I ION MON I I I AUGIJS] - 1992 I ISUIJltNE PAl i I ICIi'A liN(; Al lEA Wot king Oil Oil Oil NGI.S NGI_ S NGlS Inleresl f~oyally, f~oyally t3oyally Royally Royally Royally Owner In Kind In Value Total In Kind In Value Tolal Exxon BPX AAI I'A{ ;1. Tolals: 1.000000 Oil '[ax NGI_S (BBLS) '[ax Basi_s NGi S (M.~()F) ]ax I~ ........ Working Inleresl _ Owne~r Exxon BPX AAI Tolals: Oil Royally. In Kind 1.000000 Oil Royally In Value Oil Royally Tolal POINT MCIN1YRE PAIll ICIPATING Al'lEA ! NGLS HGI S NGI S Royally Royally Royally In Kind In Value Tolal Oil Tax Ila__si~ NGI.S (BBLS) Tax Dasis HGI S (M.%(;I ) ]ax ....... 1.1~ ...... Wolking Inleresl Owner Exxon AAI Tolals: Oil Royally. In Kind Oil Royally In Value Oil Royally Total WEST BEACII PAl ITICIPATING Al iEA NGI S NGI_S NGI S Royalty Royally Royally In Kind In Value '{'ol.~l Oil [ax , {J~i~ NG! S (Dill S) ]ax l~i~ ........ 100000l) Wo~king Interesl BPX AAI Iolals: Nom. Decimal 1000000 SAMPLE PRODUCTION ALLOCATION/OFFTAKE SCIIEDULE AlICe Al ASI(A, IN(; I"IIL)I)I. IC'IION AL LOCATION / OFF'TAKE SCI PRODI. ICllON MON'lll AUGtlS1 - 1992 I IS|~iI. Ii~NE PAl II ICIt'A I lNG AIILA AIIocaled Liqu. Ld~ F'ipeline P_B...U._~ud¢ 1 Ik Olfl~ke I'A( ;1- 1 [oad Diesel I:loyally From oil Unil ....... [J~¢__ . Walking Interest Owner Exxon BPX AAI iolals: Nom. Decimal 1.000000 Allocated Li0uid~ POINT MCINTYRE PAFIflCIF~AI'ING AIIEA Pipeline PBU Crude flk Ofllake NGI S Load Diesel I:loydlty From ollUr~it ....... t~_ _ Working Interesl Owner Exxon AAI Tolals: Nom. Decimal 1.000000 AIIocaled Liouid~ WEST BEACII PAR'I ICIPA]ING At Pipeline PBU Crud~ Ilk l.oad Diesel I {~y,~lly E OL~rrL~ILHnii __ U,~. Working Interest Owner Exxon BPX AAI Iolals: Olltake @ Nominalion 1.000000 SAMPLE PRODUCTION ALLOCATION/OFFTAKE SCtlEDULE AlICe Al ASKA. INC i'Ii(_)I)IIC I ION AI_I.OCATION / OFF'IAKF_ SCI I!!1)!11 E - PRODIIC-IION MON'II I AtJGI. IS! - 1992 I_ISBtJFINE PAI-I ! ICIPAI lNG Al:lEA Over I (Under) Over /(Hnder) Over / (Under) Olllake @ Lilt Lift Lilt Ownel,,shiD Currenl Month i~liolPelimls.. C, unl~daljvu Working Inleresl Owfl~'[ Exxon BPX AAI Totals: OIItake @ Nomination i.000000 POINT MCIN]YRE PAltTICIPAIING AItEA Over / (Under) Over / (Undel) Olflake @ ' Lift l.ill Ownership Curlent Month Piio~Pefio(l~ Over / l irt Cum_u!alj_v~ ...... Working Interesl Owner Exxon AAI Totals: Ofllake @ Nomination 1.000000 WEST BEACII PAFHICIPATING AREA Over / (tJnde~) Over / (IJnder) Over / (Under) OIIlake @ Lift I_ill l.ifl Ownelship Curie_ nL~g_LIIh Priol~e[io,_ I~_ C_,Ljflu/Ja ltv_ L.' ...... ASOF: 087,31/I.q92 FOFIM i0-40S SAMPLE PRODUCTION AND INJECI-ION REPORT AI{CO Al ASKA, INC. AI_ASKA OIL AND GAS CONSEFtVA! ION COMMISSION MONTliLY PFIODUC'[ION REPORT LISBURNE PARI/CIPATING AREA FIEI D - LISt3tllttl[: I'AIt I I(;II'A 111'~(; Alii A OPEFIA'[OII - AtlC() Al ASKA, Irl(;. I~I]O[)UC]IOI{MOt'IIII AIJ(_;IISI - 1:)9;! Woll .... ~umbe[ _ _. APl ['Lumb~r Field Cod~ .... MLh Averago Daily Daily Days Gas/Oil Tubing Average Average P~od i~Jalio .... ~s~.u[c_, .... C),J ...... _W_nl_or Daily l ol;il ltd, ~1 Average Oil Water Ga~___/[~[![ ) .... [~13 LI ' ~AMPLE AREA GAS DISPOSITION AND RESt, ,IE DEBFr REPORT ARCO ALASKA, INC. VOLUMES ARE IN MCF AT 14.65 PSIA PRODUCTION MONTH L~BURNE PRODUCTION CENTER AAI BPX TOTAL OWNERSHIP PERCENTAGES L~sburne West Beacl~ Point Mclntyre TOTAL HYDROCARBON LIQUIDS PRODUCED (STB) Lisbume West Beach Point Mcln~yre L.PC SYSTEM SUMMARY TOTALS TOTAL SOG GAS PRODUCED LESS TOTAL FUEL GAS USED Power generatmn fuel Lease fuel LPC fuel Total LESS POWER GENERATION SALES LESS FLARE GAS Flare wi~in AOGCC Allowable Excess Flare Subiect to Tax Excess Flare Subj. to Tax/Pnlty Total LESS NGLS (MCF equivalent) TOTAL SOG RESERVE GAS DEBi3S GAS INJECTED PARTICIPATING AREA SHARE BREAKOUTS TOTAL SOG GAS PRODUCED Lisburne West Beach Point Mclntyre LESS TOTAL FUEL GAS USED Lisburne Power general~on fuel Lease fuel LPC fuel LPA Total West Beach Power generation fuel Lease fuel LPC fuel WBPA Total Point Mclntyre Power generation tuel Lease fuel LPC fuel PMPA Total PAGE 1 t04 :SAMPLE AREA GAS DISPOSITION AND RESt:RVE DEBIT REPORT ARCO ALASKA, INC. VOLUMES ARE IN MCF AT 14 65 PSIA PRODUCTION MONTH LISBURNE PRODUCTION CENTER TOTAL LESS POWER GENERATION SALES Lisburne West Beac~ Point Mclntyre LESS FLARE GAS Lisburne Flare within AOGCC Allowable Excess Flare Subject to Tax Excess Flare Subj. to Tax/Pnlty LPA Total West' Beach Flare w~thin AOGCC Allowable Excess Flare Subject to Tax Excess Flare Subi. to Tax/Pnlty WBPA Tob3J Point Mclntyre Fla~e w~in AOGCC Allowable Excess Flare Subject to Tax Excess Flare Subj. to Tax/Pnlty PMPA To~al LESS NGLS (MCF equivalent) Lisburne West Beach Point Mclntyre TOTAL SOG RESERVE GAS DEBITS Lisburne Current month Y'rD West Beach Current month Point Mc!ntyre Current month GAS AVAILABLE FOR INJECTION Lisburne Current month YTD lTD West Beach Current month lTD Point Mclntyre Curren! month I'ID 105 PAGE 2 ARCO ALASKA, INC. VOLUMES ARE IN MCF AT 14.65 PSIA PRODUCTION MONTH USBURNE PRODL~TI<:~ CENTER AAI BP)( TOTAL SCG RESERVES INJECTED INTO LPA RESERVOIR From L~st3urne Current month From West Beach Current mon~ Point Mclnt~re Current month TOTAL SOG RESERVES INJECTED INTO WBPA RESERVOIR From Lisburne Current month From West Beach Current month From Point Mclntyre Current month TOTAL SCG RESERVES INJECTED INTO PIV~A RESERVOIR From Lisburne Current month From West Beach Current month From Point Mclnlyre Current month TOTAL NOTE: Each pa~cipatJng area's apportioned share of fuel gas utilized in the LPC and flare gas in any month is based on its apportioned share of total produced gas. PAGE 3 THIRD ~ TO PRUDHOE BAY UNIT OPERATING AGREEMENT LIBBURNE SPECIAL SUPPLEHENTAL PROVISIONS ?HIS AM~DMF_NT is entered into-and effective as of January 17, 1992, by and between the undersigned Parties ("Lisburne Owners"), which are all t. he Working Interest Owners of the Lisburne Participating Area within the Prudhoe Bay Unit. WHEP~T_qS, the Lisburne Owners executed the Llsburne Special Supplemental Provisions as Articles 44-59 of the Prudhoe Bay Unit Operating Agreement ( "PBUOA" ), effective December 1, 1986, ("Lisburne Provisions,,); WHEREA~, the Lisburne Owners amended the Lisburne Provisions on July 31, 1987, and April 1, 1988; WHEREAS, PBUOA Section 21.005 provides that Parties to a Participating Area may amend the provisions applicable to that Participating Area without the consent or agreement of the other Parties to the PBUOA; WH~~, PBUOA Section 49.06 provides that amendments to the Lisburne Provisions shall require approval by 100% of the Lisburne Voting Interests; and - 1 - 1 0 7 Wh~, the LisDurne Owners desire to amend '-he Lis~urne Provisions to change the provisions for snaring Lisburne Equipment. NOW ~"'HEREFORE, in considera=ion of the mu=ual promises and o covenants se= forth below, the Lisburne Owners agree to amend t. he Lisburne Provisions as follows: 1. Amendment =o Article 44 Article 44 is amended by the addi=ion of the following ..- definitions: Fixed Capacity E=uiDment means items of Lis~urne E~ipment which have a fixed, specific, mechanical, or physical capacity, suct~ as vertical support members and resez-ve pits, excluding items which have a variable capacity, such as flowfines, whose capacity can vary wit-h tempera=uts and pressure, and fluid composition. Greater Pt. McInt?r9 Area means the lands within the State of Alaska oil and gas lease~ outlined in Exhibit 53-A and reservoirs wholly or partially within such lands. The Lisburne Owners may, from time to time, expand or con=tact the Grea=er Pt. McIntyre Area if they 108 THIRD AMENDMENT TO PBU OPERATING AGREEMENT LISBURNE SPECIAL SUPPLEMENTAL PROVISIONS PAGE 2. mutually agree that tecnnical and economic factors warrant a redefinition of the Greater Pt. McIntyre Area. Hydrocarbon Fluids means unrefined liquid hydrocarDons including gas liquids, that are produced through t/%e Lisburne. Production Center and t_hen discharged in a liquid phase to a point of custody transfer. Peak Annual PrTduc=ion means the largest volume of Hydrocarbon Fluids produced and allocated over one calendar year period from a Sharing Participating Area. Each Sharing Participating Area's Peak Annual Produc=ion shall be determined by comparing each current year's total annual production of Hydrocarbon Fluids allocated to that Sharing Participating Area to all prior calendar year's, commencing on the date of the start of Sustained Commercial Production from that Sharing Participating Area and continuing on its anniversary date thereafter for 15 years. The largest annual volume thereafter shall be the Peak Annual Production until replaced by a larger annual volume. Sharin~ Par~iciDatin~ Area means a non-LPA Unit Operation, other than r_he Initial Participating Areas, THIRD AMENDMENT TO PBU OPERATING AGREEMENT LISBURNE SPECIAL SUPP?.F~fENTAL PROVISIONS PAGE 3. 109 within the Grea=er Pt. McIntyre Area, which shares Lis~urne Equipment pursuant to this Ar=icle 53. Source Water means STP wa=er pressured a= the ESIP or WSIP to average conditions of filtering and pressure, for t~e purpose of injec=ion into t. he Prudhoe Bay (Permo- Triassic) Reservoir (PBUOA § 26.002). Sustained'~Q~ercial Production means the firs= calendar day wit.~ 24 hours of continuous, uninterrupted production, other than test production, of Unitized Su~s:ances from a Sharing Par~ioipa=ing Area throug~ permanen= fa¢ili=ies and delivered t. hrough a flow lane to t. he Lisburne Production Center. 2. Amendment of Subs~ions 49.05 ¢ fi and (=~ 2.1 S%~section 49.0§¢f~ Subsection 49.05(f) is deleted in its entirety and re~laced with t-he following: 49.05(f) Sharing wi~h Sharing Par~iciDatin= Areas. Sharing of Lisburne Equipment by a Sharing Par~icipa=ing Area shall require approval by THIRD AMENDMENT TO PBU OPERATING AGREEMENT LISBURNE SPECIAL SUPP~.F~]~NTAL PROVISIONS PAGE 4. 110 90% of the Lisburne Voting interesus, which approval shall not be unreasonably wztP~eld. 2.2 Subsec=icn 49,05(q) Subsection 49.05 (g) is deleted in its entirety and replaced with the following: (g) Initial Participating Areas Sharing of Lis~urne Equipment (Subsection 53.01.03) . 3. Amendment .of Ar~ic!e 53 Article 53 is deleted in its entirety and replaced with the following: 53.01 Votinq pro¥isions. The following subsections set forth the voting provisions for sharing of Lisburne Equipment. 53.01.01 F_Q~-Unit ShariD~ of Lisburne E~uiDment. Non-Unit sharing of Lisburne Equipment shall .. require approval by 100% of the Lisburne Voting Interests entitled to vote; provided, however, this requirement is not intended nor shall it be construed to set any precedent for THIRD AMENDMENT TO PBU OPERATING AGREEMENT LISBURNE SPECIAL SUPP~AL PROVISIONS PAGE 5. iii t_he voting level required for non-Unit snaring of Unit Equipment or_her than Lim~urne Equip- men=. By so agreeing, r_he Pat'.les do no= waive any position taken as to the voting level required for non-unit sharing of equip- men= in any other Par~icipating Area or uni=. 53.01.02 Sharing with Shat±n= Particiuatin~ Area~. Sharing of Lisburne Equipment by a Sharing Par=icipa=ing Area under the =erms and condi- tions of Sec=ion 53.02 shall require approval by 90% of t. he Lisburne Voting In=ares=s, w~ich approval shall no= be unreasonably withheld. 53.01.03 Initial particiDatin= Areas Shari~ .,Q~ Lis- hume. ~auiument. Sharing of Lisburne Equip- ment by the I~itial Par=icip~ting Areas shall require approval by 90% of the Lisburne Voting Interest. 53.02 Terms and Conditions for Shari~a Lisburne E~uinment with Sharina Par~iciDatina Areas. Subject =o ~xe voting provisions of Sec=ion 53.01, t_he Lisburne Owners agree to share Lisburne Equipment in exis- THIRD AMENDMENT TO PBU OPERATING AGREE~-NT LISBURNE SPECIAL SUPPT~~AL PROVISIONS PAGE 6. tence as of January 17, 1992, and as expanded pursuant to Section 53.03, wi~h Sharing Parnlcipa=- lng Areas on the following terms and conditions: (a) The Sharing Par=icipa=ing Area will pay the Lisburne Owners $2.00 per barrel of its allo- cated Hydrocarbon Fluids processed through the Lisburne Production Center for the processing of its Unitized Substances ("LPC User Fee"). The LPC User Fee is inclusive of all costs in- cur:red by the Lisburne Owners under Sec=ion 53.03 and the use of all existing Lisburne Equipment, except as provided in subsection 53.02 (h). (b) The Sharing Participating Area will pay a proportionat~ share of Operating & Maintenance Costs, major repairs, direct and indirect allocations, ad valorem taxes, and FRO ("Oper- ating Costs") of the Lisburne Equipment used, based on its allocated share of total annual oil, water, and gas (6000 scl - 1 barrel), based on well tests, processed through the Lisburne Production Center (Sample Calculation THIRD AMENDMENT TO PBU OPERATING AGREEMENT LISBURNE SPECIAL SUPP~.~ENTAL PROVISIONS PAGE 7. 113 attached as Exhibit ~3-B). Operat!ng Costs are not offset by the LPC User Fee. (c) The Sharing Par=icipa=ing Area will provide in kind its proportionate share of the fuel gas utilized for the Llsburne Equipment based on its proportionate share of produced formation gas based on well tests. (d) The Sharing Paz-aicipating Area will pay a proppr=ionate share of the abandonment costs of the Lisburne Equipment used, based on its allocated share of cumulative oil, water, and gas (6000scl = 1 barrel), based on well processed through the Lisburne Production Center. (a) The Sharing Par~icipa:ing Area will pay Lisburne Owners $0.17 per barrel ("STP User FeeH) of Source Water commencing with the date of first utilization for 15 years and a pro- poz-Cionate share of Operating Costs, and abandonment costs for Source Water facilities utilized by such Sharing Participating Area, 114 THIRD AMENDM~ TO PBU OPERATING AGREEMENT LISBURNE SPECIAL SUPPT.F~AL PROVISIONS PAGE 8. which is obtained by the Lls~urne Owners from the Oil Rim Participating Area. The Operauing Costs will no~ be offse~ by the STP User Fee. (f) The LPC User Fee set forth in Subsection 53.02(a) will apply to each Sharing Partici- pating Area for fifteen (15) years ("Fee Term") from the date of first Sustained Com- mercial Production through the LPC for all calendar years when annual production is grea~er than 15% of Peak Annual Produc~ion. If the annual production from that Sharing Participating Area increases to a level a~ove fifteen (15%) of Peak Annual Production during any year, within t_he Fee Term, the Sharing Participating Area will retroactively pay the LPC User Fe~ for such year. (g) If a Sharing Participating Area utilizes Fixed Capacity Equipment, the Sharing Participating Area will be required to agree to replace the capacity it utilizes in the Fixed Capacity Equipment in the event that the Lisburne THIRD AMENDMI~NT TO PBU OPERATING AGREEMENT LISBURNE SPECIAL SUPP~AL PROVISIONS PAGE 9. 115 O~ners, in their sole discretion, require such capacity for Lisburne Operauions. (h) Ail Lisburne Equipment is avai!a~le for shar- ing except the flowline between DS-L5 and DS- L3 and the gas lift line to DS-L5. (i) The LPA and each Sharing Participating Area has the right of first priority to its allo- cated share of Unitized Substances and retains the obligation to take or dispose of its allocated share of Unitized Substances. 53.03 The Lisburne Owners approve the engineering, de- sign, and constzq/ction of modifications and expan- sions to the LPC, to the LPC inlet manifold, LPC produced water handling system.to increase fluid handling capacity up to 200,000 bbls/day, and the Source Water line from the ESIP to the LPC, which are planned as of January 17, 1992. 53.04 Shared Use o4 LPC, The Lisburne Operator shall have the responsibility and the right to operate the LPC such that total Hydrocarbon Fluids THIRD AMENDMENT TO PBU OPERATING AGREEMENT LISBURNE SPECIAL SUPPLEMENTAL PROVISIONS PAGE !0. througnpu~ is maximized and' prcduculcn is optimized from nigh efficiency wells based cn cas- oil ratio (GOR) or water-oil ratio (WOR) ranking regardless of 'whether production originaues =rom the LPA or Sharing Pa~-~icipating Areas. The Lisburne Operator shall use its best efforts in conjunction with well tests routinely required for State reporting requirements to choke back or shut in wells with the highest GOR or WOR, depending on which facility capacity is exceeded, unsi! the capacity of the LPC is fully utilized under the .. terms of this Ar~icte 53. 53.05 Entitled ShauiDq ParticimatiDq Areas. Subject to the terms and conditions of this Section 53.05, the Lisburne Owners agree to provide Gas Capacity Entitlements to the Niakuk Participating Area, West Beach Participating Area, and North Prudhoe Bay State Participating Area, regardless of the name actually given the Participating Area eventually approved in the locations which are known by these names as of January 17, 1992 ("Entitled Sharing Participating Areas"). A Gas Capacity Entitlement, when invoked, insures the THIRD AMENDMENT TO PBU OPERATING AGREEMENT LISBLrRNE SPECIAL SUPPLEMENTAL PROVISIONS PAGE 11. Entitled Sharlng Par-.ici_ma=ing Area a mlnimum allocation of gas handling capacit-; in the Lis~urne Production Can=er. 53.05.01 ~as ~aDacitv Enti=!ement~ At commencement of Sustained Commercial Production from an Entitled Sharing Participating Area and on each annual anniversary thereafter, regardless of wher/~er the Gas Capacity Entitlement has been invoked, the Gas ..- Capacity En=itlemen= shall be determined by multiplying eighty percent (0.8) by the ratio whose numerator is =he Entitled Sharing Par~icipating Area's Initial Reserves, as set foz-=h in Exhibit 53-C, less the ac=ual cumula=ive allocated HydrocarBon Fluids reserves produced to said date ("Remaining Reserve Balance") from the Entitled Sharing Par=icipating Area and whose denominator is the sum of the LPA and all Sharing Par- ticipating Areas' Initial Reserves, as set foz-~h in Exhibit 53-C, less the total ac=ual cumulative allocated Hydrocarbon Fluids reserves produced to date (see Exhibit 53-C). THIRD AMEND.~[ENT TO PBU OPERATING AGREEMENT LISBURNE SPECIAL SUPP~AL PROVISIONS PAGE 12. In the even~ tha~ the Remainin~ Reserve Balance of an Entitled Sharing Pa~ici~a~lng Area is less than zero, ~he balance sna!l be set to zero and there shall be no further Gas Capacity Entitlement for that Entitled Sharing Participating Area. For purposes of this Section, the LPA reserve base and actual cumulative allocated Hydrocarbon Fluids reserves produced will be deemed to commence August 31, 1993. Ail LPC gas capacity which is nat allocated to Entitled Sharing Partic- ipating Areas will be allocated based on GOR ranking regardless of whether the production originates from the LPA or Sharing Par~icipating Areas. 53.05.02 !nvg~in= Gas Capacity Entitlement. Any Enti- tled Sharing Participating Area Owner owning at least a 20% Lisburne Voting Interest ("Invoking Owner") may invoke the Gas Capacity Entitlement for the Entitled Sharing Participating Area in which it has an ownership interes~ if the following conditions are met: THIRD AMEND~ TO PBU OPERATING AGREEMENT LISBURNE SPECIAL SUPP~.R~.NTAL PROVISIONS PAGE 13. (a) the Entitled Par~icipatlng Area ~s at leas~ 50% owned by a Lisburne O'wner or Lis~urne Owners collectively; (b) ~he Invoking Owner is able uo demon- strate that invoking the Gas Capacity Entitlement will increase Hydrocarbon Fluids production a minimum of five percent (5%) from the Entitled Sharing Paz~icipating Area; (c) at least one year has elapsed since the .date of withdrawal or termination of a previous invocation of the Gas Capacity Entitlement for the Entitled Par~i=ipating Area; and (d) the Entitled Sharing Participating Area has demonstra=ed well test capacity de- livers~le to. the LPC to fully utilize its' Gas Capacity Entitlement. Well res= capacity will be demonstrated by well tests a= existing drillsite operating conditions as routinely obtained for State reporting purposes. Any well which produces above 10,000 SCF/STBO will not be included in the THIRD AMENDMENT TO PBU OPERATING AGREEME}~T LISBURNE SPECIAL SUPPT,~AL PROVISIONS PAGE 14. determination of demonstrated ~es~ capacity. The invocation nus~ be in wri~inc ~s the Lisburne Owners and will become effective at 12:01 a.m. Alaska zime, the first day of the month following receipt of the notice by the Ltsburne Operator. 53.05.03 Withdrawal o~ Gas Capacity E~%itleme~t. The Invoking Owner will have the right to withdraw its request for the Gas Capacity Entitlement at any time by written notice to the Lisburne Owners. Such withdrawal will become effective at 12:01 a.m. Alaska time the first day of the month following receipt of the notice by the Lisburne Operator. 53.05.04 Automatic Termination Q~ Ga~ caDacitv Entitlement, On or before each annual anniversary date of the invoking of the Gas Capacity Entitlement for an Entitled Sharing Participating Area, the Invoking Owner must demonstrate that the allocation of the Gas Capacity Entitlement to the Entitled Sharing THIRD AMENDMENT TO PBU OPF~RATING AGREEM25NT LISBURNE SPECIAL SUPPI~NTAL PROVISIONS PAGE 15. Participating Area will increase Hydrccarmon Fluids production a minimum of five percent (5%) for =he succeeding year or the Gas Capacity Entitlement will be automatically terminated. 53.05.05 ~alancin=. Each time that a Gas Capacity Entitlement is invoked, t_he Lis~urne Operator will maintain a cumulative account of actual gas produced by the Entitled Sharing Participating Area beginning on the date of invocation ("Utilized Capacity") and a cumulative account of the Gas Capacity Entitlement ("Entitled Capacity"). In the even= that the Utilized Capacity of an Entitled Sharing Participating Area differs from the Entktled Capacity by a volume which is greater than five percent (5%) of the annual Gas Capacity Entitlement for the Entitled Sharing Participating Area, the Gas Capacity Entitlement of that Entitled Sharing Participating Area will be adjusted in conjunction with Uhe annual redetermination of the Gas Capacity Entitlement to equalize THIRD AKEN~ TO PBU OPERATING AGREEHENT LISBURNE SPECIAL SUPPLEMENTAL PROVISIONS PAGE 16. t22 the Utilized Capacity to the Encitled Capaci- ty over the following year. Such balancing shall terminate upon withdrawal of invocation as provided in Subsection 53.05.02 and uDon automatic termination of invocation as provided in Subsection 53.05.04. 53.05.06 Maximum Produc=ionCaDs. Notwithstanding the other provisions of this Section 53.05, the Lisburne Operator will use its best efforts to ensure that an Entitled Sharing Participating Area shall no= be allowed to produce in excess of the annual average maxi- mum rates set out in Exhibit 53-D, unless the Lisburne Operator at its discretion determines that excess LPC capacity exists, in which event the Maximum Production Caps shall not apply. As the Maximum Production' Caps are an annual average~ the Lisburne Operator will determine whether the Maximum Production Caps have been exceeded on each annual anniversary from the commencement of Sustained Commercial Production from an Entitled Sharing Participating Area. In the THIRD AMEND~ TO PBU OPERATING AGREEMENT LISBURNE SPECIAL SUPP~.F~F. NTAL PROVISIONS PAGE 17. 123 even~ tha~ the Maximum Production Caps have been exceeded, the Lis~urne Opera=ur will adjus~ producnion over the following year to recover the over production from the Entitled Sharing Participating Area. There shall be no maximum production cap for the LPA or the Pt. McIntyre Participating Area. 53.05.07 Additional Entitled Sharing ParriciDe=in= -- Ar~CA~. The Gas Capacity Entitlement and .~ ... Maximum Production Caps, if any, for additional Entitled Sharing Par~icipaCing Areas will be approved as par~ of the approval of the Sharing Participating Area under Section 53.01.02. ~3.05.08 AdPustments to Maximum Productio~ C~DS an~ Gas Capacity Entitlement. In the event of a Force Majeure or significant operational downtime, ~he Maximum Production Caps and invoked Gas Capacity Entitlements will be adjusted in proportion to the percent of reduction in LPC capacity. THIRD AM~ND~ TO PBU OPERATING AGREEMENT LISBURNE SPECIAL SUPPLEMENTAL PROVISIONS PAGE 18. 124 53.05.09 Du:ies of LisDurne 0peri,or. The Lisnurne Owners specifically acknowledge ~ha~ ~he provisions of PBUOA Article !0 apply Jo ~he Lisburne Operator with respect to its duties under Section 53.04 and 53.05. 4. Amendment of Artic!e 59 Article 59 is amended by t~e addition of the following Sec=ion 59.06: 59.06 Severabilitv. In the event that any provision or clause of the Lisburne Provisions is inconsistent with any State of Alaska statute, regulation, or valid administrative order, that provision shall be deemed invalid, but such invalidity shall not affect any otheF provisions Of the Lisburne Provisions. The Lisburne Owners will enter into good faith negotiations to redraft the provision or clause tha= is inconsistent in order to make the provision or clause consistent with the statute, regulation, or administrative order. THIRD AMENDMENT TO PBU OPERATING AGRE~-HENT LISBURNE SPECIAL SUPPLEMENTAL PROVISIONS PAGE 19. 125 ~lloca~o~ ~et~o~oloc~ · · · · · · Conduc= monthly well =as=s to de=ermine production raues for each well· Calculate each well's t. heore=ical monr/%ly production by co~ining monthly well res: rate and ac=ual time ~he well was on production. Sum the t. heore=ical monthly production volume for all wells in all Sharing Par~icipa=ing Areas· Compare =he sum of theoretical monthly production volumes for all wells =o t/~e total sales oil volume as determined by the LACTme:er. Adjust each well theoretical mon~.~ly production volume by an allocation fac=or which is calculated from: Alloca=ion Fac=or Total Sales Oil Volume Sum of Theoretical Production Vol%~mes for Ail Wells Calculate each well's ac=ual monthly production volume as: Ac=ual Production Volume Theoretical Production Volume X Alloca=ion Fac=or Sum actual production volumes for each we}l in each Sharing Par=icipa=ing Area to determine the amount of production derived from eac~ Sharing ParCicipating Area. EXHIBIT 53B Apl ~AI'ER MclNI'YRE ,edit GREAIEFI PT. MclN'I"YIIE AREA 95 MHBO 330 M~BO 50 MMBO 24 MHBO Gas h~n=i=lamoAC ~-c~/aCion: Z RUR,~ PA where-. if: Pi> R, ~.hmn: E:Lu 0 Parciciua=in= Area Maximum Annual Average Rates Oil* Total Fluids* Gas ~ ~ ~M~SCF/~ NiakuX 30 West Beach, Nor=~ Pruchhoe 15 Bay State *values exclude Natural Gas Liquids 40 80 20 4O 129 PT. McINTYRE SPECIAL SUPPLEMENTAL PROVISIONS TO UNIT OPERATING AGREEMENT MARCH 1, 1993 PT. McINTYRE PARTICIPATING AREA PRUDHOE BAY UNIT STATE OF ALASKA ^laska Oit & Gas Cons. :t30 ATTACHMENT II Pt. McIntyre Provisions (March 1, 1993) TABLE OF CONTENTS Section Paqe ART I CLE 75 DEFINITIONS 75.01 Definitions ..................... 3 ARTICLE 76 ESTABLISHMENT OF PT. McINTYRE PARTICIPATING AREA (PMPA); 76.01 76.02 76.03 76.04 76.05 76.06 76.07 76.08 76.09 SCOPE OF PT. MCINTYRE PROVISIONS; EXHIBITS TO PT. MCINTYRE PROVISIONS Establishment of Pt. McIntyre Participating Area (PMPA) .................... 10 Description of the PMPA .............. 10 Plan of Development and Operation for the PMPA . . 10 Scope of Pt. McIntyre Provisions ......... 10 Authority in Case of Conflict ........... 11 Tax Partnership .................. 11 Agreements Ratified and/or Superseded ....... 11 Exhibits ..................... 12 Conflict Between Exhibits and the Body of the Pt. McIntyre Provisions ............. 12 77.01 77.02 ARTICLE 77 PT. McINTYRE OPERATOR General ..................... 13 Designation of Pt. McIntyre Operator ....... 13 '18 1 Pt. McIntyre Provisions (March 1, 1993) Section 77.03 77.04 77.05 77.06 77.07 77.08 77.09 Paqe Exclusive Right to Operate ............ 13 Rights and Obligations of Pt. McIntyre Operator . . 13 Resignation and Termination ............ 13 Removal ...................... 14 Effective Date of Resignation or Removal ..... 14 Selection of Successor Pt. McIntyre Operator . . . 14 Assumption of Duties by Successor ......... 15 78.01 78.02 78.03 78.04 ARTICLE 78 PT. McINTYRE PARTICIPATIONS, PT. McINTYRE TRACT PARTICIPATIONS AND PT. McINTYRE VOTING INTERESTS Pt. McIntyre Participations ............ 16 Pt. McIntyre Tract Participations ......... 16 Pt. McIntyre Voting Interests ........... 16 No Redetermination of Pt. McIntyre Participation and Pt. McIntyre Tract Participations ....... 16 79.01 79.02 79.03 79.04 79.05 79.06 ARTICLE 79 SUPERVISION OF OPERATIONS BY PT. McINTYRE OWNERS Formation of Pt. McIntyre Owners Committee .... 17 Chairmanship of the Pt. McIntyre Owners Committee . 17 Secretary ..................... 17 General Meetings .. ................ 18 Special Meetings ................. 18 Emergency Meetings ................ 19 -ii- Pt. McIntyre Provisions (March 1, 1993) Section 79.07 79.08 p.aqe Greater Pt. McIntyre Planning Subcommittee .... 19 Subsurface Development Team (SDT) ......... 19 ARTICLE 80 VOTING PROVISIONS FOR THE PMPA 80.01 General Principles Governing Voting ........ 20 80.02 : Action Through the Pt. McIntyre Owners Committee . 20 80.03 80.04 80.05 80.06 80.07 Action Without a Meeting ............. 21 Matters Requiring 51% Affirmative Vote ...... 21 Matters Requiring 90% Affirmative Vote ...... 21 Matters Requiring 100% Affirmative Vote ...... 23 General Unit Matters ............... 23 81.01 81.02 81.03 81.04 ARTICLE 81 APPROVALS, BUDGETS, AND EXPENDITURES General ...................... 24 Pt. McIntyre Reservoir Development Objectives and Depletion Plan .................. 24 Pt. McIntyre Five-Year Plan ............ 24 Budgets ...................... 24 81.04.01 Budget Format .............. 25 81.04.02 Budget Timing and Period Covered by Budgets ................. 25 81.04.03 Budget Approval ............. 25 81.04.04 Capital Budgets ............. 26 -iii- Pt. McIntyre Provisions (March 1, 1993) Section Paqe 81.04.05 Expense Budgets ............. 27 81.05 Pt. McIntyre Master Commitment Authorization (PMMCA) ...................... 28 81.06' Authorization for Expenditure ........... 28 81.06.01 Operator Expenditure Authority ..... 29 81.06.02 Capital AFE ............... 30 81.06.03 Expense AFE ............... 30 81.06.04 AFE Overrun Limit ............ 30 81.06.05 AFE Underrun .............. 31 81.06.06 Budget Status Report .......... 31 81.06.07 AFE Revision .............. 31 81.06.08 AFE Content ............... 32 81.06.09 Non-Operator Costs ........... 32 81.06.10 Subcomponent AFEs ............ 33 Facility Sharing Fees ............... 33 81.07 82.01 82.02 82.03 82.04 82.05 ARTICLE 82 ALLOCATION AND EQUALIZATION OF PT. McINTYRE SUBSTANCES AND EXPENDITURES Allocation of Pt. McIntyre Substances and Expenditures to Pt.. McIntyre Owners ........ 34 Equalization of Pt. McIntyre Expenditures ..... 34 Taking Hydrocarbon Fluids in Kind ......... 34 Taking Gas in Kind ................ 35 Allocation of Fuel Supply Obligations ....... 35 -iv- Pt. McIntyre Provisions (March 1, 1993) Section 82.06 82.07 82.08 82.09 82.10 82.11 82.12 82.13 82.14 82.15 Page Separate Facilities for Taking in Kind or for Substituting Fuel ................. 36 Estimate of Deliverable Hydrocarbon Fluids .... 37 Units of Measurement ............... 37 Coordination of Offtake and Responsibility.for Metering Pt. McIntyre Substances ......... 38 Point of Taking .................. 38 Condition at Taking ................ 38 Gas Injection ................... 39 Gas Reserve Debits Record ............. 39 Equalization of Hydrocarbon Fluid Production . . . 40 Procedure for Adjustment of Offtake to Pipeline Capacity ................. 40 82.15.01 Notification of Pipeline Space ..... 40 82.15.02 Recalculation of Production Level .... 40 82.15.03 Recoupment of Unplaced Offtake and Adjustment of Overplaced Offtake .... 41 82.15.04 Balancing of Production ......... 42 82.15.05 Good Faith Tenders Requirement ..... 42 82.15.06 Time Limits ............... 42 83.01 83.02 83.03 ARTICLE 83 SHARING OF EQUIPMENT Non-Unit Sharing of Pt. McIntyre Equipment .... 43 Unit Sharing of Pt. McIntyre Equipment ...... 43 Sharing of Non-Pt. McIntyre Equipment ....... 43 -v- 135 Pt. McIntyre Provisions (March 1, 1993) Section Page 84.01 84.02 84.03 84.04 84.05 ARTICLE 84 DISPOSITION AND RETIREMENT OF PT. McINTYRE EQUIPMENT; ALLOCATION OF PROCEEDS; ALLOCATION OF ABANDONMENT AND CLEAN-UP COSTS General ...................... 44 Voting Provisions ................. 44 Notification ................... 44 Cost of Abandonment ................ 44 Distribution of Assets .............. 45 85.01 ARTICLE 85 SETTLEMENT OF CLAIMS OR SUITS Settlement of Claims or Suits ........... 46 85.01.01 Damage Claims .............. 46 85.01.02 Penalty Claims ............. 46 86.01 86.02 86.03 86.04 ARTICLE 86 CHANGE OF BOUNDARIES OF THE PMPA Expansion of the PMPA ............... 47 Contraction .................... 47 Combining the PMPA with Other Participating Areas ....................... 47 Voting Adjusted ................. 47 136 -vi- Pt. McIntyre Provisions (March 1, 1993) Section ARTICLE 87 paqe 87.01 TERMINATION OF PMPA Termination of the PMPA .............. 48 ARTICLE 88 88.01 PMPA EFFECTIVE DATE AND TERM PMPA Effective Date ................ 49 88.02 88.03 Term ....................... 49 Effect of Termination ............... 49 ARTICLE 89 89.01 89.02 89.03 89.04 89.05 EXECUTION, EFFECT AND AMENDMENT Original, Counterpart or Other Instrument ..... 50 Successors and Assigns .............. 50 Amendment ..................... 50 Benefits of Agreement Restricted to Parties .... 50 Entirety of Agreement ............... 50 -vii- Exhibit 75-A Exhibit 76-A Exhibit 76-B Exhibit 76-C Exhibit 76-D Exhibit 76-E Exhibit 78-A Exhibit 81-A Exhibit 81-B Exhibit 82-A SUMMARY OF EXHIBITS Greater Pt. McIntyre Area Boundaries of PMPA Tracts within the PMPA and Pt. McIntyre Tract Participations Logs Denoting Pt. McIntyre Reservoir, Pt. McIntyre #11 and Pt. McIntyre #8 and Stump Island Reservoir, Pt. McIntyre #3 Plan of Development and Operations for the PMPA Agreements Ratified and/or Superseded Pt. McIntyre Participation and Pt. McIntyre Voting Interest of the Pt. McIntyre Owners Pt. McIntyre Reservoir Development Objectives and Depletion Plan Indexing of Operator Expenditure Authority Sample Calculation of Effective Heating Value Adjustment for Fuel Substitution 135 -viii- Pt. McIntyre Provisions (March 1, 1993) PT. McINTYRE SPECIAL, SUPPLEMENTAL PROVISIONS TO UNIT OPERATING AGREEMENT PRUDHOE BAY UNIT STATE OF ALASKA THIS AGREEMENT ("Pt. McIntyre Provisions"), entered into as of March 1, 1993 by and between ARCO Alaska, Inc. ("ARCO"), BP Exploration (Alaska) Inc. ("BPX") and Exxon Corporation ("Exxon"), hereinafter referred to as the "Pt. McIntyre Owners." W I TNE S SETH: WHEREAS, the Prudhoe Bay Unit Operating Agreement ("Unit Operating Agreement") and the Prudhoe Bay Unit Agreement ("Unit Agreement") were entered into effective April 1, 1977; WHEREAS, Articles 1 through 25 of the Unit Operating Agreement are referred to as "General Provisions," applicable to all Unit Operations undertaken within the Prudhoe Bay Unit; WHEREAS, Articles 2'6 through 43 of the Unit Operating Agreement are referred to as "Special, Supplemental Provisions" relating to the Initial Participating Areas; WHEREAS, Articles 44 through 59, as amended, of the Unit Operating Agreement are referred to as "Lisburne Special Supple- mental Provisions to Unit Operating Agreement" or, simply, the "Lisburne Provisions"; WHEREAS, Articles 60 through 74 of the Unit Operating Agreement are referred to as the "West Beach Special Supplemental Provisions to Unit Operating Agreement" or, simply, the "West Beach Provisions"; WHEREAS, Article 21 of the Unit Operating Agreement and Article 5 of the Unit Agreement provide for the formation of additional Participating Areas within the Prudhoe Bay Unit; WHEREAS, the Pt. McIntyre Owners have agreed to expand the Prudhoe. Bay Unit and to form the Pt. McIntyre Participating Area ("PMPA") pursuant to Article 21 of the Unit Operating Agreement and Article 5 of the Unit Agreement; and WHEREAS, the Pt. McIntyre Owners are required by Article 21 of the Unit Operating Agreement to enter into an agree- -1- Pt. McIntyre Provisions (March I, 1993) ment adopting Special, Supplemental Provisions to include all terms necessary and advisable for Pt. McIntyre Operations; NOW, THEREFORE, in consideration of the mutual agreements herein set forth, it is agreed as follows: -2- ].40 Pt. McIntyre Provisions (March 1, 1993) 75.01 ARTICLE 75 DEFINITIONS Definitions. Those terms which have the initial letter(s) of the word(s) capitalized and which are not specifically defined herein will have the meaning given in Article 2 of the General Provisions. Unless the context clearly requires otherwise, as used in the Pt. McIntyre Provisions: Authorization for Expenditure (AFE) means the written authorization to commit or expend funds. AFE procedures for the PMPA are provided in Section 81.06. Budget means a document that sets forth the overall scope, timing, and expenditure limits associated with the Pt. McIntyre Five-Year Plan and approved Pt. McIntyre Master Commitment Authorizations for the Budget Year. The Budget shall include a Capital Budget and an Expense Budget. Budqet Year means the first calendar year included in each annual Budget in which expenditures are projected by calendar quarters. Capital AFE means an AFE that is prepared for any Investment Expenditure. Capital AFE procedures for the PMPA are provided in Subsection 81.06.02. Capital Budget means a listing of the Investment Expendi- tures associated with the Pt. McIntyre Five-Year Plan. Capital Budget procedures for the PMPA are provided in Subsection 81.04.04. Chairman means the representative of the Pt. McIntyre Operator on the Pt. McIntyre Owners Committee pursuant to Section 79.02. Commissioner means the Commissioner (or duly authorized representative) of the Department of Natural Resources, or of any successor agency of comparable jurisdiction. Expense AFE means an AFE prepared for non-capital expenditures such as repair or replacement, studies and workovers. Expense AFE procedures for the PMPA are provided in Subsection 81.06.03. -3- Pt. McIntyre Provisions (March 1, 1993) Expense Budget means that Budget containing well work, overhead, ad valorem taxes, facility sharing fees, major repairs, field specific study cost and other expenses. Expense Budget procedures for the PMPA are provided in Subsection 81.04.05. Final Equity means the fixed and final ratios expressed as a single percentage for cost sharing and production sharing among the parties to the Pt. McIntyre Agreement for the Pt. McIntyre Participating Area as will be determined pursuant to the Pt. McIntyre Agreement. Gas means hydrocarbon and non-hydrocarbon natural gas, except Hydrocarbon Fluids, that is produced from a Reservoir in the Pt. McIntyre Participating Area and then consumed, injected in the course of Pt. McIntyre Opera- tions, flared, vented, unavoidably lost or discharged in a gaseous phase to a point of custody transfer. General Provisions mean Articles 1 through 25 and Exhibits A through K of the Unit Operating Agreement, as amended or supplemented from time to time. Greater Pt. McIntyre Planning Subcommittee (GPMPSC) means the joint committee of the Pt. McIntyre Owners Committee and the Lisburne Owners Committee constituted pursuant to Section 79.07. Greater Pt. McIntyre Area means the lands within the State of Alaska oil and gas leases outlined in Exhibit 75-A and reservoirs wholly or partially within such lands. The Lisburne Owners may, from time to time, expand or contract the Greater Pt. McIntyre Area if they mutually agree that technical and economic factors warrant a redefinition of Greater Pt. McIntyre Area. Hydrocarbon Fluids means unrefined liquid hydrocarbons, including gas liquids, that are unavoidably lost, consumed or injected in Pt. McIntyre Operations or produced from the PMPA and through the Lisburne production center and then discharged in a liquid phase to a point of custody transfer. Intangible Costs mean those Investment Expenditures for items possessing no salvage value, incident to and necessary for'the drilling and preparation of wells. 142 -4- Pt. McIntyre Provisions (March 1, 1993) Investment Expenditures mean the Tangible Costs associ- ated with equipment and facilities and Intangible Costs, including gravel related costs. IPA/LPA Facility Sharinq Agreement means that certain agreement entered into among the parties effective October 15, 1985, as amended or superseded, regarding the sharing of certain IPA Equipment by the LPA. Lisburne Equipment means Unit Equipment owned by or allocated to the Lisburne Owners for use in Lisburne Operations. Lisburne Operations means Unit Operations conducted for the Lisburne Participating Area (LPA). Lisburne Operator means the Lisburne Owner designated by the Lisburne Owners pursuant to Article 46 of the Lisburne Provisions to conduct Lisburne Operations, acting as operator and not as a Lisburne Owner. The rights and obligations of Unit Operator as specified in the General Provisions are assumed by the Lisburne Operator to the extent applicable to Lisburne Operations. Lisburne Owner means a Working Interest Owner that owns a Working Interest in the LPA. Lisburne Owners Committee means the committee of Lisburne Owners that is constituted pursuant to Section 48.02 of the Lisburne Provisions. Lisburne Production Facilities mean the Lisburne produc- tion center (LPC), including LPA water disposal, LPA drill sites, LPA production flowlines and vertical support members from the drill sites to the LPC, power distribution system in direct support of production, the oil sales line from LPC to TAPS Pump Station #1, and associated equipment. Lisburne Provisions mean the Special, Supplemental Provisions for the LPA, which are Articles 44 through 59 and Exhibits 45-A through 52-8 of the Unit Operating Agreement. Minor Capital Investment (MCI) means the Capital Budget category which includes those items that are within Operator Expenditure Authority and are projected on a 143 -5- Pt. McIntyre Provisions (March 1, 1993) historical basis and not specifically identified at the time of Capital Budget preparation. Operatinq and Maintenance Costs (O & M Costs) mean Pt. McIntyre expense incurred in normal ongoing operating and maintenance activities. Operator Expenditure Authority means the expenditure limitation of the Pt. McIntyre Operator for the PMPA, as provided in Subsection 81.06.01. Plan of Development and Operation means the document set forth in Exhibit 76-D as modified from time to time in accordance with Section 4.2 of the Unit Agreement and Section 76.03 of the Pt. McIntyre Provisions. Pt. McIntyre Aqreement means that certain agreement among ARCO, BPX and Exxon entitled "Pt. McIntyre Agreement Regarding Interim Funding, Final Equity Determination and Facility Sharing" effective January 17, 1992. Pt. McIntyre Equipment means Unit Equipment owned by the Pt. McIntyre Owners. Pt. McIntyre Expenditure means all capital, expense, and inventory expenditures, as determined in accordance with Exhibit I of the General Provisions, made by the Pt. McIntyre Owners or the Pt. McIntyre Operator for Pt. McIntyre Operations. Pt. McIntyre Expenditure for the PMPA will include Pre-PMPA Costs, Operating and Main- tenance Costs, Investment Expenditures, overhead, and abandonment and clean-up costs. Pt. McIntyre Five-Year Plan means the plan of the Pt. McIntyre Owners for implementing reservoir management and production strategies over the following five years. The Pt. McIntyre Five-Year Plan is provided for in Section 81.03. Pt. McIntyre Master Commitment Authorization (PMMCA) means the document(s) referred to in Section 81.05. Pt. McIntyre Operations mean Unit Operations conducted for the PMPA. Pt. McIntyre Operator means the Pt. McIntyre Owner desig- nated by the Pt. McIntyre Owners pursuant to Article 77 T44 -6- Pt. McIntyre Provisions (March 1, 1993) of the Pt. McIntyre Provisions to conduct Pt. McIntyre Operations, acting as operator and not as a Pt. McIntyre Owner. The rights and obligations of Unit Operator as specified in the General Provisions are assumed by the Pt. McIntyre Operator to the extent applicable to Pt. McIntyre Operations. Pt. McIntyre Owner means a Working Interest Owner that owns a Working Interest in the PMPA. Pt. McIntyre Owners Committee means the committee of Pt. McIntyre Owners that is constituted pursuant to Section 79.01. Pt. McIntyre Participatinq Area (PMPA) means the Partici- pating Area established for the Pt. McIntyre Reservoir, the Stump Island Reservoir. The PMPA is described in Exhibits 76-A, 76-B and 76-C. Pt. McIntyre Participation of a Pt. McIntyre Owner means the sum of the percentages obtained by multiplying the Working Interest owned by that Pt. McIntyre Owner in each Tract or portion of a Tract included within the PMPA by the Pt. McIntyre Tract Participation of that Tract or portion of a Tract in the PMPA. The Pt. McIntyre Participation of each Pt. McIntyre Owner is set out in Exhibit 78-A. Pt. McIntyre Provisions mean the Special, Supplemental Provisions for the PMPA, which are Articles 75 through 89 and Exhibits 76-A through 82-B of the Unit Operating Agreement. Pt. McIntyre Reservoir means the accumulation of Pt. McIntyre Substances correlating with the stratigraphic interval in the ARCO-Exxon Pt. McIntyre #11 Well between the measured depths of 9908 feet to 10665 feet, as determined by reference to the Schlumberger Dual Induction SFL-GR Log, dated March 28, 1991, and in the ARCO-Exxon Pt. McIntyre #8 Well between the measured depths of 10084 feet and 10877 feet, as determined by reference to the Schlumberger Dual Laterolog-SFL-GR Log, dated March 7, 1990. A representation of these logs is shown in Exhibit 76-C. For the purposes of the Pt. McIntyre Provisions, the Pt. McIntyre Reservoir shall be considered as a separate continuous accumulation even if faults or other discontinuities may divide the Pt. -7- Pt. McIntyre Provisions (March 1, 1993) McIntyre formation within the boundaries of the PMPA into separate reservoir segments. Pt. McIntyre Reservoir Development Objectives and Deple- tion Plan mean the objectives of the development of the Pt. McIntyre Reservoir and SI Reservoir as amended from time to time in accordance with Section 81.02. The Pt. McIntyre Reservoir Development Objectives as of the PMPA Effective Date are set forth in Exhibit 81-A. Pt. McIntyre Substances mean Unitized Substances allo- cated to the PMPA. Pt. McIntyre Tract Participation means the percentage assigned to a Tract or a portion of a Tract within the PMPA for the purpose of allocating Pt. McIntyre Sub- stances and Pt. McIntyre Expenditure. The Pt. McIntyre Tract Participation of each Tract in the PMPA is set out in Exhibit 76-B. Pt. McIntyre Votinq Interest means a Pt. McIntyre Owner's percentage of the total voting rights held by all Pt. McIntyre Owners in the PMPA. The Pt. McIntyre Voting Interests of each Pt. McIntyre Owner shall be equal to its Pt. McIntyre Participation in effect at the time of the vote as shown in Exhibit 78-A. PMPA Effective Date means the date the Pt. McIntyre Provisions become effective as provided in Article 88. Pre-PMPA Costs mean the actual costs, as of July 1, 1993, of those AFEs and other items including overhead applied in accordance with Section 82.02. Secretary means the designee of the Pt. McIntyre Operator in accordance with Section 79.03. Sharinq Participatinq Area means a non-LPA Unit Operation, other than the Initial Participating Areas, within the Greater Pt. McIntyre Area, which shares Lisburne Equipment pursuant to amended PBUOA Article 53. sOurce Water means STP water pressured at the ESIP or WSIP to average conditions of filtering and pressure, for the purpose of injection into the Prudhoe Bay (Permo- Triassic) Reservoir (PBUOA Section 26.002) which for the -8- Pt. McIntyre Provisions (March 1, 1993) purposes of this Agreement may be injected into the Pt. McIntyre and SI Reservoirs. Stump Island Reservoir (SI Reservoir) means the accumu- lation of Pt. McIntyre Substances correlating with the stratigraphic interval in the ARCO-Exxon Pt. McIntyre #3 Well between the measured depths of 8759 feet and 8930 feet, as determined by reference to the Schlumberger Dual Induction-SFL Log Run No. Two dated March 29, 1988. A representation of this log is shown in Exhibit 76-C. Subcomponent AFE means an AFE that is created for cost and financial accounting control of a Pt. McIntyre Expenditure which was previously approved under another AFE. Subcomponent AFE procedures for the PMPA are provided in Subsection 81.06.10. Subsurface Development Team (or SDT) means the team established pursuant to Section 79.08. Support Facilities means the facilities shared by the IPA and LPA as defined by the IPA/LPA Facility Sharing Agreement, as amended or superseded. Tangible Costs mean capital costs for facilities, equip- ment, and tangible well investments. -9- Pt. McIntyre Provisions (March 1, 1993) ARTICLE 76 ESTABLISHMENT OF PT. McINTYRE PARTICIPATING AREA (PMPA); SCOPE OF PT. McINTYRE PROVISIONS; EXHIBITS TO PT. McINTYRE PROVISIONS 76.01 Establishment of Pt. McIntyre Participatinq Area (PMPA). Pursuant to Article 21 of the Unit Operating Agreement and Article 5.3 of the Unit Agreement, the Pt. McIntyre Owners hereby establish the PMPA. 76.02 Description of the PMPA. The boundary of the PMPA is displayed in Exhibit 76-A. A description of the Tracts included in the PMPA, the ownership thereof, and Pt. McIntyre Tract Participations are provided in Exhibit 76-B. Logs depicting the stratigraphic intervals for the Pt. McIntyre Reservoir and the Stump Island Reservoir are represented in Exhibit 76-C. 76.03 Plan of Development and Operation for the PMPA. Pursuant to Section 4.2 of the Unit Agreement and Section 21.003 of the Unit Operating Agreement, the Pt. McIntyre Owners have agreed to a Plan of Development and Operation for the PMPA as provided in Exhibit 76-D. The GPMPSC will coordinate the annual updates and additional Plans of Development and Operation for approval of the Pt. McIntyre Owners and submission to the Commissioner. 76.04 Scope of Pt. McIntyre Provisions. The Pt. McIntyre Owners enter into the Pt. McIntyre Provisions pursuant to Article 21.004 of the Unit Operating Agreement. The Pt. McIntyre Provisions contain the following: (a) Exhibits 76-A and 76-B describing the PMPA and ownership therein; (b) Procedures for decision and action of Pt. McIntyre Owners in exercising supervision over Pt. McIntyre Operations (Articles 79, 80 and 81); (c) Basis and allocation factors for participating in Pt. McIntyre Substances and Pt. McIntyre Expenditure (Articles 78, 82, 83 and 84, and Exhibits 76-B and 78-A); 1.48 -10- Pt. McIntyre Provisions (March 1, 1993) 76.05 76.06 76.07 (d) Provisions dealing with the consequences of the failure of any Pt. McIntyre Owner to take in kind its share of Pt. McIntyre Substances (Article 82); (e) Provisions for the expansion and contraction of the PMPA and for combining the PMPA with other Partici- pating Areas (Article 86); and (f) Procedures for and limitations on terminating the PMPA (Article 87). Authority in Case of Conflict. The Pt. McIntyre Provi- sions: (a) do not supersede the General Provisions of the Unit Operating Agreement and are supplemental and sub- ject to the General Provisions except as noted in Subsection (c) below; and (b) are subject to any inconsistent terms of Article 53 of the Lisburne Provisions; but (c) in all matters affecting only the PMPA, shall govern the rights and obligations of the Pt. McIntyre Owners as among themselves regardless of whether there is any conflict with the General Provisions or the Lisburne Provisions. Tax Partnership. The Pt. McIntyre Owners recognize that the joint operations conducted under the terms of the Pt. McIntyre Provisions are conducted under the terms of and governed by the Prudhoe Bay Unit tax partnership. In the event of a conflict between the terms of Article 12 of the General Provisions and the Pt. McIntyre Provisions, the Pt. McIntyre Owners agree that the terms of Article 12 prevail and govern. Aqreements Ratified and/or Superseded. ARCO, Exxon, and BPX entered into the agreements set out in Exhibit 76-E in their capacity as Working Interest Owners of Operating Tracts and in anticipation of the formation of the PMPA. By their execution of the Pt. McIntyre Provisions, ARCO, Exxon, and BPX ratify these agreements as Pt. McIntyre Owners except to the extent they are inconsistent with the Pt. McIntyre Provisions, in which case they are superseded and replaced by the Pt. McIntyre Provisions or the General Provisions, as appropriate. 149 -11- Pt. McIntyre Provisions (March 1, 1993) 76.08 76.09 Exhibits. The following exhibits are attached hereto and incorporated into the Pt. McIntyre Provisions by refer- ence: Exhibit 75-A - Greater Pt. McIntyre Area Exhibit 76-A - Boundaries of the PMPA Exhibit 76-B Tracts within the PMPA and Pt. McIntyre Tract Participations Exhibit 76-C Logs Denoting Pt. McIntyre Reservoir, Pt. McIntyre #11 and Pt. McIntyre #8 and Stump Island Reservoir, Pt. McIntyre #3 Exhibit 76-D Plan of Development and Operations for the PMPA Exhibit 76-E Agreements Ratified and/or Super- seded Exhibit 78-A Pt. McIn%yre Participation and Pt. McIntyre Voting Interest of the Pt. McIntyre Owners Exhibit 81-A Exhibit 81-B Pt. McIntyre Reservoir Development Objectives and Depletion Plan Indexing of Operator Expenditure Authority Exhibit 82-A Sample Calculation of Effective Heating Value Adjustment for Fuel Substitution Conflict Between Exhibits and the Body of the Pt. McIntyre Provisions. In the event of a conflict between the exhibits listed in Section 76.08 and the body of the Pt. McIntyre Provisions, the body of the Pt. McIntyre Provisions shall govern. J. 50 -12- Pt. McIntyre Provisions (March 1, 1993) 77.01 77.02 77.03 77.04 77.05 ARTICLE 77 PT. McINTYRE OPERATOR General. This Article 77 designates the Pt. McIntyre Operator, sets forth the rights and obligations of the Pt. McIntyre Operator, and provides for the resignation, removal, and replacement of the Pt. McIntyre Operator. Article 77 shall, for Pt. McIntyre Operations only, supersede Article 9 of the General Provisions. In no way shall Article 77 be construed to amend or modify the rights and obligations of the Working Interest Owners and of the Unit Operator in the conduct of Unit Operations other than Pt. McIntyre Operations. Desiqnation of Pt. McIntyre Operator. ARCO is hereby designated by the Pt. McIntyre Owners as the initial Pt. McIntyre Operator. Exclusive Right to Operate. Subject to the Pt. McIntyre Provisions and to instructions from the Pt. McIntyre Owners, the Pt. McIntyre Operator shall have the exclu- sive right and be obligated to conduct Pt. McIntyre Operations on behalf of the Pt. McIntyre Owners. Rights and Obliqations of Pt. McIntyre Operator. The Pt. McIntyre Operator shall assume all existing rights and obligations of the Unit Operator as specified in the General Provisions and the Unit Agreement, to the extent that such provisions are applicable to Pt. McIntyre Operations. Resignation and Termination. Pt. McIntyre Operator may resign at any time. Should the Pt. McIntyre Operator dissolve, liquidate, or terminate its corporate exis- tence, other than through merger, it shall cease to be Pt. McIntyre Operator. If the Pt. McIntyre Operator sells or otherwise disposes of or loses a portion of its Working Interest such that its Pt. McIntyre Participation is less than 12.5%, it shall cease to be Pt. McIntyre Operator unless a majority of the Pt. McIntyre Voting Interests confirms the continuation of the operatorship. In the event that the Pt. McIntyre Operator is finally adjudicated to be bankrupt or otherwise adjudicated to be insolvent, such adjudication shall automatically be treated as though the Pt. McIntyre Operator had resigned as of the date of such adjudication. -13- O Pt. McIntyre Provisions (March 1, 1993) 77.06 77.07 77.08 Removal. Pt. McIntyre Operator may be removed by 90% of the Pt. McIntyre Voting Interest, excluding the Pt. McIntyre Voting Interest of Pt. McIntyre Operator, if (i) Pt. McIntyre Operator files a petition for bankruptcy or reorganization under the Federal Bankruptcy Act; (ii) such a petition is filed against such Pt. McIntyre Operator and the petition is granted; or (iii) such Pt. McIntyre Operator is determined by final judgment of a court of competent jurisdiction to be guilty, or admits to being guilty, of willful, material breach of the provisions of the General Provisions and the Pt. McIntyre Provisions, and if such Pt. McIntyre Operator fails within ninety days after such final determination or admission to remedy the default or otherwise restore, as nearly as possible, the Pt. McIntyre Owners so affected to their original positions before such breach, or if such remedy or restoration cannot be physically accom- plished within such ninety day period, such Pt. McIntyre Operator fails to give a satisfactory bond or other undertaking to make such remedy or restoration as soon as is reasonably possible. Whether or not the events mentioned in (i), (ii), and (iii) of the preceding paragraph shall have occurred, the Pt. McIntyre Operator with a Pt. McIntyre Participation of less than 20% of the Pt. McIntyre Voting Interests may be removed by a vote of 90% excluding the Pt. McIntyre Voting Interest of such Pt. McIntyre Operator. The effect of excluding the Pt. McIntyre Voting Interest of the Pt. McIntyre Operator means that the total Pt. McIntyre Voting Interest of all Pt. McIntyre Owners shall be deemed the Pt. McIntyre Voting Interests that remain after deducting the Pt. McIntyre Voting Interest of the Pt. McIntyre Operator, and the percentage votes required shall be the percentages specified above of the Pt. McIntyre Voting Interests remaining after such deduction. Effective Date of Resiqnation or Removal. No resignation or removal provided for in Section 77.05 and 77.06 shall become effective until a qualified successor Pt. McIntyre Operator shall have been selected and approval thereof is given by the Commissioner and the successor shall have assumed its duties as a Pt. McIntyre Operator. Selection of Successor Pt. McIntyre Operator. Upon the resignation or removal of the Pt. McIntyre Operator, a Il./ -14- Pt. McIntyre Provisions (March 1, 1993) 77.09 successor Pt. McIntyre Operator shall be selected by the affirmative vote of Pt. McIntyre Owners having 90% or more of the Pt. McIntyre Voting Interest applicable at the time of such resignation or removal as set forth in Sections 77.05 and 77.06, above. If the Pt. McIntyre Operator that is removed fails to vote or votes only to succeed itself, the successor Pt. McIntyre Operator shall be selected by the affirmative vote of Pt. McIntyre Owners having 90% or more of the Pt. McIntyre Voting Interest remaining after excluding the Pt. McIntyre Voting Interest of the Pt. McIntyre Operator that was removed. Assumption of Duties b~ Successor. Upon a change of Pt. McIntyre Operator, the outgoing Pt. McIntyre Operator shall deliver possession of all equipment, records, materials, appurtenances and any other Pt. McIntyre Equipment used in conducting Pt. McIntyre Operations to the new, duly approved successor Pt. McIntyre Operator, and said successor Pt. McIntyre Operator will thereupon have assumed the duties and obligations of Pt. McIntyre Operator hereunder. .53 -15- Pt. McIntyre Provisions (March 1, 1993) 78.01 78.02 · 78.03 78.04 ARTICLE 78 PT. McINTYRE PARTICIPATIONS, PT. McINTYRE TRACT PARTICIPATIONS AND PT. McINTYRE VOTING INTERESTS Pt. McIntyre Participations. The Pt. McIntyre Participa- tion of each Pt. McIntyre Owner as of the PMPA Effective Date is set forth in Exhibit 78-A. Pt. McIntyre Tract Participations. Pt. McIntyre Tract Participations are set forth in Exhibit 76-B. Pt. McIntyre Voting Interests. The Pt. McIntyre Voting Interest of each Pt. McIntyre Owner is equal to its Pt. McIntyre Participation. The Pt. McIntyre Voting Inter- ests as of the PMPA Effective Date are set forth in Exhibit 78-A. No Redetermination of Pt. McIntyre Participation and Pt. McIntyre Tract Participations. Once the Final Equity percentages are approved pursuant to the Pt. McIntyre Agreement, Pt. McIntyre Participations and Pt. McIntyre Tract Participations shall remain in effect until the termination of the PMPA, except in the event of a change in boundaries of the PMPA, as provided in Article 86. 154 -16- Pt. McIntyre Provisions (March 1, 1993) 79.01 79.02 79.03 ARTICLE 79 SUPERVISION OF OPERATIONS BY PT. McINTYRE OWNERS Formation of Pt. McIntyre Owners Committee. Ail Pt. McIntyre Operations shall be subject to the supervision and control of the Pt. McIntyre Owners. In order to effectively exercise such supervision and control, the Pt. McIntyre Owners shall act through a Pt. McIntyre Owners Committee consisting of their designated manage- ment representatives. At the time of the execution of the Pt. McIntyre Provisions, each Pt. McIntyre Owner shall designate a management representative and an alternate to serve on the Pt. McIntyre Owners Committee by giving written notice thereof to the other Pt. McIntyre Owners and the Secretary setting forth the names, addresses, and telephone numbers of such representative and alternate. A Pt. McIntyre Owner may at any time remove its represen- tative or alternate and designate a replacement by giving written notice thereof to the other Pt. McIntyre Owners and the Secretary setting forth the name, address, and telephone number of such new representative or alternate. The compensation and expense of representatives and alternates to the Pt. McIntyre Owners Committee shall be borne by their respective Pt. McIntyre Owners. Chairmanship of the Pt. McIntyre Owners Committee. The Chairman of the Pt. McIntyre Owners Committee shall be the designated representative of the Pt. McIntyre Operator, or in the absence of such designated represen- tative, the alternate representative of the Pt. McIntyre Operator. The Chairman shall, with the assistance of the Secretary, attend to the administrative needs of the Pt. McIntyre Owners Committee, preside at all regular and special meetings, and perform such other duties as shall be assigned by the Pt. McIntyre Owners Committee. Secretary. A Secretary shall be designated and provided by the Pt. McIntyre Operator. The Secretary shall have the responsibility to keep the minutes, records, and files of the Pt. McIntyre Owners Committee and otherwise to assist in the administrative work of the Pt. McIntyre Owners Committee under the direction of the Chairman. 155 -17- Pt. McIntyre Provisions (March 1, 1993) 79.04 79.05 The Secretary will be responsible for maintaining files for all proposed written votes and all approved written votes. Written minutes, resolutions, and approval notices will be submitted to the Pt. McIntyre Owners in a timely manner. The office of Secretary is recognized to be a part-time position, and the holder of that office shall remain attached to and be located with the Pt. McIntyre Operator. The Secretary shall devote such time to the business of the Pt. McIntyre Owners Committee as shall reasonably be required to efficiently and expedi- tiously serve the needs of the Pt. McIntyre Owners Committee and the Chairman. General Meetings. The Pt. McIntyre Owners Committee will meet periodically as agreed at a specific time and place to be designated by the Chairman. The Chairman will give at least 30 days advance notice to the Pt. McIntyre Owners of each general meeting, specifying the time and place and setting out a tentative agenda, including all items proposed by other Pt. McIntyre Owners, together with appropriate information and documents relating to the items on the agenda. At any time prior to 10 days before the meeting, any Pt. McIntyre Owner may add items to the agenda by giving written notice to the Secretary and the other Pt. McIntyre Owners and by furnishing appropriate information and documents concerning the added agenda items. Only items placed on the agenda in accordance with the foregoing may be voted on or approved. Amendments to the agenda may be made at the meeting if such amendments are directly related to items on the agenda. A Pt. McIntyre Owner may, at its option and expense, attend by means of telephone or video conference facilities. Special Meetings. Special meetings of the Pt. McIntyre Owners Committee may be called by any Pt. McIntyre Owner on at least 15 days advance written notice to the Secretary and the other Pt. McIntyre Owners and by specifying the agenda and by furnishing appropriate information and documents concerning the agenda. The Chairman will then promptly notify all Pt. McIntyre Owners of the time and place of the special meeting and allow the Pt. McIntyre Owners to add items to the agenda by giving written notice and furnishing appropriate documents concerning the added agenda items not less than five days prior to the meeting. Only items placed on the agenda in accordance with the foregoing may be voted on i56 -18- Pt. McIntyre Provisions (March 1, 1993) 79.06 79.07 79.08 or approved. Amendments to the agenda may be made at the meeting if such amendments are directly related to items on the agenda. Emerqency Meetinq~. In the event of an emergency threat- ening life or property, a meeting of the Pt. McIntyre Owners Committee may be called by any Pt. McIntyre Owner or the Pt. McIntyre Operator as soon as practicable to address those emergency matters only. Greater Pt. McIntyre Planninq Subcommittee. The Greater Pt. McIntyre Planning Subcommittee (GPMPSC) is estab- lished to assist the Owners of participating areas (other than the IPAs) in the Greater Pt. McIntyre Area in performing their duties and functions. The Pt. McIntyre Owners shall each be entitled to designate and at any time replace one representative and one alternate to the GPMPSC after the same pattern applicable to represen- tatives and alternates on the Pt. McIntyre Owners Committee. The offices of representative and alternate shall not be full-time positions, and the compensation and expenses of representative and alternate shall be borne by their respective Pt. McIntyre Owner. The chairman of the GPMPSC shall be the designated repre- sentative of the Lisburne Operator. The location of meetings will be designated by the chairman of the GPMPSC. Normally, GPMPSC meetings will be at the location of the Lisburne Operator. The Pt. McIntyre Owners Committee or the GPMPSC may set up standing or ad hoc subcommittees as deemed appropri- ate. Any action taken by the GPMPSC or a subcommittee shall be deemed only advisory to the Pt. McIntyre Owners Committee, as the sole power to bind a Pt. McIntyre Owner shall reside in the representative of the Pt. McIntyre Owner when acting in the capacity of a Pt. McIntyre Owners Committee representative. Subsurface Development Team (SDT). The Pt. McIntyre Owners will immediately appoint a group that will be charged with the responsibility of determining the composition and functions of the Subsurface Development Team by July 1, 1993. The Subsurface Development Team shall report to the Pt. McIntyre Owners Committee. Any Pt. McIntyre Owner may disband the Subsurface Development Team upon written notice to the other Pt. McIntyre Owners and Secretary. 157 -19- Pt. McIntyre Provisions (March 1, 1993) ARTICLE 80 VOTING PROVISIONS FOR THE PMPA 80.01 General Principles Governing Votinq. The Pt. McIntyre Owners shall exercise overall supervision and control of Pt. McIntyre Operations by making such decisions, deter- minations and granting such approvals as are required or permitted by the Pt. McIntyre Provisions. Unless other- wise provided in Article 77, each Pt. McIntyre Owner shall have a Pt. McIntyre Voting Interest with respect to PMPA matters subject to any such decision, determination or approval equal to its Pt. McIntyre Participation in the PMPA at the time of the vote. The procedures through which the Pt. McIntyre Owners will exercise their Pt. McIntyre Voting Interests are set forth in Sections 80.02 and 80.03. In each instance where a decision, determination or approval requires a specified percentage vote, the vote that is required is the percentage of the total Pt. McIntyre Voting Interests of all Pt. McIntyre Owners entitled to vote thereon, and not merely the percentage of those participating in the vote. Any decision, determination or approval receiving the affirmative vote of the required Pt. McIntyre Voting Interests shall be deemed given by and shall be binding upon all Pt. McIntyre Owners entitled to vote thereon. 80.02 Action Throuqh the Pt. McIntyre Owners Committee. Each representative to the Pt. McIntyre Owners Committee (or the alternate in the absence of the representative) shall have the authority to exercise the voting rights of the Pt. McIntyre Owner, and the vote shall bind and obligate such Pt. McIntyre Owner. A representative shall not, however, have any authority to act on behalf of the Pt. McIntyre Owners as an entirety. Any representative of a Pt. McIntyre Owner may vote at any Pt. McIntyre Owners Committee meeting through any person authorized by a written proxy signed by such representative and filed with the Secretary prior to or at the meeting. No such proxy shall be valid for more than the single meeting specified in the proxy. Any Pt. McIntyre Owner not represented at a Pt. McIntyre Owners Committee meeting by a representative, alternate, or proxy.may vote by a writing addressed to the Secretary -20- 158 ' Pt. McIntyre Provisions (March 1, 1993) 80.03 80.04 80.05 with a copy to the Chairman, provided such vote is received prior to the submission of such items to vote. Such an absentee vote will not be counted, however, on any agenda item that is amended at the meeting. Action Without a Meeting. In lieu of a meeting of the Pt. McIntyre Owners Committee, the Pt. McIntyre Owners may decide any matter by a vote taken by letter provided the matter is first submitted in writing to the Pt. McIntyre Owners and to the Secretary by the Chairman or any other Pt. McIntyre Owner representative proposing the vote and no meeting on the matter is called as provided in Article 79 within ten (10) days after such proposal is dispatched to the other Pt. McIntyre Owners. The votes of the Pt. McIntyre Owners shall be sent to the Secretary with copies to the Chairman, and the Secretary shall give prompt written notice of the results of the voting to all Pt. McIntyre Owners. All proposed ballots shall expire 90 days following submission to the Secretary if approval of the Pt. McIntyre Owners is not received. Matters Requirinq 51% Affirmative Vote. Except where a voting level is specifically provided otherwise in the Pt. McIntyre Provisions, matters requiring Pt. McIntyre Owner approval shall require approval by 51% of the Pt. McIntyre Voting Interests. Matters Requirinq 90% Affirmative Vote. The following PMPA matters shall require approval by 90% of the Pt. McIntyre Voting Interests: (a) Amendments to the Pt. McIntyre Reservoir Develop- ment Objectives and Depletion Plan (Section 81.02). (b) Pt. McIntyre Master Commitment Authorizations (PMMCA) as provided for in Section 81.05. (c) Capital AFEs and associated Capital Budget line items, if outside the scope of approved PMMCAs, for the following expenditures (Subsections 81.04.03 and 81.06.02): (i) drilling beyond the first 85 development wells and 2 gas injection wells; (ii) facility modifications or expansions in excess of $25,000,000 gross expenditures; and 159 -21- Pt. McIntyre Provisions (March 1, 1993) (iii) non-drilling Investment Expenditures in excess of $3,500,000, other than facility modifica- tions or expansions of less than $25,000,000 gross expenditure. In the determination of the appropriate voting level for a facility modification or expansion, the expenditures required for the total project shall be considered in sum, even if the funding is to be accomplished through multiple AFEs. (d) Exceeding the Gas reserve debit as specified in Section 82.04. (e) Terms and conditions for sharing of Pt. McIntyre Equipment (Sections 83.01 and 83.02). (f) Injection of non-Pt. McIntyre Substances into the Pt. McIntyre Reservoir. This is not intended to apply to injection of substances such as lost circulation materials, well stimulation materials, corrosion inhibitors or other substances routinely used in drilling, workover, operating and mainte- nance activities, or to Pt. McIntyre's share of residue gas from the LPC (which is in fact from more than one source). (g) Injection of Pt. McIntyre Substances into a non-Pt. McIntyre Reservoir, which includes Pt. McIntyre's share of residue gas from the LPC (which is in fact from more than one source). (h) Settlement of a single damage claim or suit in excess of $200,000 (Section 85.01). (i) Settlement of a single penalty claim or suit in excess of $50,000 (Section 85.01). (j) Disposition and retirement of Pt. McIntyre Equip- ment for items with replacement value in excess of $5,000,000 (Section 84.02). (k) Release of confidential data in accordance with Article 6 of the General Provisions. (1) Removal of the Pt. McIntyre Operator under condi- tions specified in Section 77.06. (The Pt. 160 -22- Pt. McIntyre Provisions (March 1, 1993) 80.06 80.07 McIntyre Voting Interest of the Pt. McIntyre Operator shall be excluded in such determination.) (m) Selection of a successor Pt. McIntyre Operator after removal or resignation of the Pt. McIntyre Operator (Section 77.08). (n) Changes in boundaries of the PMPA or combination of the PMPA with other Participating Areas in accor- dance with Article 86. (o) Termination of the PMPA (Article 87). Matters Requiring 100% Affirmative Vote. The following matters shall require approval by 100% of the Pt. McIntyre Voting Interests: (a) Amendments to the Pt. McIntyre Provisions. (b) Non-Unit sharing of Pt. McIntyre Equipment. How- ever, this requirement is not intended nor shall it be construed to set any precedent for the voting level required for non-Unit sharing of Unit Equipment other than Pt. McIntyre Equipment. General Unit Matters. The voting requirements of the General Provisions for General Unit Matters remain unchanged except to the extent explicitly modified herein for Pt. McIntyre Owners. 161 -23- Pt. McIntyre Provisions (March 1, 1993) 81.01 81.02 81.03 81.04 ARTICLE 81 APPROVALS, BUDGETS, AND EXPENDITURES General. The planning and approval of Pt. McIntyre Operations pursuant to the Pt. McIntyre Provisions involves the following five basic elements: (a) annual review of the Pt. McIntyre Reservoir Development Objec- tives; (b) preparation of a Pt. McIntyre Five-Year Plan; (c) preparation and approval of a Pt. McIntyre Master Commitment Authorization (PMMCA), if required; (d) prepa- ration and approval of a Budget which is consistent with the Pt. McIntyre Five-Year Plan; and (e) approval of AFE items that exceed the Operator Expenditure Authority. The planning and approval requirements related to the above process are set out in the remaining sections of this Article 81. Pt. McIntyre Reservoir Development Objectives and Deple- tion Plan. The Pt. McIntyre Reservoir Development Objectives and Depletion Plan are set out in Exhibit 81-A, with amendments requiring approval by 90% of the Pt. McIntyre Voting Interests. Pt. McIntyre Five-Year Plan. A Pt. McIntyre Five-Year Plan shall be submitted to the Pt. McIntyre Owners by June 1 of each year. The Pt. McIntyre Five-Year Plan may be submitted in conjunction with Five-Year Plans from other Participating Areas which share the use of the LPC for processing of their produced fluids. The Pt. McIntyre Five-Year Plan will be consistent with the approved Pt. McIntyre Reservoir Development Objectives. The plan shall include a volume forecast and shall describe proposed development plans for the next five years. The Pt. McIntyre Five-Year Plan shall require approval by 90% of the Pt. McIntyre Voting Interests unless the SubsurfaCe Development Team exists, in which case approval shall be by 51% of the Pt. McIntyre Voting Interests. In either case, the approval shall be by August 1 of each year. Budgets. Budgets prepared by the Pt. McIntyre Operator will be consistent with the approved Pt. McIntyre Five- Year Plan issued on a not-to-exceed basis with no contin- gency above that determined for individual components. Items outside the scope of an approved PMMCA will be clearly identified. -24- Pt. McIntyre Provisions (March 1, 1993) 81.04.01 Budget Format. The Pt. McIntyre Operator will provide Budgets in a consistent format and in sufficient detail to allow the Pt. McIntyre Owners adequate review and to permit the calculation of each Pt. McIntyre Owner's obligation. All items of expenditure and their requisite approval level must appear in the Budgets. The Budget Year estimate will be divided by calendar quarters. Escalation factors, where used, will be clearly stated. 81.04.02 Budget Timing.and Period Covered by Budqets. The Pt. McIntyre Operator shall submit an original Budget to the Pt. McIntyre Owners for their review by September 15 of each year for approval by November 15. The Pt. McIntyre Operator shall inform the Pt. McIntyre Owners of changes to the original Budget by December 20. The Budget shall be comprised of a Capital Budget and an Expense Budget and shall project Pt. McIntyre Expenditure by quarter for the succeeding calendar year. In conjunction with the submission of the Budget, the Pt. McIntyre Operator will submit a volume forecast of production for the Budget Year. 81.04.03 Budqet ADDroval. Capital Budgets shall be approved in accordance with the voting provi- sions of Sections 80.04 and 80.05(c) on a line item basis, except for wells, which will require approval as a single category. Approval for wells to be drilled and/or other line items in the Capital Budget constitutes approval of scope and timing only and thus, no commitments of funds are authorized for items requiring Capital AFE approval pursuant to Subsection 81.06.02 until such Capital AFE is approved. Once a Capital AFE is approved, the line item corresponding to the Capital AFE will not require approval on any subsequent Capital Budget. Additional Pt. McIntyre Expenditures will be approved by the Lisburne Owners through the Lisburne Expense Budget consistent with Section 81.06 of the Pt. McIntyre Provisions, Section 53.02 of the Lisburne Provisions, as 163 -25- Pt. McIntyre Provisions (March 1, 1993) amended, the Pt. McIntyre Agreement and the Lisburne Budget terms agreed to in conjunction with facility sharing. Expense Budgets shall be approved for the Budget Year on a total basis only by 90% of the Pt. McIntyre Voting Interests unless the SDT exists, in which case the approval shall be by 51% of the Pt. McIntyre Voting Interests. Approval of the Expense Budget constitutes the authority to expend or commit funds up to the approved total Expense Budget amount for well work, major repairs, and field specific study cost. The Expense Budget will include estimates of amounts billed by the governmental authorities for ad valorem taxes and the amount calculated for overhead pursu- ant to Exhibit I of the PBUOA and the actual amount calculated for facility sharing fees pursuant to Section 81.07 and the Pt. McIntyre Agreement. The Budgets' amounts will be revised when actual amounts are obtained pur- suant to the above. No commitment of funds is authorized for items requiring an Expense AFE until such Expense AFE is approved. Approval of the Budget constitutes a spending limit on the Pt. McIntyre Operator by the Pt. McIntyre Owners. If the Pt. McIntyre Operator reasonably expects to exceed the then cur- rently approved Budget amount for the Capital Budget or the Expense Budget, then the Pt. McIntyre Operator will submit an interim Budget addition that must be acted on by the Pt. McIntyre Owners within 60 days of receipt. The Pt. McIntyre Operator's submission for Budget addition may be made by letter request with sufficient detail to allow adequate Pt. McIntyre Owner review. 81.04.04 Capital Budqets. A Capital Budget line item will specify the AFEs for which approval will be requested in that Budget Year and expendi- tures for that Budget Year. Each line item will be approved by an individual Capital AFE or series of Capital AFEs or a grouping of similar minor AFEs. 164 -26- Pt. McIntyre Provisions (March 1, 1993) The Capital Budget will be categorized as follows: (a) development drilling; (b) capital workovers; (c) field production facilities; (d) Minor Capital Investment as specified below; and (e) other. Expenditures within Operator Expenditure Authority that are generally projected on a historical basis and not specifically identi- fied at the time of Budget preparation will be grouped into a single category entitled Minor Capital Investment ("MCI") and divided into separate subcategories as appropriate. The total MCI expenditures for any year may not exceed an amount equal to the Operator Expenditure Authority. 81.04.05 Expense Budqets. Expense Budgets will be categorized as follows: (a) well work; (b) ad valorem taxes; (c) overhead; (d) facility sharing fees (as identified in Section 81.07); (e) major repairs; (f) field specific study cost; and (e) other. Facility sharing fees which include propor- tionate and per barrel O&M fees will be identified by source. Non-LPC major repairs are defined as those repairs in excess of the -27- Pt. McIntyre Provisions (March 2, 1993) 81.05 81.06 Operator Expenditure Authority. Field spe- cific study costs are those that can be identified with a specific field or fields. The estimated cost associated with those items requiring Expense AFE approval will be sepa- rately identified in the Expense Budget. Pt. McIntyre Master Commitment Authorization (PMMCA). A PMMCA includes, but is not limited to, the objective and . scope of a project, its conceptual design, the approxi- mate timing of construction and installation, and the total estimated commitment. Escalation factors, where used, will be clearly stated. The Pt. McIntyre Operator may at any time prepare and submit for approval a PMMCA with respect to a project. A PMMCA requires approval by 90% of the Pt. McIntyre Voting Interests. Any PMMCA which is inconsistent with the Pt. McIntyre Reservoir Development Objectives will be identified, and once approved, will specifically amend the Pt. McIntyre Reservoir Development Objectives and the Pt. McIntyre Five-Year Plan. Approval of a PMMCA constitutes approval of scope of a project. Individual items identified in or arising out of the approved PMMCA shall be the subjects of AFEs to be submitted by the Pt. McIntyre Operator. No commitment of funds is authorized except as otherwise provided in this Article until an AFE is approved pursuant to Section 81.06. If a Capital AFE which modifies the scope of an approved PMMCA is submitted for approval, such.inconsis- tency will be identified and the voting provisions of Section 80.05(c) for Capital AFEs outside the scope of approved PMMCAs shall apply as to approval. Once approved, the Capital AFE will specifically amend the PMMCA. AuthorizatiOn for Expenditure. The Pt. McIntyre Operator will prepare and submit Capital AFEs and Expense AFEs for approval where appropriate. Commitment of funds is only authorized, except.as provided in Subsection 81.04.03, or as otherwise specified in this Section 81.06, when AFEs or revised AFEs are approved. The Budget line items and/or PMMCAs under which AFEs are submitted will be identified in the AFE. All AFEs will be submitted in "as spent" dollars with the amount of included inflation indicated. -28- Pt. McIntyre Provisions (March 1, 1993) 81.06.01 Operator Expenditure Authority. Except as otherwise provided, the Pt. McIntyre Operator is authorized to commit to or expend any single item of Pt. McIntyre Expenditure up to the amount specified in Exhibit 81-B except in the case of an expenditure shared with other Participating Areas where such limitation shall apply to the total expenditure. As of the PMPA Effective Date, the Operator Expenditure Authority is $900,000, subject to calculation as provided in Exhibit 81-B. The Pt. McIntyre Operator is not authorized to make any expenditures without Pt. McIntyre Owner approval on the following items: (a) drilling or completing any well; (b) deepening or plugging back a well; (c) long-term changes of well status and con- version of wells from existing service to other service; (d) charges for services by consultants, engineering contractors or other techni- cal services, not authorized in Exhibit I of the General Provisions; (e) selection of completion intervals; (f) reservoir control workovers, such as but not limited to stimulation workovers, altering the completion interval; or (g) offtake and injection strategies. Approval of paragraphs (a) through (g) shall require approval by 90% of the Pt. McIntyre Voting Interests unless the Subsurface Devel- opment Team exists, in which case approval of (a) through (d) shall be by 51% of the Pt. McIntyre Voting Interests and approval of (e) through (g) shall be by the Subsurface Devel- opment Team. The Pt. McIntyre Operator will not fragment expenditures which normally would be performed 167 -29- Pt. McIntyre Provisions (March 1, 1993) under a single AFE and when taken in sum, exceed the Operator Expenditure Authority. If the Pt. McIntyre Operator, subsequent to committing or expending funds under this authority, reasonably expects that expendi- tures will exceed the Operator Expenditure Authority, the Pt. McIntyre Operator will immediately notify the Pt. McIntyre Owners by submitting an AFE in the full amount for their approval. 81.06.02 Capital AFE. A Capital AFE will be issued for any capital expenditure which is expected to exceed the Operator Expenditure Authority. Approval of a Capital AFE shall be in accor- dance with the voting provisions of Sections 80.04 and 80.05(c). In addition, in cases where an AFE is not required for approval, the Pt. McIntyre Operator will prepare an AFE for information only and distribute it to the other Working Interest Owners. The Pt. McIntyre Operator will not submit a Capital AFE in an amount greater than $100,000,000 unless that amount is within the scope of a previously approved PMMCA. 81.06.03 Expense AFE. An Expense AFE will be issued for single items in excess of an amount equal to the Operator Expenditure Authority. All Expense AFEs that exceed the Operator Expendi- ture Authority will require approval by 51% of the Pt. McIntyre Voting Interests. In addi- tion, in cases where an AFE is not required but the total ARCO net amount exceeds $100,000, an informational AFE shall be pro- vided to all Pt. McIntyre Owners for their information. 81.06.04 AFE Over,in Limit. An approved AFE which exceeds the Operator Expenditure Authority authorizes the Pt. McIntyre Operator to expend the total approved amount, plus excess expenditures of 10% of the total approved amount or $5,000,000, whichever is less. 168 -30- Pt. McIntyre Provisions (March 1, 1993) 81.06.05 AFE Underrun. When the Pt. McIntyre Operator reasonably expects the total cost of an AFE to be less than 80% of the total authorized amount of such approved AFE, the Pt. McIntyre Operator will distribute a memorandum for the information of the Pt. McIntyre Owners describing such AFE underrun. The revised amount will become the approved amount for said AFE. 81.06.06 Budget Status Report. The Pt. McIntyre Operator will provide a quarterly status report to all Pt. McIntyre Owners, specifying the estimated work in place, expenditures booked to date, projected ultimate cost under any active AFE, and latest estimate of the total projected capital and expense for the Budget Year. The Pt. McIntyre Operator shall also provide monthly notification of any significant variances from the quarterly report. 81.06.07 AFE Revision. A revised AFE will be promptly submitted for approval when the Pt. McIntyre Operator: (a) reasonably expects to exceed the total authorized amount of the AFE plus the excess expenditure pursuant to Subsection 81.06.04; (b) significantly changes the scope of the work authorized in the AFE; or (c) significantly changes the expenditure pattern of a project. Minor changes in scope of drilling AFEs including, but not limited to, minor revision to the surface or bottomhole location, logging program, mud system or completion program which do not result in exceeding the autho- rized expenditure limit may be approved by letter agreement without submitting a revised AFE, subject to the voting requirements of Sections 80.04 and 80.05(c). 1(]9 -31- Pt. McIntyre Provisions (March 1, 1993) 81.06.08 AFE Content. Ail AFEs will identify the scope of the work to be performed, the total amount requested and each Pt. McIntyre Owner's obli- gation, and will provide~ estimates of the quarterly expenditures for the first calendar year and annual expenditures for each year thereafter. AFEs will be categorized into the following items, if applicable, but not limited to: (a) engineering design; (b) equipment and materials; (c) fabrication; (d) transportation; (e) installation; (f) Pt. McIntyre Operator's cost; (g) other cost, including computer-related costs; and (h) contingency. Ail contingencies will be identified as a single amount in item (h), and this item may not exceed 10% of the total estimate prior to application of the contingency. The items or reasons most likely to cause the contingency will be identified. If the scope of the AFE has previously been identified in a PMMCA or Budget, reference will be made to the PMMCA and the Budget line item. Each AFE will contain sufficient information to enable the Pt. McIntyre Owners to evaluate the benefits and justifications for the expenditure. 81.06.09 Non-Operator Costs. Upon the request of a Pt. McIntyre Owner, the Pt. McIntyre Operator will prepare and submit AFEs for approval of non- operator costs. These AFEs will be for the purpose of requesting approval for furnishing 170 -32- Pt. McIntyre Provisions (March 1, 1993) 81.07 technical employees, as defined in Exhibit I of the General Provisions, of a non-operator to supplement the technical employees of the Pt. McIntyre Operator in the conduct of Pt. McIntyre Operations. The Pt. McIntyre Owner making the request will describe the work to be performed and the estimated costs. Any technical employees approved under an AFE will remain employees of the Pt. McIntyre Owner furnishing the techni- cal employees. 81.06.10 Subcomponent AFEs. Subcomponent AFEs are created for internal cost control and finan- cial administration purposes only and are not submitted to the Pt. McIntyre Owners for approval. Subcomponent AFEs are included in the scope and cost of approved AFEs. Subcom- ponent AFEs are not subject to the approval provisions, the revision requirements or the overexpenditure limits of this Section 81.06. Facility Sharing Fees. Pt. McIntyre Owners will also pay certain fees, proportionate share of Operating Cost (as defined in Section 9.2 of the Pt. McIntyre Agreement and Subsection 53.02(b) of the Lisburne Provisions, as amended), and abandonment cost or fees for use of Support Facilities, Lisburne Equipment and IPA Source Water facilities and services as provided in Section 53.02 of the Lisburne Provisions, as amended, and Article 9 of the Pt. McIntyre Agreement. These facility sharing fees, whether current or prior period adjustments, will be paid through current and/or future Operating Cost allocations to and from Pt. McIntyre Owners. -33- Pt. McIntyre Provisions (March 1, 1993) 82.01 82.02 82.03 ARTICLE 82 ALLOCATION AND EQUALIZATION OF PT. McINTYRE SUBSTANCES AND EXPENDITURES Allocation of Pt. McIntyre Substances and Expenditures to Pt. McIntyre Owners. The allocation of Pt. McIntyre Substances and Expenditures to the Pt. McIntyre Owners and to Tracts will be in proportion to Pt. McIntyre Participations and Pt. McIntyre Tract Participations, respectively. Pt. McIntyre Participations and Pt. McIntyre Tract Participations are set forth in Exhibits 78-A and 76-B, respectively. The allocation of Pt. McIntyre Expenditure will be implemented in accordance with Exhibit I of the General Provisions. Monthly allo- cations of Pt. McIntyre Substances for royalty reporting will be based on Pt. McIntyre Substances actually taken by each Pt. McIntyre Owner and allocated to its Tracts. Equalization of Pt. McIntyre Expenditures. Pre-PMPA Costs to be equalized shall include the following: (a) items specifically covered in Section 8 of the Pt. McIntyre Agreement; (b) items included within the scope of the Pt. McIntyre Master Commitment Authorization; and (c) other items included by separate written agreement. No other costs shall be included for equalization unless approved by 51% of the Pt. McIntyre Voting Interests. The Pt. McIntyre Operator shall provide a list of costs included in paragraphs (a) through (c) by May 15, 1993. Each Pt. McIntyre Owner shall furnish a list of all other costs which it seeks to equalize by June 1, 1993, and the Pt. McIntyre Owners shall reach final resolution of the equalization of said costs by July 1, 1993. Only costs identified under these procedures shall be equalized. Takinq Hydrocarbon Fluids in Kind. Except for those Hydrocarbon Fluids used in Pt. McIntyre Operations or unavoidably lost, each Pt. McIntyre Owner will take in kind or separately dispose of its allocation of Hydrocarbon Fluids. In the event any Pt. McIntyre Owner -34- Pt. McIntyre Provisions (March 1, 1993) 82.04 82.05 shall fail to take in kind or separately dispose of its Pt. McIntyre Participation share of Hydrocarbon Fluids, Pt. McIntyre Operator shall have the right, subject to revocation at will by the Pt. McIntyre Owner owning it, but not the obligation, to purchase such Hydrocarbon Fluids or sell the same to others for the time being, at not less than the market value prevailing in the area. However, all contracts of sale by Pt. McIntyre Operator of another Pt. McIntyre Owner's share of Hydrocarbon Fluids shall be only for such reasonable period of time consistent with the minimum needs of the industry under the circumstances, but in no event shall any such contract be for a period in excess of one year. Except as otherwise provided in Section 82.15, any such purchase or sale by Pt. McIntyre Operator shall be subject to the right of the owner of the Hydrocarbon Fluids to exercise at any time its right to take in kind, or separately dispose of, its share of all Hydrocarbon Fluids not previously delivered to a purchaser. Takinq Gas in Kind. Subject to the limitation in this Section 82.04, each Pt. McIntyre Owner will have the right, but not the obligation, to take in kind or sepa- rately dispose of any of its allocation of Gas, except for that Gas used in Pt. McIntyre Operations pursuant to Section 82.05, flared, vented or unavoidably lost. Unless otherwise approved by 90% of the Pt. McIntyre Voting Interests, a Pt. McIntyre Owner's Gas reserve debit, as specified in Section 82.13, shall not exceed one-third of its Pt. McIntyre Participation share of 300 billion standard cubic feet. Any approval for a reserve debit in excess of one-third of a Pt. McIntyre Owner's Participation share of 300 billion standard cubic feet shall include a gas balancing agreement to rectify any Gas Imbalance (as that term is used in Section 82.13). Allocation of Fuel Supply Obliqations. The obligation to supply fuel for Pt. McIntyre Operations (including any obligation to provide fuel to the Lisburne Participating Area under Section 53.02(c) of the Lisburne Provisions, as amended) shall be allocated to the Pt. McIntyre Owners in proportion to their respective Pt. McIntyre Participa- tions. Any Pt. McIntyre Owner may substitute Hydrocarbon Fluids or other fuel, including fuel acquired from sources 1.73 -35- Pt. McIntyre Provisions (March 1, 1993) 82.06 outside of the PMPA, to satisfy its fuel supply obliga- tion. If such substitution is made, the fuel supply obligation of the Pt. McIntyre Owner electing to substitute Hydrocarbon Fluids or other fuel shall be increased or decreased to account for the effective heating value of the substituted fuel with respect to the effective heating value of the fuel for which the substitution is being made. Exhibit 82-A sets forth a sample calculation for determining effective heating value adjustments. The substitution may be made only if: (a) the substitution itself and the method of using such fuel has been approved by 51% of the Pt. McIntyre Voting Interests, which approval shall not be withheld except for technical reasons or unless the economic impact on the PMPA as a whole (as opposed to the impact on an individual Pt. McIntyre Owner) is negative; (b) any and all materials or equipment used to trans- port, handle, use or consume such substituted fuel and the use of the substituted fuel are compatible with Pt. McIntyre and Lisburne materials and equip- ment being used to transport, handle, or consume fuel in Pt. McIntyre Operations; (c) any and all,additional investment, operating, over- head, abandonment and cleanup costs directly associated with such substitution are allocated to the Pt. McIntyre Owner electing to make the substitution; (d) all technical safeguards dictated by good engineer- ing and prudent operating practice are taken in making such substitution to prevent any injurious effects upon Pt. McIntyre Equipment and Lisburne Equipment and Pt. McIntyre Operations; and (e) all regulatory requirements set forth by govern- mental agencies for the PMPA and LPA are met in making such substitution. Separate Facilities for Taking in Kind or for Substitut- ing Fuel. Pt. McIntyre Owners shall have the right under the coordination of the Pt. McIntyre Operator (and the Lisburne Operator, as applicable) to provide for con- struction, maintenance, and operation within the PMPA -36- Pt. McIntyre Provisions (March 1, 1993) 82.07 82.08 and/or the LPA of all necessary facilities for the purpose of taking Pt. McIntyre Substances in kind or for substituting fuel, provided such facilities are so constructed, maintained and operated as not to unrea- sonably interfere with Pt. McIntyre Operations and/or Lisburne Operations; and, provided further in the case of the LPA, that the LPA Owners agree or the Lisburne Provisions allow. Any extra investment, operating, over- head, abandonment and cleanup costs incurred by reason of such separate delivery in kind of any portion of the Pt. McIntyre Substances or by reason of substitution of fuel shall be borne by the owner of such portion. Estimate of Deliverable Hydrocarbon Fluids. The Pt. McIntyre Operator will notify each Pt. McIntyre Owner of its share of, and the total of, the estimated deliverable Hydrocarbon Fluids on a monthly basis in accordance with major pipeline nomination procedures. The Pt. McIntyre Operator will have the right to revise the estimate of deliverable Hydrocarbon Fluids under the following circumstances: (a) governmental restraint on production rates; (b) inability to sustain the estimate of deliverable Hydrocarbon Fluids; (c) major pipeline restrictions caused by actions of a major pipeline operator; or (d) Force Majeure. If the estimate of deliverable Hydrocarbon Fluids is revised, the Pt. McIntyre Operator will promptly advise each Pt. McIntyre Owner of its share of, and the total of, the adjusted deliverable Hydrocarbon Fluids. Units of Measurement. Except as otherwise provided in this Article 82 and in Exhibit 82-A, all volumes of Hydrocarbon Fluids referred to herein shall be expressed in STB (stock tank barrels) and all volumes of Gas referred to herein shall be expressed in MMSCF (millions of standard cubic feet); all calculations required by this Article 82 shall be made using volumes expressed in such units of measurement, in accordance with applicable requirements of the State of Alaska, the American Petroleum Institute, the American Gas Association and Pt. McIntyre Provisions (March 1, 1993) 82.09 82.10 82.11 industry standards. If conflicts among the foregoing requirements occur, then precedence is established by the order as listed. Coordination of Offtake and Responsibility for Metering Pt. McIntyre Substances. The Pt. McIntyre Operator shall be responsible for overall management and coordination of offtake of Pt. McIntyre Substances, including gas which is sold or used as fuel. This management and coordina- tion responsibility includes all actions necessary to invoke the right to share Lisburne Equipment under Section 53.02 of the Lisburne Provisions, as amended. Additionally, the Pt. McIntyre Operator shall maintain liaison among the Pt. McIntyre Owners, the Lisburne Owners, the State of Alaska, and any person or entity to whom Pt. McIntyre Substances may be delivered to imple- ment offtake procedures and tender of Hydrocarbon Fluids for pipeline shipment. Concerning State reporting, Pt. McIntyre Operator shall be responsible for preparing and submitting a "Monthly Production and Injection" report and a "Monthly Producer's Report of Gas Disposition." Since Pt. McIntyre Substances will be surface commingled with production from other participating areas prior to treatment and measurement at custody transfer conditions, the Pt. McIntyre Operator is responsible for well test based production allocation of Pt. McIntyre Substances taken in kind by each Pt. McIntyre Owner pursuant to this Article 82. Such well test based production allocation shall be for the purpose of custody transfer of Pt. McIntyre Substances to a Pt. McIntyre Owner and shall be conducted in accordance with applicable requirements of the State of Alaska. The Pt. McIntyre Owners shall be granted access at rea- sonable times and at their sole cost and risk to inspect or witness meter provings and shall be informed in a timely manner of any disruption in the metering of Pt. McIntyre Substances. Point of Taking. A Pt. McIntyre Owner shall be entitled to take all or any portion of its share of Pt. McIntyre Substances excluding water at any location allowed by Section 52.09 of the Lisburne Provisions. Condition at Taking. Ail Pt. McIntyre Substances taken or disposed of by or for a Pt. McIntyre Owner will be 176 · Pt. McIntyre Provisions (March 1, 1993) 82.12 82.13 delivered by the Pt. McIntyre Operator in its then- current condition of quality at the point of its taking or disposition without regard to composition or specific gravity. All handling, treating or other processing of Pt. McIntyre Substances beyond the point of taking will be at the sole risk and expense of the Pt. McIntyre Owner taking and disposing of Pt. McIntyre Substances. Gas Injection. Gas that is not flared, vented, unavoid- ably lost, required for fuel or other use in Pt. McIntyre Operations, or is not taken or disposed of by or for Pt. McIntyre Owners, will be injected into the Pt. McIntyre Reservoir unless injection into another reservoir is authorized by a 90% vote of the Pt. McIntyre Owners. Ail of Pt. McIntyre's share of Gas injected into the Pt. McIntyre Reservoir will, for future purposes, be consid- ered indigenous and, when produced, will be allocated to the Pt. McIntyre Owners in accordance with Sections 82.04 and 82.13. Gas Reserve Debits Record. For purposes of evaluating any imbalance of the proportion in which Pt. McIntyre Owners take in kind or separately dispose of Gas or Gas products, the Pt. McIntyre Operator will maintain a cumulative record on a monthly basis of each Pt. McIntyre Owner's Gas reserve debits. Gas reserve debits will be calculated for each Pt. McIntyre Owner as the sum of the following volumes: (a) that Pt. McIntyre Owner's proportionate share of Gas flared, vented or unavoidably lost; (b) Gas supplied by or for that Pt. McIntyre Owner, for use or consumption as fuel in Pt. McIntyre Operations, including Gas used as fuel in the Lisburne Production Facilities for the benefit of Pt. McIntyre Operations; and (c) Gas, including the gaseous equivalent of gas liquids, taken in kind or separately disposed of by or for that Pt. McIntyre Owner. If any Pt. McIntyre Owner does not take in kind or sepa- rately dispose of Gas in proportion to its Pt. McIntyre Participation, thereby creating a "Gas Imbalance," that Gas Imbalance will be eliminated within a reasonable -39- Pt. McIntyre Provisions (March 1, 1993) 82.14 82.15 period of time by disproportionate taking by the Pt. McIntyre Owners. Except as otherwise provided in a gas balancing agreement entered into by the Pt. McIntyre Owners, any Gas Imbalance remaining upon depletion of the Pt. McIntyre Reservoir shall not be rectified and there shall not be a final accounting. Equalization of Hydrocarbon Fluid Production. Hydro- carbon Fluids production will be equalized in accordance with Section 8.3 of the Pt. McIntyre Agreement. Procedure for Adjustment of Offtake to Pipeline Capacity. This section sets forth the procedure by which the Pt. McIntyre Operator is authorized to adjust offtake to pipeline capacity during the time this section is effec- tive and during periods when TAPS capacity is exceeded by production from fields on the North Slope of Alaska. 82.15.01 Notification of Pipeline Space. At least three working days prior to the end of any month after the effective date of the Pt. McIntyre Provisions, each Pt. McIntyre Owner shall notify the Pt. McIntyre Operator of the total pipeline space it (or its designated shipper) has obtained in TAPS for Hydrocarbon Fluids production for the next month, expressed in barrels per day. This volume shall be the Pt. McIntyre Owner's Accepted Pipeline Space for that month. 82.15.02 Recalculation of Production Level. Upon receiving notice of the volumes described in Subsection 82.15.01 above, the Pt. McIntyre Operator shall total all Pt. McIntyre Owners' Accepted Pipeline Space; this volume shall be the Revised Production Level for the next month. To the extent the Revised Production Level is less than the Pt. McIntyre Operator's estimate of deliverable Hydrocarbon Fluids established under Section 82.07, the Pt. McIntyre Operator shall adjust the estimated deliverable Hydrocarbon Fluids to equal the Revised Production Level. The Pt. McIntyre Operator shall then apply the usual Pt. McIntyre Participation to the Revised ProductiOn Level for each Pt. McIntyre Owner and compute the difference between the Pt. 178 -40- Pt. McIntyre Provisions (March 1, 1993) McIntyre Owner's Accepted Pipeline Space and its allocated share of production from the Revised Production Level. Any difference shall be the Unplaced Offtake or the Over- ~.placed Offtake, as required, of each Pt. McIntyre Owner. Unplaced Offtake shall be recouped as provided in Subsection 82.15.03, and Overplaced Offtake shall reduce a Pt. McIntyre Owner's participation, during any Adjustment Month, as described in Subsection 82.15.03. Thus, a Pt. McIntyre Owner with Unplaced Offtake shall receive more production during an Adjustment Month, to the extent of the Unplaced Offtake, and a Pt. McIntyre Owner with Overplaced Offtake shall receive less production during the Adjustment Month. 82.15.03 Recoupment of Unplaced Offtake and Adjustment of Overplaced Offtake. Six weeks prior to the beginning of the fourth month after a Revised Production Level has been calculated for any month, called the Adjustment Month, the Pt. McIntyre Operator shall estimate deliverable Hydrocarbon Fluids in the ordinary manner and then revise the allocations to each Pt. McIntyre Owner to credit or debit that Pt. McIntyre Owner's production share by the amount of Unplaced Offtake or Overplaced Offtake for the month in which a Revised Production Level was calculated. This volume shall be called a Pt. McIntyre Owner's Adjusted Production Share and shall be used by that Pt. McIntyre Owner in obtaining pipeline space for the Adjustment Month. Provided, however, that for any Adjustment Month, the total amount of Unplaced Offtake which is recoupable shall not exceed ten percent (10%) of the estimated deliverable Hydrocarbon Fluids. If more than one Pt. McIntyre Owner is entitled to a credit for Unplaced Offtake, they shall share the ten percent (10%) of the estimated deliverable Hydrocarbon Fluids available for recoupment in proportion to their respective Unplaced Offtake amounts at the time. It is understood that the Pt. McIntyre Operator may also be required to make a Revised Production Level adjustment for that -41- Pt. McIntyre Provisions (March 1, 1993) month to account for lack of pipeline capacity on a continuous basis. 82.15.04 Balancinq of Production. The Pt. McIntyre Operator shall continue to make adjustments as described above until each Pt. McIntyre Owner has received its Pt. McIntyre Participation share of each month's production in accordance with the allocations in Section 82.01. 82.15.05 Good Faith Tenders Requirement. In accordance with the obligation of Section 82.02 that each Pt. McIntyre Owner take in kind its allocation of Hydrocarbon Fluids, each Pt. McIntyre Owner agrees that it (or its designated shipper) will make good faith tenders of its total allocated volumes to the TAPS pipeline com- panies. The purpose and intent of this obligation is to ensure that these imbalance procedures are utilized only when necessary; that is, when TAPS capacity is less than total North Slope production. 82.15.06 Time Limits. The time limits specified herein may be adjusted at the Pt. McIntyre Operator's discretion from time to time provided adequate notice is given all affected parties and ade- quate time is available to permit tenders into TAPS. -42- 180 :'. Pt. McIntyre Provisions (March 1, 1993) 83.01 83.02 83.03 ARTICLE 83 SHARING OF EQUIPMENT Non-Unit Sharinq of Pt. McIntyre Equipment. Non-Unit sharing of Pt. McIntyre Equipment shall require approval by 100% of the Pt. McIntyre Voting Interests entitled to vote; provided, however, this requirement is not intended nor shall it be construed to set any precedent for the voting level required for non-Unit sharing of Unit Equipment other than Pt. McIntyre Equipment. Unit Sharinq of Pt. McIntyre Equipment. Sharing of Pt. McIntyre Equipment and the terms and conditions of that sharing with other Participating Areas that have been or may be formed in the Unit shall require approval by 90% of the Pt. McIntyre Voting Interests, which approval shall not be unreasonably withheld. Sharinq of Non-Pt. McIntyre Equipment. The Pt. McIntyre Owners agree to maximize economy and efficiency by utilizing non-Pt. McIntyre Equipment as permitted by other provisions of the PBUOA, including, without limitation, the sharing provisions in Article 53 of the Lisburne Provisions, as amended, and the Pt. McIntyre Agreement. -43- Pt. McIntyre Provisions (March 1, 1993) 84.01 84.02 84.03 84.04 ARTICLE 84 DISPOSITION AND RETIREMENT OF PT. McINTYRE EQUIPMENT; ALLOCATION OF PROCEEDS; ALLOCATION OF ABANDONMENT AND CLEAN-UP COSTS General. Subject to the provisions of Articles 16 and 22 and Exhibit I of the General Provisions as to the rights to acquire Unit or Area Equipment, the sale, abandonment, or other disposition of Pt. McIntyre Equipment and wells will be governed by this Article 84. Votinq Provisions. The sale, abandonment, or other dis- position of Pt. McIntyre Equipment will be: (a) within the discretion of the Pt. McIntyre Operator for individual items or integrated assemblies of items having a total replacement value (including others' interests if ownership is shared with a non-Pt. McIntyre Operation) less than the Operator Expenditure Authority; (b) subject to approval by 51% of the Pt. McIntyre Voting Interests for individual items or integrated assemblies of items having a total replacement value (including others' interests if ownership is shared with a non-Pt. McIntyre Operation) exceeding the Operator Expenditure Authority and not in excess of $5,000,000; and (c) subject to approval by 90% of the Pt. McIntyre Voting Interests for individual items or integrated assemblies of items having a total replacement value (including others' interests if ownership is shared with a non-Pt. McIntyre Operation) in excess of $5,000,000. Notification. For purposes of Pt. McIntyre Operations, the Pt. McIntyre Owners waive the notification require- ments of Subsection 16.004.01 of the General Provisions for decisions to dispose of Pt. McIntyre Equipment with replacement value less than the Operator Expenditure Authority. Cost of Abandonment. Pursuant to Subsection 22.001.04 of the General Provisions, the cost of abandoning Pt. McIntyre Operations will be allocated to the Pt. McIntyre 182 -44- Pt. McIntyre Provisions (March 1, 1993) Owners in proportion to their Pt. McIntyre Participa- tions. The cost of abandonment will include and not be limited to dismantling and removal costs, costs of any surface restoration required by applicable lease, law, regulation or agreement, and costs of transportation required to dispose of or distribute any item of Pt. McIntyre Equipment as determined by the Pt. McIntyre Owners. 84.05 Distribution of Assets. Each Pt. McIntyre Owner will share in the distribution of each item of Pt. McIntyre Equipment or the proceeds thereof in proportion to such Owner's Pt. McIntyre Participation. -45- Pt. McIntyre Provisions (March 1, 1993) 85.01 ARTICLE 85 SETTLEMENT OF CLAIMS OR SUITS Settlement of Claims or Suits. The following approval provisions shall apply for settlement of claims or suits involving Pt. McIntyre Operations. 85.01.01 Damaqe Claims. Pt. McIntyre Operator may settle any single damage claim or suit involv- ing Pt. McIntyre Operations for a settlement expenditure not to exceed $200,000 without further approval of the Pt. McIntyre Owners, provided that the payment is in complete settlement of such claim or suit, except in the case of an expenditure shared with other Participating Areas, in which case such limi- tation shall apply to the total expenditure. Expenditures exceeding $200,000 in settlement of such a claim or suit shall require approval by 90% of the Pt. McIntyre Voting Interests. 85.01.02 Penalty Claims. Pt. McIntyre Operator may settle any single penalty claim or suit involving Pt. McIntyre Operations for a set- tlement expenditure not to exceed $5,000 .without prior notice or approval of the Pt. McIntyre Owners. Upon receipt of any penalty claim or suit demanding payment of $5,000 or more, the Pt. McIntyre Operator shall promptly notify all Pt. McIntyre Owners. The Pt. McIntyre Operator may settle any single penalty claim or suit of $5,000 up to $50,000 without the approval of the Pt. McIntyre Owners. In any event, the payment must be in complete settlement of such penalty claim or suit, except in the case of an expenditure shared with other Participating Areas, in which case such limitation shall apply to the total expenditure. Expenditures exceeding $50,000 in settlement of such a penalty claim or suit shall require approval by 90% of the Pt. McIntyre Voting Interests. -46- Pt. McIntyre Provisions (March 1, 1993) 86.01 86.02 86.03 86.04 ARTi CLE 8 6 CHANGE OF BOUNDARIES OF THE PMPA Expansion of the PMPA. The Pt. McIntyre Owners may, by approval of 90% of the Pt. McIntyre Voting Interests, enlarge the PMPA in accordance with Section 5.3 of the Unit Agreement. Any enlargements shall be on the basis of participation and other terms and conditions deter- mined by the Pt. McIntyre Owners, including provision for the allocation of Pt. McIntyre Tract Participations to the added area and the determination of Pt. McIntyre Voting Interests. The current Pt. McIntyre Owners agree among themselves that cost and production of the Pt. McIntyre Participating Area shall be maintained in pro- portion to Final Equity upon any future expansion of the PMPA. Contraction. Except as required by law, the PMPA will not be contracted to exclude those lands included as of the PMPA Effective Date. Should the PMPA be required by law to contract, then the Pt. McIntyre Tract Participa- tions shall be redetermined such that Pt. McIntyre Participations within the contracted PMPA and within the boundaries outlined in Exhibit 76-A shall remain unchanged. Combininq the PMPA with Other Participatinq Areas. The Pt. McIntyre Owners may, by approval of 90% of the Pt. McIntyre Voting Interests, combine the PMPA with one or more Participating Areas within the Prudhoe Bay Unit in accordance with Section 5.4 of the Unit Agreement. Such combination shall be on the basis of participation and other terms and conditions determined by the Pt. McIntyre Owners and the owners of the other affected Participating Area. Votinq. Adjusted. Upon enlargement of the PMPA, the Pt. McIntyre Voting Interests shall automatically be adjusted to conform to their newly redetermined Pt. McIntyre Participations. In the event the PMPA is combined with other Participating Areas, conditions for voting and approvals will be determined by the Pt. McIntyre Owners and the owners of the other affected Participating Area. -47- Pt. McIntyre Provisions (March 1, 1993) 87.01 ARTICLE 87 TERMINATION OF PMPA Termination of the PMPA. Notwithstanding anything in the Unit Agreement to the contrary, the PMPA may be termi- nated by approval by 90% of the Pt. McIntyre Voting Interests whenever they determine that continued Pt. McIntyre Operations are no longer profitable or no longer feasible. 6 -48- Pt. McIntyre Provisions (March 1, 1993) 88.01 88.02 88.03 ARTICLE 88 PMPA EFFECTIVE DATE AND TERM PMPA Effective Date. The Pt. McIntyre Participating Area and the Pt. McIntyre Provisions shall become effective as of March 1, 1993. Term. The Pt. McIntyre Provisions shall continue in effect until (a) all wells in the PMPA have been plugged and abandoned or turned over to the Pt. McIntyre Owners in accordance with Article 24 of the General Provisions; (b) all Pt. McIntyre Equipment and real property acquired pursuant to the Pt. McIntyre Provisions have been disposed of in accordance with the instructions of the Pt. McIntyre Owners; and (c) there has been a final accounting. Effect of Termination. If the Pt. McIntyre Provisions are terminated for any reason, the Pt. McIntyre Owners will remain responsible for the confidentiality obli- gations of Article 6 of the General Provisions, the liabilities which accrued prior to the date of ter- mination, and the provisions of the Pt. McIntyre Provisions relating to the payment of Pt. McIntyre Expenditure until the Pt. McIntyre Operator certifies that all items of Pt. McIntyre Expenditure have been paid. Pt. McIntyre Provisions (March 1, 1993) 89.01 89.02 89.03 89.04 89.05 ARTICLE 89 EXECUTION, EFFECT AND AMENDMENT Original, Counterpart or Other Instrument. A Pt. McIntyre Owner may become a party to the Pt. McIntyre Provisions by signing the original of this instrument, or a counterpart hereof, or other instrument agreeing to become a party hereto, and to be bound by the provisions hereof. The signing of any such instrument shall have the same effect as if all parties had signed the same instrument. Successors and Assiqns. The Pt. McIntyre Provisions shall extend to, be binding upon and inure to the benefit of the parties hereto and their respective heirs, devisees, legal representatives, successors and assigns, and shall constitute a covenant running with the lands, leases and interests covered by the PMPA. Amendment. As provided in Article 21.005 of the General Provisions, the Pt. McIntyre Owners may amend the Pt. McIntyre Provisions without the agreement or consent of any other parties to the Unit Operating Agreement if such amendment applies only to matters affecting the PMPA. No amendment, modification or supplement to the Pt. McIntyre Provisions, however, shall be made except by instrument in writing duly executed by all parties whose approval of such amendment, modification or supplement is required. Benefits of Agreement Restricted to Parties. Nothing in the Pt. McIntyre Provisions, expressed or implied, shall give or be construed to give any person, firm or corporation, other than the Pt. McIntyre Owners and their successors and assigns, any legal or equitable right, remedy or claim under or in respect of the Pt. McIntyre Provisions or under any covenant, conditions, or provisions contained herein; and all such covenants, conditions and provisions shall be for the sole benefit of the Pt. McIntyre Owners. ENtirety of Aqreement. The Pt. McIntyre Provisions shall constitute the entire agreement among the Pt. McIntyre Owners with respect to the matters provided for herein, but only with respect to the matters provided herein; provided that any Working Interest Owners may agree between or among themselves that no provision of the Pt. 1 $ $ Pt. McIntyre Provisions (March 1, 1993) McIntyre Provisions, as between or among themselves, shall have any effect on any agreement or agreements between or among them. IN WITNESS OF THE ABOVE, Pt. McIntyre Owners have executed the Pt. McIntyre Provisions on the dates set forth below. ARCO ALASKA, INC. ~~ Its: Date: EXXON CORPORATION By: Its: Date: BP EXPLORATION (ALASKA) INC. By: Its: Title: F: XDATAXM ARION \WPXM PgVXIrI'- M AC.OA Pt. Mclntyre Provisions (~arch l, 1993) McIntyre Provisions, as between or among themselves, shall have any effec: on any agreement or agreemen~m between or among them. IN WITNESS OP T~ ABOVE, Pt. McIntyre Owners have executed the Pt. McIn~yre Provisions on the dates set forth below. ARCO ALASKA, INC. Its: Date: EXXON CORPORATION .... /, Its, Manager-A]ask/--~ierest BP EXPLORATION (ALASKA) INC. By: Its: Title: ir tOATA ~M A~IO N VWi%M I~T -MAC, C A 190 -51 - Pt. McIntyre Provisions (March' 1, 1993) McIntyre Provisions, as between or among themselves, shall have any effect on any agreement or agreements between or among them. IN WITNESS OF THE ABOVE, Pt. McIntyre Owners have executed the Pt. McIntyre Provisions on the dates set forth below. ARCO ALASKA, INC. By: Its: Date: EXXON CORPORATION By: Its: Date: BP EXPLORATION (ALASKA) INC. Its: · ' ' __ lopment Progr ~ams F: ~)ATAkM ARION\W]AM P'W~:~-MAC.OA EXHIBIT 75-A &~ m~ II ~ mmm~ ad8 '64 'el4emlm GflEAIEfl PT. MclH'I'YItE Al:lEA EXHIBIT 76A Boundaries of the PMPA A/E 34623 Pi. Mclnlyre Paracipating Area I I J~ II · I EXX 34622 I II I BPX 365548 375136 Lease bnes ~ AJE 28298 A/E 28297 AJE 34624 A/E 34627 Shoreline AMENDED EXHIBIT 76-B TRACTS WITHIN THE PT. McINTYRE PARTICIPATING AREA AND PT. McINTYRE TRACT PARTICIPATION (Amended to Reflect Final Equity) (Corrected) Tract No. 115 116 Description T12N-R15E, Sec. 18: Sec. 19: T12N-R14E, Sec. 13: Sec. 14: Sec. 23: Sec. 24: T12N-R14E, Sec. 15: Sec. 16: Sec. 21: Sec. 22: T12N-R14E, Sec. 17: T12N-R14E, Sec. 3: Sec. 4: Sec. 9: Sec. 10: No. of ADL Serial Acres No. Ail N1/2 875 34627 Ail 1800 Ail N1/2 NWl/4, N1/2 NE1/4, SW1/4 NWl/4 N1/2 34624 Ail Ail N1/2 NE1/4 N1/2 1680 28297 N1/2, N1/2 312 SE1/4, NE1/4 SW1/4 excluding U.S. Survey 4044 28298 Ail Ail Ail Ail 2560 34622 Working Pt. McIntyre Basic Lessee of Interest Tract Par- Royalty Record Ownership ticipation % 1/8 ARCO ARCO-50% 7.0 Exxon Exxon-50% 1/8 ARCO ARCO-50% 31.2 Exxon Exxon-50% 1/8 ARCO ARCO-50% 21.9 Exxon Exxon-50% 1/8 ARCO ARCO-50% 0.1 Exxon Exxon-50% 1/8 Exxon Exxon-100% 7.6 Tract No. 117 Description Working Pt. McIntyre No. of ADL Serial Basic Lessee of Interest Tract Par- Acres No. Royalty Record Ownership ticipation % Those Lands in Block 605 lying northerly of the north boundary of Section 3, T12N, R14E, UM, AK (identical with line 4-5 on Block 605), and lying easterly of the west boundary of Sections 2 and 11, T12N, R14E, UM, AK (identical with line 5-6 on Block 605), and lying northerly of the south boundary of Sections 11 and 12, T12N, R14E, UM, AK, and lying northerly of the south boundary of Section 7, T12N, R15E, UM, AK (identical with line 6-7 on Block 605), within the offshore three-mile arc lines listed as State Area on the "Supplemental Official O.C.S. Block Diagram" approved 12/9/79. 3601 365548 1/6 BPX BPX-100% 32.2 -2- 5P MV SP MV GR GAP! Exhibit 76-C Log Denoting Stump Island Reservoir Pt Mclntyre #3 GR 12. SF~U O~ m ~LM ~ OHMM .............. ~-*'?~16-f--+ -- 8100 ~,,_..~__, .... ........ ~___H__,~___~~__ ........... ~ ..... ~_ ........ ,.., ..... t ...... :IL~~l~~~~*'. :l~-- :l~ --" 'i: : ~--': 8759'1 ..... ~._} ~ : ~l~l.l ~ ' . I lJ__ : I I I: l ......... ....... ..... ----.~--.;~T.~-~+ .... ~-.~- :;_:: .... ~ ..... ~..;~-~-b--~- .-~.~-~.~-~-~~~~~_, , .... - ~ ~ ~.~.-~.~ -~8 ~0 ' TVD , ~ ,' :, ', ~':' 8993', ~ ~ ~'~~~~~ ~ ~ -8432 ........ ~~~-. .... ~ .... + ...... . .... .... ~e~;.:;; e--~-- -- .... ~~~ ...... ~ ......... '- ...... Fm · .~~Lm~ ~:: -' .... : [" ~' "~ ' ....... ~ F ~[ ~ : '~ : ;:~:,,, : il. 'L. .} .... ; _ '~~~- t , f t'~ : TVD~ , i ~ ' - -~~:~', :, ~,,:~ ~Miluveach ~_ ,i ........ Fm ' : - ~~ ',I :'i~:i~l ~ iii ii .... ~ ...... : .... ~ i i I - i ' i i ii i i iiii MD MD )SS MD © MO $ 196 AK. g21 104~ ~ ~ l~ 197 Exhibit 76-C Log Denoting Pt. Mclntyre Reservoir Pt Mclntyre #8 ) QR ~ LLD QHMM GR QAPI LL,e. ..~__... ........ ~ .................. ~._~_.. ~ ~ I 1'-,'"'"~ , ~ ....... ~~~~,*~' ~'~" ' ~.~ :' H RZ 1 0,084' ~ . ' , , - : ?.-~o,~oo ~~~='~ -8624.3' ............ . _ ~.~.~~ ~ ~ j~= TVDSS ~:~ ,- .... ~ ;, -, ,,, ,, ,,%-- - ~-:~.;;~i~ ........ ~--'--~ .... '~--~ ......:~o,~ -'*=JT~ ....... --"~~-" ,,~~.~-.--~~.-...~.~ ~ N .--~-~.~~ .... ~;-~ .... 10,~ .-' ~ --~-- ~.-~ ' .~.~ ~ = 0 .................. ~-~ ..... '~ ............ ~ r" ' ~---~.J ..... -- .................. ~._...~~ ..... ~ .... '~~i '~ ~ ~ , ' . :~:;.'.:~:::~ : ~ ~ - , - ~ : ~10,7~ ~ ~ ' :~,~--'~--, .... ~ = __~_ ~~, ; ~ : _.~~~~ ~ 10,877MD ~--.~: ,, , .....~ ......... , "~ ' ~ :"' -9369,9' .... ~~ ...... 11,~ ~ ,r:~,, ...... _ 95~ ,~ ~::;:~ , ..... '--' " ' - I l['J~ , , AK92 1104431 BOO Pt. McIntyTe Provisions (March 1, 1993) Pipelines Production will flow from PM-1 and PM-2 to the LPC via 18" and 24" pipelines, respectively. An 18" water injection pipeline and a 14" high pressure gas pipeline will carry water and gas, respectively, from the LPC to each drill site (Attachment lb). Corrosion resistant materials will be used where appropriate for Point McIntyre pipelines. Lisburne Production Center There is excess facility capacity at the LPC. The original design liquid and gas handling capacities are approximately 100,000 stock tank barrels per day (STB/D) of liquid and 440 million standard cubic feet per day gas. Facility expansion of the LPC is planned to increase the liquid handling capacity to 200,000 STB/D. The planned LPC modifications include additional water separation capacity, inlet header modifications, and produced water treating and pumping capacity. Prudhoe Bay Unit Initial Participating Area CIPA") source water will be used for the Point McIntyre waterflood. There is a potential to convert to the use of produced water at a later date. Possible future LPC modifications include expansion of the existing gas handling capacity. Support Facilities Point McIntyre will share North Slope infrastructure with the Lisburne Participating Area CLPA") and the IPA to minimize duplication of facilities. These include the co- user camp core facilities, potable water and waste disposal facilities, shop and maintenance facilities, certain roads and bridges, crawlers, operations vehicles, module movement and placement equipment, airstrip, construction pad, storage and warehouse space, fire fighting equipment, medical facilities, oily waste disposal facilities, living quarters, and telecommunications systems. Production ,~dlocation The production of oil and gas, including those hydrocarbon liquids reported as NGLs by the producer, will be allocated to the Point McIntyre Participating Area in accordance with conditions approved by the Alaska Department of Natural Resources, Alaska Department of Revenue, and Alaska Oil and Gas Conservation Commission. One test separator at PM-1 and two test separators at PM-2 will be utilJ, zed. Gas Sales Point McIntyre gas sales would utilize a gas flow line in which the LPA has pre-'' invested for connection into a future gas processing facility. The timing of gas sales is dependent upon market demands and the availability of a transportation system. Prior to initiation of gas sales, the Pt. McIntyre produced gas will be used or consumed for Unit Operations, or injected into another formation underlying the Unit Area as dictated -2- Pt. Mclntyre Provisions (March 1, 1993) by the desirability from a reservoir standpoint and the availability of such facilities. Fuel will be provided to the LPC as per the LPC facility sharing provisions. Enhanced Recovery Techniques Enhanced recovery techniques such as miscible gas injection will be evaluated in the future to determine the potential of increasing the economic recovery of the Point McIntyre Reservoir hydrocarbons. The source of the miscible injectant may be from processed Pt. McIntyre gas or by purchase from an outside source. MAC\ MPWXExhibit 76-D, PMOA 199 -3- Exhibit 76-C Log Denoting Pt. Mclntyre Reservoir Pt Mclntyre #11 0 ~- =--:~-~'~~.if~- HRZ .... i :.;.7-?-.&~-~7--. =.~-~.- :"~ .. ......... :... ' ' ~ .... ?..,...~,~7-~z~ 9908' MD I :~~= ~" ~' :- ..-~-~"~-~~.~*,,~ Kalubik -8649.5 ........ L,...~ .~ ...... ;': ..... -~4-~.:.*:. ~-:--,.,~,-~ ~-~ ~ .,- .,. ~ ......... ~,,~ FM : : '-~ .... ~,,~ -++~+.+~~~.~, ,~., ~, ~ ~ , .... ~ .... ~._..~~ ......... ~ ...... : ...................................... ~'~"~ ............................ - ' .: ?;E;~i~ i;.~;i i': :.~,,: ~:-.~.,. ... T ......... : ............ ~~ ................ , ...... :,o,,. . ..~ ..... A'~ ..... ~..: ...~..~--. - ,z:~,~ o~ EL.~¢_~~~ .... o =--.~:~.--~ .... ~-: ~ Ku paru k .,,..,, , , _ ~~~~ ~ FM .... ~,~.~.~~i~ . : ~ ~ ;.:~.~.~ I _ ~ ~:1' ; -I~-~ '~ " ' ~ ~~, ~ I ' ' , + ~~ ~ :.z:~,..,:,~.~.,~, ,,~, , , ,, 10,665 MD , , ; , il';[: ~i if -+H : Tl 'll~ ] ]~ i i i. I i i II ,, ~ i , , ~ , _ ~ , , i ii i i i ' ' ~ '~r~ .... :~ ~ ,. ' -- · , : -i ' , , ; ~ , ,']; , ,, , . ~ ; ' ' ; - ~ 71: . '--* ...... ; ' ; : - ,, , ~-"Tq"T': ; ; ';; ;; ;-] Pt. McIntyre Provisions (March 1, 1993) Exhibit 76-D to the Point Mclntyre Provisions Exhibit E-4 to the Prudhoe Bay Unit Agreement PLAN OF DEVELOPMENT AND OPERATIONS FOR THE POINT MclNTYRE PARTICIPATING AREA Initial development of the Point Mclntyre Reservoir includes drilling of 80-acre spacing wells directionally drilled from two drill sties, PM-1 and PM-2. The planned start-up date is August 1993. Waterflood operations will be implemented in the down-structure portion of the reservoir after field start-up. Produced gas in excess of lift and fuel gas requirements will be injected into the Point Mclntyre gas cap or sold. Point Mclntyre production will be commingled with Lisburne production at the Lisburne Production Center CLPC"). The production will be allocated to Point McIntyre in accordance with conditions approved by the Commissioner of the Alaska Department of Revenue, the Alaska Department of Natural Resources, and Alaska Oil and Gas Conservation Commission. Sharing existing production facilities is possible due to the excess LPC capacity. Wells Twenty Point Mclntyre wells have been drilled to date (Attachment 4a). Additional development wells are being drilled to an expected nominal spacing of 80 acres. Drill Sites Point Mclntyre drill site locations have been selected to take advantage of existing gravel to minimize new gravel placement. PM-1 is located at the existing Point Mclntyre exploration pad. PM-2 is located at the existing West Dock Causeway. Dockhead #3 is being expanded to accommodate drill site facilities and maintain barge docking functions (Attachment 4b). Power to drill sites will be provided by extending existing Lisbume power lines to Point Mclntyre drill sites. Water will be injected at both drill sites for waterflood operations. Produced gas in excess of lift and fuel gas requirements will be injected into the Point Mcintyre reservoir at the PM-1 drill site. Lift gas will be used at both drill sites. PM-1 will have 24 well slots and PM-2 will ultimately have approximately 60 total well slots. The Point Mclntyre produced gas will be reinjected at PM-1 utilizing one gas injection well initially, with the potential need for an additional gas injection well in the future. Ex,=ting Wells in the Proposed Pr. Mclntyre Participlating Area ____ Attachment 4a NE 34623 Proposed Pl. Mclnlyre Participating Area Il · · i I I I I I · P2-51 ~ Pl-16 ~ PI-Il II II i i · i EXX 34622 · P2-55 · PM7 ~ PM9 ~ PM6 ~1 P2-4g ~ PM13 AAI 375138 Lease LJnes ~ ~ Pl-14 O PM11 PM 4 P2-30 ~ PMS~i ~ P1-G~ PM 3 ~ PM10 ~ PM5 P2-48 I P2-50 A/E 28298 A/E 28297 A/E 34624 AJE 34627 0 Exislin9 Wells ~I' Currenll¥ Drilling Shoreline POINT MclNTYRE ! ...... -,...::., EXPLORATION PAD ! DRILLSITE PM1 ! ! ! LEGEND EXISTING FACILITY EXISTING PIPELINES FUTURE PIPELINES EXISTING ROADS FUTURE DRILLSITES "i LISBURNE ':'/ PRODUCTION ~ CENTER ~1~'' :: ~ SOURCE WATER I"'1 INJECTION PLANT DS-L3 DS-L5 DS-L4 Pt. McIntyre Provisions (March 1, 1993) E__~_IBIT 7 6-E AGREEMENTS RATIFIED AND/OR SUPERSEDED · Letter Agreement for Sharing Initial Participating Area Equipment and Facilities with the Lisburne Owners, dated October 15, 1985, effective October 25, 1985, as amended · Letter Agreement between Exxon Corporation and ARCO Alaska, Inc. for drilling Point McIntyre No. 3, dated December 11, 198~7. · Exploration Program Agreement, Pt. McIntyre Area, North Slope, Alaska, signed February 22, 1989 and effective January 1, 1989 · LPA 89-7: Ballot Agreement for Handling of Produced Fluids, effective February 24, 1989, as amended · Well Data Trade and Equalization Agreement, Pt. McIntyre Nos. 6, 7 and 8 Point McIntyre Area, North Slope, Alaska, effective December 1, 1989 · Agreement Regarding Use of the West Dock Staging Area, Docks, and Causeway, effective January 1, 1990, as amended · Pt. McIntyre ~7 Well Operating Agreement, effective January 1, 1990 · Pt. McIntyre Interim Cost Sharing and Operating Agreement, effective December 15, 1989, dated January 20, 1990, as amended · LPA 89-16/IPA 89-103, Ballot Agreement for Sharing of PBU Facilities and Equipment by Exploration Operation Operators, effective January 12, 1990 10. Pt. McIntyre No. 11 Well Operating Agreement, effective January 1, 1991 11. LPA 90-124/IPA 90-022, 1990 Ballot Agreement for the Sharin~ of Prudhoe Bay Unit Facilities and Equipment by Exploration operator, effective January 2, 1991 12. McIntyre #9, #10, #11o West Beach #4 Well Data Exchange Agreement, dated April 1, 1991 2O4 Pt. McIntyre Provisions (March 1, 1993) 13. LPA 91-26, Ballot Aqreement for Sellinq of Lisburne DS-L6 Equipment to the Point McIntyre Owners, effective August 19, 1991 14. LPA 91-28/IPA 91-141, Sharinq of PBU Facilities and Equipment by Exploration Operator, effective October 28, 1991, as amended 15. Point McIntyre Aqreement Reqardinq Interim Funding, Final Equity Determination, and Facility Sharinq, dated April 28, 1992, effective January 17, 1992 16. Article 53 of the Lisburne Provisions to the Prudhoe Bay Unit Operatinq Aqreement, as amended on April 28, 1992, effective January 17, 1992 17. IPA/LPA Infrastructure Resolution Letter of Intent, dated January 29, 1993 2O5 AMENDED EXHIBIT 78-A PT. MCINTYRE PARTICIPATION AND PT. McINTYRE VOTING INTEREST OF THE PT. McINTYRE OWNERS (Amended to Reflect Final Equity) Pt. McIntyre Owners .° ARCO BPX Exxon Pt. McIntyre Participation and Pt. McIntyre Voting Interest 30.1% 32.2% 37.7% 206 Pt. McIntyre Provisions (March 1, 1993) EXHIBIT 81-A PT. McINTYRE RESERVOIR DEVELOPMENT OBJECTIVES AND DEPLETION PLAN The Pt. McIntyre Reservoir Development Objectives are the long-term objectives of the Pt. McIntyre Owners for Hydrocarbon Fluids and Gas production to the extent achievable through the use of wells and facilities approved from time to time by the required votes of the Pt. McIntyre Owners. The objectives, as of the PMPA Effective Date, are described below: Achieve the maximum economic recovery of Hydrocarbon Fluids and Gas within the constraints on logistics and technology imposed by the Arctic environment. b · Achieve and sustain an optimum Hydrocarbon Fluids production rate, up to the limits imposed by the production facilities and wells and a management plan agreed to by the Owners. C · Inject produced Gas, if in excess of Gas taken or separately disposed of by the Pt. McIntyre Owners and fuel requirements, as appropriate. d o Process gas for recovery of gas liquids and condensate for sale. e o Recover Gas for sale, dependent upon availability of a market and transportation system to a market. f · Dispose of produced water and waste products in accordance with governmental regulations. g. Explore the feasibility of enhancing the economic recovery of Hydrocarbon Fluids and Gas through any appropriate means. 207 Pt. McIntyre Provisions (March 1, 1993) EXHIBIT 81-B INDEXING OF OPERATOR EXPENDITURE AUTHORITY This Exhibit 81-B sets forth procedures for revision of Operator Expenditure Authority referred to in the Pt. McIntyre Provisions. Such revisions will be made, if required, to account for changes in inflation rate as determined through application of the Producers Price and Price Indexes for Industrial Commodities (WP) as published by the U.S. Department of Labor, Bureau of Statistics. For the .~omputations set out below, the PPIs to be used are based upon the 1967 = 100 based PPI. If at some future time the PPI is published for a different standard reference base than 1967 = 100, the PPI will be converted to the 1967 = 100 base using the method suggested by the U.S. Department of Labor, Bureau of Labor Statistics. If the PPI should cease to exist, the Pt. McIntyre Owners will select some other suitable reference guide to take account of inflation. The Operator Expenditure Authority as referred to in the Pt. McIntyre Provisions will be increased in $50,000 increments to the greatest amount that does not exceed the value of the following expression: (The then current PPI) x ($750,000) PPI for January 1981 At the time of the PMPA Effective Date, the Operator Expenditure Authority is $900,000. There will be no 'reduction of the Operator Expenditure Authority due to decrease in the PPI. 2O8 Pt. McIntyre Provisions (March 1, 1993) EXHIBIT 82-A SAMPLE CALCULATION OF EFFECTIVE HEATING VALUE ADJUSTMENT FOR FUEL SUBSTITUTION Assumptions: Effective heating value of Pt. McIntyre fuel for which fuel is being substituted Effective heating value of substitution fuel Volume of substitution fuel Equivalent volume of substitution fuel after application of effective heating value adjustment 10,000 MSCF * 1,080 Btu/SCF = 11,429 MSCF 945 Btu/SCF 945 Btu/SCF 1,080 Btu/SCF 10,000 MSCF T-'!~L~H :RDGCC . 276-?542 3UL( $'35 15:26 RE-( EIV D $ E P - 8 t99~ STATE O~ ALASKA 0il & Gas gens. C;ommiSSiO" O~ ~ GA~ CON~VA~ON COMMISSION 3001 Porcupine D~ve .Anchorage ~nchorag~ ~as~ 99~01-3192 The Application of ARCO Alaska. ) Inc. to present testimony for ) clusification of new oil pools and to ) prescribe pool rtllel for development of ) thc Pt. Mclntyre Oil Field. ) Conservation Order No. 317 Pt, M¢Intyre Oil Field Pt. Mclntyre Oil Pool Stump Island Oil Pool IT APPEARING TI~T: July 2, 1993 By letter dated Sanuary 15, 1993, ARCO Alaska. Inc. requestsd a public hearing to present testimony for establishins pool rules for development and operations in the Pt. Mclntyre oil field, located in T12N, R15E and TI2N, RI4E Umiat Mm'idian. 2, Notic~ of public hearin~ to be held on March 24. 1993 was published in the An~oraso Daily News on Pebmm'y 5, 1993; o A hearing concerning the matter of the applicant's request was held in conforman~ with 20 AAC 25.540 at the Fairview Conununity Recreation Center, ! 121 East 10th Avenue, Anchorage, Alu~ 99501 at 9:00 a.m. March 24, 1993. The hearing record remained open until the (:lose of buaiiless Ay 14, 1993. FINDINGS: ARCO Alaska, Inc. has been designated operator of the Pt. Mclntyre oil field by working interest owners ARCO Alaska. Inc., BP Exploration (Alaska), Inc., and Exxon Corporation. i Oil within thc Pt, Mc,~ym reservoir is trapped in the Kupamk River and the Kalubik formations. The vertical limits of tbs Kupangt River and Ktlubik formations may be de. ed in the P~. McIntyre No. 11 wcll, which appears to be & typical and representative well. . Oil within the Stump Island reservoir is stratilp*aphically trapped in discontinuous sandstones of the Seabee formation. Thc vertical limits of tho Stump Island rcse~oir may bc d~nod in tho Pt. Molntyri No. 3 well, which appears to bo a typical and representative well. ' 4. The Iiuparuk River formation is present throughout the Pt. Mclntyre area and is characterized by rapid chan~es in thickness, lithology, and dc~oo of cementation. 210 1 Tho ]Caiubik formation exhibits abrupt r, ha~. in lithololiy sad thiok~Sl wis oil boarin~ sandstones restricted to the western portion of the Pt. Moh~ryre oil tleld. P .01 -ROM AOGCC Conservation Order No. 317 Pt. Mclntyre Oil Fie. Id 276-7542 -2- ;UL 5 '93 13'26 No.OOl'P.02, July 2, 1993 , The Stump Island reservoir is of limited and varicd areal cxtcnt within the Pt. Mclntyre oil field. Development of thc S~mp Island reservoir will initially be ~valt~atod on a w~ll-by, well buis in conjtmGtion with 1'~, Mclntyre reservoir dcvclopmcnt. . Seabee sands are separated from the Kuparuk sands by a series of Cretaceous marine shales which range from approximately fifty to more than two hundred rut thick, An oil column in the Stump Island reservoir overlies a gas cap and oil column in the Pt. Mclntyre reservoir. . Insufficient subsurface data currently exists to accurately characterize the Stump Island reservoir or estimate thc total volume of hydrocarbons in place. Known res~ves are minor in relation to those of the Pt. Mclntym reservoir. 10. The Stump Island reservoir has been penetrated in four of the 21 wells drilled within thc Pt. Mclntyre oil field area to date.. Only the Pt. Mclntyre No. 3 well proved capable of hydrocarbon production from the Stump Island reservoir. 11. The productive interval in Pt. Mclntym No. 3 Is thought to be an isolated occurrence. Subsurface information indicates a lack of continuity between the Stump Island reservoir interval in the Pt. Mdntyre No. :3 well aild adjacent wells. 12. Those wells encountering both Stump Island and Pt. Mclntyre productive intervals will be completed to allow for independent testing of each interval. 13. The Pt. Mclntyre reservoir is controlled by a north plunging anticline with fault olosur¢ to tho south across the large displac, mnunt Pt. Mclntyre fault, pmphsrai reservoir quality degradation and stratigraphic truncation of the reservoir along its eastern flank. 14. Numerous moderate displacement normal faults cut the Pt. Mc, Intyre are~ reservoirs. Fluid contact and pressure dam indicate these flmlts ar~ non-sealing. 15. Net pay determination in the Pt. Mclntyre reservoir is primarily controlled by 1) oil- water contact elevation, 2) distribution oflithologics and 3) degree of intergranular cementation. 16. The Pt. Mclntyre owners propose development activities for those portions of the Pt. Mclntyr6 rcm'voit with greai~r than five net hydrocari~on pore fm sa delineated from pr~scatly available subsuflhr, e data.. 17. Core data shows average horizontal pcrmeabilitiea range from 50-300 tnillidarcies in the Upper Kupamk and 100-600 millidarcies, in the Lower Kupamk sands. Vertical ~ ]_ 1 psrmsabilities range from 1-~0% of horizontal pmneability, .?6-?542 ..TUI_ ( .... Conservation Order No. 317 Pt. M¢Intyre Oil Field 15'27 No.O01 -3- 3~y 2, 1993 18. The operators define net pay as reservoir rock with permeability > 10 md, to air at roservoir conditions. Net pay to gross interval ratio ranges fi.om 0.2-0.8 (0.55 average) in the Upper Kupa~k ~ fi.om 0,7-0.96 (0,87 average) in the Lower Kuparuk. 19, Average porosity ranges from 19-25% in the Kuparuk 1Liver sands. :20, Initial water saturation ranges from 15-65% (33% average) in tho oil column end less than 15% in the Itu column. 21. Laboratory waterflood displacement and centri~ge tests indicate residual oil saturation will range fi.om 10-30%. 22. Based on Amott tests on core fi.om Pt. Mclntyre No. 5 and No. 6, the Pt. Ntclntyre reser.;oir was detm'minod to have int~trd~Uo wetability. 23. The Sas-oil-contact (Gl}C) in Pt. Mclntyr~ No. 3 is et 8582' Tv'Dss and is considered to be planar throughout the Pt. Mclntyro reservoir. 24. The OWC ranges from 9035-9122' T'v'Das and is subject to varyi,g thickness of transition zone throughout thc pool. Tho owners have staved &t a consensus planar contact at 9069' TVDaL 25. Initial reservoir pressure is 4377 psis calculated to a datum of 8800' TVDss. Initial reservoir temperature ranges fi'om 17~-184 °F et 8800' TVDss, 26. Pt. Mclntyrc reservoir oil gravity is 27 °API, solution gas-oil-retie is 806 $CF/STB, r'brmation volume factor is 1,39 RB/STB, and ~scosJty la 0,9 cefltipoise at the bubble point pressure of 4308 psis and ros~rvoir t~mperature. 27. Estimates of oflgir~l oil in place (OOIP) J. the Pt. Mclntyre reservoir range from 750.800 NRviSTBO, orisinal Sis in place (O(~XP) ~om 750.870 BSCF of which 160- 240 BSCF is non &,~o~atod free ~ 28. Test rates range fi'om 600-6000 BOPD from the Pt. Mclntyre reservoir. Calculated productivity indic~ ranged f~om 0.$-13 BPD/PSI. 29. Primary drive mechanisms in the Pt. Mclntyrc reservoir ere Sss cap expansion end solution gas drive. 30, Pressure mamtenanc, o Ltd onhan~ oil recovery plans in the Pt, Molntyro reservoir are to inject produced tpts into the pa c~p and waterflood tho reservoir usin~ an inverted nino spat pattern. (hs injection will besin with regular produotion arid waterflood is expected to start within onc year of initial production. 212 P .03 FROM F~OGCC 276-7542 JUL S'93 13'27 No.O01 'P.04, Conservation Order No. 317 -4- July 2, 1993 Pt. McIntyre Oil Field . 31. Each working interest owner developed an independent three dimensional model of th8 Pt. Melntyrs ru,rvoir to study reservoir ma~isms, estinmte r,cov~ss ad optimize Facility design. 3 2. Results of model studies from the owners indicate primary depletion with gas cap injection would yield recovery of 20-25% OOIP. Enhnnced recovery with pattern wateffiood and Ss~ injection increases recovery to 4245% OOIP. 33. Sensitivity studies indicated no impsct on ultimate recovery using field o~nke rates fi'om 50-160 MBD. 34. Perforation stand off from GOC a~t OWC will be determin~l based on rock quality and prcsence of flow baiTiers in order to mitigate gas and water coninl~. 35. Well spacing will depend on fault location, reservoir rock properties and estimates of sweep et'liciency. Spa~mg of 40 acres p~r well rely be required to a~oommodate localizcd conditions. 36. Fail s~e surfaco sa.f'oty valves (SSV) md subsurikce s~ety valves (SSSV) will be installed in all wells capable of unassisted flow of hydrocarbons to the surfaco. 37. 35. 39. Certain well operations will require temporary removal of the SSSVs to allow ps, saSe o£ equipment ~nd performance of operations. Reservoir surveillance will consist of monitoring reservoir pressure in both the Pt. Mclntyre and Stump Isl~nd reservoirs. Alienated production volumes, based on well test data will be reported monthly and u~ed to track individual well oil, gas, water and GeR. behavior as well as beh~tvior of the entire reservoir. GOC ~nd production profile programs lmve not been completed as yet Production from the Pt. Mclntyre and Stump Island pools will be comminsled with production ~rom other oil pools at tim Lisburne Production Center O,~C). Process capacifics at LPC will bc incrcased from 100 to 135 MBPD oil and fi'om 25 to 200 MBD water. G~s processing capacity is expeoted to remain at 460 MMSCF/D. Facility expansions are ~xpeoted to be completed in 4th Quarter 1994, Produoed g~s from LPC will be injected into th~ Lisbume and Pt. M~Intym pools proportion~[ to their produced volumes. 40. Monthly well tests will be used to allocate production to e~ch producing well. 41. Well test facilities will be installed at Pt. Molntyro drill ~it~ I ~d 2 to faoilit4tu well tests for allocation purposes. 42. 213 Optimusn w~ll tut stlbiliz~tion md duration ttmaa will vary from w~ to well and rn~y chnnge with time. Well testin6 8uidelin~ for Pt. Mclntyro wells must be determined a~er start of' production. 276-7542 JUl_( $ 93 Conservation Order No. 317 Pt. McIntyre Oil Field 13'28 No.O01 -5- July 2, 1993 43. An NGL process simul~t:or will be utilized to determine and allocate NGL volumes. 44. The Lisburne Data Gathering System 0'-riGS) will be expanded to accommodate the Pt. Mclntyre drill sites. The LDGS will continuously monitor the ilowing status, pressures and tomperature~ of producing wells. 4:5. H2S has been de~ected at low levels in well Pt. Mclntyre well P2-$5. 46. H2S levels are expected to rise over the life of tho pool because of 8u injection and water i~eotion from the I, PC. The operator plans to follow APl RP 70 Section I to rniti~,te drill string corrosion and sulfide strOllS orgking. 47. The proposed area of development for the Pt. Mclntyre oil field is not committed to ,, unit, nor has a participating area been app;oved for this field by the state. 48. The Pt. Mclntyro working interest owners have applied for expansion of the Prudhoe Bay Unit to include tho proposed area of development for the Pt. Molntyro oil field. This expansion, u proposed, would include the participating ares(s) for the field. 49. The application for ~xpansion of tho Pmdhoe Bay Unit and formation of the Pt. Mclntyrc participation are· is under review by the Department of Natural Rzaources, ~t date of this order. $0. Pt. Molntyre drill site 1~ is legated on · 8mvol ex, lesion from tho sum made Rut Dook causeway whioh extends into tho Bcaufofl SoL 51. Wells chilled from Pt. Mclntyre drill site 2 during tho course of delineation and development to d~te have had surface casing set at depths between 2612.431t9' TVDss with condu~ors set between 75-I 16' MD. 82. No hydrocarbons or abnormal pressures haw been encountered above 5000' TVDis in tho Pt. Molntyre wells drilled to date. CONCI,USlON$: 1. Pool rules for d~velopm~nt of the Pt. Mc, Int]~ and Stump Islazal r~servoirs are · ppropriato at this time. , The unitizcd management, operation and further development of the Pt. Mclntyre and Stump Island oil pools is reasonably necessary to effectively catty on pressure maintcnmzcc and enhanc~ oil recovery operations to maximize ultimate recovery. 3. An intoaration of [nmst between tho working interest owners ami royalty owner appears to be in question as ofthis d~te. Well ape;ins of 40 a~res per wall is reasonable to Kcornmodato faulting, secondary recovery patterns and reservoir rock characteristics. · P .05 FROM a06CC 2T6-7542 gUL 5'93 13'29 No.O01 Conservation Order No. 317 -6- July 2, 1993 Pt. Mclntyre Oil Field , 5. Watefflood and gas injection will cnha.nce oil recovery for the Pt. M¢intyre oil pool. 6. Oil recovery from the Stump Island oil pool cannot be quantified becauae of lhnited areal extent and variable characteristics. 7. Pt. McIntyre and Stump Island oil pooh are not in hydraulic communi~tion. 8. Development oflmown reserves in the Stump Island oil pool is not likely without welibore conumngling with Pt. Mclntyre oil pool production. 9. Future drilling ~d production data are rmeded to adequatcly dana size and extant of the litump Isled oil pool. 10. Fail safe surface safety valves (SSV) and subsurface safety valves (SSSV) are reasonable in wells capable of unassisted flow of hydrocarbons. 11. Exception to 20 AAC 25.240 governing l~s-oil-r&tios is appropriate because produced gas injection into the pool will ~tart immediately and enhanced oil recovery operations are expected to begin within one year ofhfitial production..' 12. Surfitcc cmmningling of the production from Pt. Mclntyrc oil field within the LPC will increase ultimate recovery, will not cause waste nor jeopaxdiza correlative rights. 13. Periodic review of production allocation procedures is appropriate to evaluate techniques ~d to revise procedures ifwarranted. 14. Conductor casing set at least 75 feet MD provides adcquato anchorage for a d/ratter system, structural c,~in8 is not needed. 15. Surface casing can be set to a depth of 5000 feet TVDss because of the absence of shallow hydrogazbons and ~nonn~l pr~sure zone~. NOW, TREREFORE, IT IS ORDERED TI=tAT the rules hereina.Rer set foffi~, in addition to state-wide requirements under 20 AAC 25 apply to the following affected m-ea referred to in this order: Umiat M~-idian P .06' T12N R15E Section 18 All. Section 19 NI/2. T12N RI4E 215 Section 13 All. .. Sc;fica 14 All. Section 23 NIl2 NWII4, Nl/2 NEll4, $W1/4 NWl/4. S~tion 24 NI/2. ~,'FROM ROGCC ~," 276-7542 Conservation Order No. 317 Pt. Mdntyre 0il Field TI2N RI4E Section 15 Section 16 Section 21 Section 22 T12N R14E Section 17 TI2N K14E -7- :, '93 All All N1/2 NE1/4. N1/2. 13'31 No.O01 July 2, 1993 NE1/4, NIl2, SE 1/4, El/2 El/2 NWl/4, El/2 NE1/4 SW1/4. Section 3 ~ Sec,,ion 4 Atl. S~ction 9 All. Section 10 All. P.iO Those Lands in Block 605 lying northerly of the north boundary of Section 3, T12N, R14E, UM, AK. (Identical with line 4-5 on ]]lock 605) and lying oMterly of the west boundary of Sections 2 and I1, T12N, R14£, UM, AX (Identical with line 5-6 on Block 60:J) and lying nonhm'ly of'the ~outh boundary of Section 11 and 12, T12N, R14E, ~ AK, and lying noaherly of'the south boundary of'Section ?, T12N, R15E, UM, AK (IdenticAl with line 6-7 on Block 605), within the oF. shore three-mile arc lines listed as State Area on the "Supplemental OfficiAl O.C.S. Block Diagram," &pproved 12/9/79, containing 1457.32 hectares. Rule ! lntegr.,ation ofhter~itS Regular production may not be~n until the interests of'the working interest and royalty owners are integrated in a:cordance with the provisiotu of 20 AAC 25,517. Rule 2 Field and Pool Names , The fl~ld tm the Pt. Mclntyre oil ibid. Hydrocarbons uontamed within the Kuperuk River and Fdlublk formations constitute a single a#odated ~u and oil reservoir called the Pt. Me. lntyre oil pool. Hydrocarbons contained within the Soabee formation constitute a single associated gas and oil reservoir called the Stump Island oil pool. Rule 3 Pool Definition The Pt. Mclntyre oil pool is defined as the accumulation ofhydrocarbons common to and which correlates with the interval from 9908 to 10665 foot measured depth in the ARCO Pt. Mclntyre No. 11 well. I The Stump I~and oil pool ia dctmed aa the a~umulation ofhydroctrbons common to and which con'elates with the interval from 8759 to 8930 foot measured depth in the ARCO Pt. Mclntyre No. 3 well. 2 1 ~ R~le 4 =Well Spacin~ ~:ROM AOGCC I ~76-7542 fUL }'93 13'30 No.O01 P.08 Conservation Order No. 317 Pt. M¢Intyr¢ Oil Field -8- July 2, 1993 The spacing unit shall bo one producing well per 40 acres or quarter-quarter 8overnmental section. No pay shall bc opened in a well clol~ than 500 feet to the boundary of the affected aze~. Rule 5 C~sing and Cementing a. A conductor casing shall be set at least 75 feet below thc surfacc and sufficient cemem shall be used to fill the annulus b~hind the pipe. Ce~nent to surface shall be verified by visual inspection. The Commission may administratively waive or approve other conducwr lotting depths and sealin$ methods that are supported by sound cnginoenn~ principles. b. Surface casing shell be set at least 500 feet MD below the base of the permafrost but not below 5000 f~ct TVDss. Sufficient o~msnt shall be used to fill ~ ~mulus behind the cssing to the surface; if complge fill-up is not chinned, a top job will be performed before proceeding with drilling operations. c. Structural casing is not required. Rule 6 Completion Practices. Wells completed for production may utilize cuing strings or liners cemented through the productive intervals and perfomed, slotted liners, sc. reen-wrapp0d liners, ~rsvel pscks or open hole methodn, or combinations thereof, Rule 7 Drilling and Production Equipment Drilling tnd production equipment must meet the requirements of AP1 RP 7G, Section, "Drillstem Corrosion and Sulfide Stress Cra~:king," curp.'nt edition, Rule 8 Automatic Shut In Eouinmen_t a. Upon completion, each well which is capable of unassisted flow of hydrocarbons to the surface shall be equipped with: a fail-safe automatic surface safety valve (SSV) capable of preventing uncontrolled flow. a fail-safe automatic subsurface safety valve (SSSV), unless other typea of subsurface valve are approved by the Commission, shall be installed in the tubing string below the brae of the perm.'oat n.nd be capable of preventing uncontrolled flOW. bo A well that is not capable of unassisted flow of hydrocarbons, as determined by a "no flow" performance test witnessed by a Commission representative, is not required to have tail-safe automatic SSSVs. Conservation Order No. 317 Pt. Mclntyre Oil Field -9- July 2, 1993 C, SSSVs may be temporarily removed as part of routine well operations without specific notice to, or authorization by the Commission. Rule 9 Wellbore Commin~lling Production ti'om the Pt. Mclntyre and Stump Island uti pools my be commingled in the weilbore of the Pt. Mclntym No. 3 well, Allocation to each pool may be determined by production profile surveys or separate zone well tests. ii. The Commission ma)' require additional production surv¢iilan~ methods artd my administratively accept alternative methods of allocation of wellbore commingled production upon application by tho operator. b, Additional wells may be approved administrativdy for wdlbor¢ commingling on a case-by,case basis upon application to the Commission, Rule 10 .i_ur£ac.c_.C..Plnmi~lin~ and Common. l~adlities. a. Productiun lirotn the Pt. Mclntyre and Stump Island oil pools may be commingled on the surface with production from other pools at tho LPC prior to ~ustody transfer. be Production from ench well will be determined by the following well trot alloo~tion methodoloSy. Allo~tion data md wall :alt data will be supplied to the Conunimon montkly in both computer file and report formats, i. Conduct well t#ts to determine production rates for each well. ii. Cal~late each well's theoretical montltly production (TMP) based on well test rate(s) and ~tual time on production, iii. Sum the TMP volume for ali wells in all pools. iv. Detmminc an allocation factor as thc ratio of thc metered volume to the TMP for all wells in ali pools (i.e., metered/TMP) v. Calculatc cach well's actual monthly production (AMP) volume as: AMP - TMP x AlloCation Factor c. N(3Ls will be allocated to ~ pool based on a~mal gas production volumes and NGL process simulations. Process simulations will be updated at least once per year based on NGL samples and results reported to thc Commission. d. l~aah produeins will will be testld st lima twirl sash month, WeLls that have been shut in and cannot meet the twice monthly test frequency must be tested within five No .001 P.11 FROM ~OGCC ]. 2?6-?542 }UL 3'9~ i$'$2 No.O01 P.12 Conservation Order No. 317 -10- July 2, 1993 Pt. Mclntyre Oil Field , days of startup. All available test separator capacity within the constraints imposed by operatin8 conditions must be utilized for well testing. e. Optimum test duration and stabilization time will be determixled on a well by well basis by tha operator. £ Water volumes will be d~armined by API/MPM$ approved mgthods, or the uso of industry proven, on-line water gut measurement devices. go APl gntvity will be determined for each producing well annually by an API/MPMS approved method. h. Gas samples will be taken and analyzed for composition from oa~:h non gas lifted produoinl~ wail yea~'ly. i, Quarterly allocation process reviews will bo held with :he Commission. j. This rule may be revised or rewritten after an evaluation period of at least one year. Rule._l 1_ Production Ano.ma. lies la tho event of oil produotion capacity proration at or t~om the LPC, all oommlnBled pools produced at the LPC will be prorated by ~ equivalent pereentage of oll production recognizing mechanical limitations and operattorud constraints. Rule 12 Reservoir Pressure Monjto~ng a. Prior to regular prodm;tion, a pr#sure survey shall be taken on e~oh well to determine the reservoir pressure. · b. A minimum ut'one bottom hole pressure survey per producing 8ovemmental section shall be run mmually. The surveys in part a. of this rule may be used to fulfifl the minimum requirements. c. The datum/'or all surveys is ii00' TVDss. d. Pressure surveys will be either a pressur~ buildup, pressure fallofl~ RFT, or static bottom hole pressure tiler the well has been shut in for an extended period. Tile pressure surveys will be reported to the Commission quarterly. Commission form 10-412, Reservoir Pr,sure Report, shall be used to report results ii'om these surveys. All data necessary for complete analysis of' each survey need not be submitted with the /'ore 10-412 but must be submitted upon request. Results and data fi*om an)' tp~ial reservoir pressure monigorip$ toc, hniqu s, tom, or surveys also shall be submitted in aooordtnoe with part 'o' of'this rule, ~FROH ROGCC J'UL{' J ' 93 276-?542 13:32 Conservation Order No. 317 Pt. M¢lmyre Oil Field - 11 - July 2,1993 Rule 13 Gas-Oil -Ratio Exemption Wells producing l'rom the Pt. Mc, Intyre and Stump Island oil pools a~e exempt f~om the sas-oil ratio limit set forfla in 20 AAC 2f240(b) so long as the provisions of 20 AAC 25.240(c) apply. .k~le 1 ~. Aflministra~iv_e Actio_n Upon proper application, the Commission may administratively waive the requirements of any rule stated above or administratively amend this order as long as the chan~e does not promote waste, jeopardiz~ correlative rights, and is based on sound enl]ineerin$ principles, DONE at Anchorage, Alaska and dated July 2, 1993. .... Alaska Oil'~!._~ons.rvation Commission Russell A. Dou$1~s, Con,.mi oner Alasl~ Oil and Gu Conservation Commission No .001 P.13 ckarrnm Babcock, Commissioner Alaska Otl and Gas Conservation Commission _ _ I i i ii I____IL ii I I~ il ..... "Wi% ~o d.v, ,~.~ n~.p, .t,,~."" .0~ o~ ,..~ o~ ~, o,d,~ · ~,o. ~ ~ i, my file ~th t~ Co~islion m appli~tion for rehmg, The Co.salon shgl ~mt or r~se the nppii~ion in whole or in pan ~thin 10 days. ~ Co~sgon em r~se ~ apportion by not ~ ~t~ ~e lO day period. ~ ~ted pe~on ~ 30 days ~om · e da~ ~t the Co~ission's r~ of the ~pplication or order upon reh~n~ ~o~ bei~ ~e ~at order of the Con.ion) is ~1~ or othe~se dis~but~ m app~ ~e d~i~on to the super ~un. ~e a r~ue~ for rebea~n~ is d~ by ~~on of~e Co~asion. ~e 30 day p~od ~or appe~ io sup~or court runs ~m ~n ~t~ o~ w~ch ,~e ~qu~,st is d~m~ den!~ {i.e., 1 ~h da~ ~er the application for r~~ ~ filed}. , 220 ALASKA OIL AND GAS September 8,~SERVATION COMMISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 Harry A. Noah, Commissioner Office of the Commissioner Department of Natural Resources P.O. Box 107005 Anchorage, Alaska 99510-7005 Re: Pt. Mclntyre Oil Field-September 9, 1993 heating Dear Commissioner Noah: The Commission has carefully considered your request to defer the September 9, 1993 hearing for two weeks. As you know, the purpose of the hearing is to determine whether any action is required by the Commission at this time to prevent waste, insure greater ultimate recovery or protect correlative tights. You note that ARCO, BP and Exxon are working closely with DNR to try to resolve differences. These differences have remained unresolved for several months. While we encourage your continued efforts to resolve this dispute, the Commission sees no compelling reason to delay its September 9 hearing. Following the September 9 hearing, the Commission will determine if further action is warranted. Should ARCO, BP, Exxon and DNR voluntarily integrate their interests to provide for the unitized management, development and operations of the Pt. Mclntyre lease tracts as a unit, then further action by the Commission may not be necessary. Of course, the Commission reserves the right to review the terms and conditions of any agreement prescribed under AS 38.05.180(p) to insure that the purpose and intent of the Alaska Oil and Gas Conservation Act are satisfied. Chairman BP EXPLORATION ARCO Alaska, Inc. September 3, 1993 Mr. David W. Johnston, Chairman Alaska Oil and Gas Conservation Commission 3001 Porcupine Drive Anchorage, AK 99501-3192 RE: September 9, 1993 Show Cause Hearing Dear Chairman Johnston: The Commission has scheduled a public hearing for September 9 inviting all concerned to show cause as to whether any action is necessary to prevent or to assist in preventing waste, to ensure a greater ultimate recovery of oil and gas, or to protect correlative rights of persons owning interest in the Pt. McIntyre oil field. The producers and the Department of Natural Resources are working on an Amended Application to expand the Prudhoe Bay Unit to include the proposed Pt. McIntyre Participating Area. We hope this can be accomplished before September 9. If the Amended Application does not resolve the matter before September 9, ARCO and BP will be filing a joint compulsory unitization petition requesting the Commission to order expansion of the Prudhoe Bay Unit to include the proposed Pt. McIntyre Participating Area. This petition would be filed prior to the .scheduled show cause hearing. truly yours, /cs E. Golden c: Mr. Harry Noah, Commissioner Department of Natural Resources Mr. James Eason, Director Division of Oil and Gas Mr. Tom Theriot, Exxon BP Exploration (Alaska)Inc. Post Office Box 196612 Anchorage, Alaska 99519-6612 Telephone (907) 561-5111 Co-Operators, Prudhoe Bay Unit A~aska Oil & GaS Cons. Anchorage ARCO Alaska, Inc. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone (907) 276-1215 %?-09-9B ?RI 17:06 DIV OF OIL ~ND (;RS t, FAX NO. 9075829852 P. O1 WALTER J. HICKEL GOVERNOR DEPARTMENT OF ~VATURAL RESOURCES OFFICE. OF Tile COMMi~$1ONER ANCHOR. AG ~_, Ai.,AgKA 995t PHONE: (907) September 3, 1993 David Johnston, Chairman Alaska Oil and GaS conservation Co~mission 3001 Porcupine Drive Anchorage, AK 99501 Re: Pt. McIntyre 0il Field Public Dear ChairmaD Johnmton= whether it neeas to act ~o prevent waste, ~o insure greater ultimat~ recovery of oil and gas, ~r ~o protect correlative rights. I appreciate the. opportunity as ~he Co~mismioner of the Depart. merit of Natural Resources tO comment on tt~ese issue~. It is my view =~at action by the Commission is not n~cesmary now. ARCO, B,P, a~d Exxon are working closely with DNR to try ~o re~olve their ~iff~rences and ~o form a volun=ary unit. We expect to know whether we can resolve the dispute by the week of Septembe~ 13. A~¢ordingly, I would request that ~ho Co~mi~sion defer the hearing scheduled for September 9, 1993 for two weeks. If the state and tt~e ~pplican=s are unsuccessful in fo~ing a voluntary, unit, it is my intent to reql/i~e the applicants to ~ub~ribe to the sta~e's model uni= agreement to form a separate unit outside of the Prudhoe Bay unit to produce oil an4 qas from the Pt. ~cIntyre £tel~. My authority for doing ~0 is AS 38.05.180(p), 11 AAC 83.328(b), and the lease provisions. It i~ a~y ~pinion ~at u~ing the s~ate Rodel ~'orm unit agreement to form a ~epara=e unit is reasonable under the circumstances and wall adequately prote== =~e interest of all partie~, ~nclu~ing [~e state. I remain hopeful that the part~.e~ will be able to reach an. a~reement and =hat =ne fiold will be unitized through the ,9EP.-O3-g3 FRI 17'.07 DIV OF OIL AND P.,AS FAX NO. 9075623852 P. 02 Duvid Jonns=on, Chairman, AOGCC September :3, 1993 Pago ~. voluntary unitization process. Thank you for the upportunity to Sincerely/~~~ James Eaton, D~r~..~.t. or, Division of Oil & James Weeks, ARCO Jack Col d~.n, B.~ Joel Kiker, Exxon c ,:,,,E 0 ?' 1 ,-~ ~.~ ~ ,~, ?., ,,.,. Alaska Oi] :~ ~:~.,~: ~..,:,,.~ ~,~,, (;~.;~,~ ...... .,~, 0.3_ J 93_ _ 02._:_.85_P_1!.. ~P~..l?::lH..R. 6ECl_EH. T_. ( cj07 ) ~E,4-5000 BP EXPLORATION ARCO Alaska, Inc. P. 2./2' s~ptezid:Je~ 3, 1993 Mr. David W. Johns=on, c~a&rman Alaska 0il and Gas Conservation Co~miSsion 3003~ Powcup&ne Drive Anchorage, AX 99S01-319~. Dear Chairman Johnston: £nvi~ing all cones=nad to ~Aow cause as ~o whe=her any action is necessary to prevan= or =o a~i~= in preven=ing wa~e, ~o ensure a greater ultima~e recovery of oil and gas, or to PC. McIn=yre oil fiela. The producers and the Department o£ Natural Resources are working on an A~ended Application to expand the Prudhoe Bay Unit to include the proposed Pt. McInty=e Par=fcipa~ing Ar~a. we hope ~hi; can be accomplished before Sep=e~er 9. September 9, ARCO an~ ~P will be filing a ~oin~ oo~pulsor~ expansion of ~he Prudhoe Bay Unit =o include =he proposed ~t. ~=In~yre Par~ioipa~ing Area. This petition would be filed prior to the scheduled show cause hearing. . D. Weeks /cs . ~. Oolden Mr. Harry No=h, Commissioner Depar~men= of Na=ural Resources Division of 0fl and Gas Tom TArrier, Exxon , Post Off;c~ 8ox i0891 Telepl~one (O0?) 561 , C;o. Operotors, Prucihcm Bay unit ARCO Alaska, Inr,, P~! office Box 100~150 An~otage, Alas~ 99510-0360 TeJepho.e (901) ~76.1~15 '~SEP ~B '~B BP EXPLORATION BP Exploration (Alaska) Ino, 130 Box 196612 Anchorage, Alaska 99519-6612 02: 04PM BPX MAHAGEMEHT (907) 564-5000 TELECOPY COMMUNICATIONS CENTER MESSAGE# P. 1/2 TO: Name: Company: Location' · David W. Johnston Alask Oil and Gas Conservation Commission Anchorage, Alaska ..... ._., Fax # (907) 276-7542 Confirm # _(907) 279-1433 FROM: Name & Ext,: Jack E. Golden Department: End. & Dev. Programs Mail Stop: MB 13-4 ii i i i ii ....... NOTES: PAGES TO FOLLOW .... (Do Not include Cover Sheet) SECURITY CLASSIFICATION PRIVATE SECRET CONFIDENTIAL Telecopy # (907) 564-5000 Confirm # (907) 564-4777 Contact Name: Dawn Conatser #7512 STOF0330 ( .... · 08-5748 $36.10 AFFIDAVIT STATE OF ALASKA, ) THIRD JUDICIAL DISTRICT. ) Eva M. Kaufmann being first duly sworn on oath deposes and says that he/she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anchorage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on August 25, 1993 OF PUBLICATION CHANGE OF LOCA TION OF PUBLIC HEARING STATE OF ALASKA 'Alaska Oil and Gas Conservation Commission GIVEN THAT the Alaska Oil and Gas Conservation 'Commission has changed the location Of the hearing Scheduled for September 9, 1993 at 9:00 a.m. The location has been moved from the COmmission Offices to:the Z.J. Loussac. Library, Assembly ha.mbers, 3600 Denall, ncnorage, AK. SubjeCt Of the em'lng, to show cause as to' hether any action is neces-~ ary to prevent or to assist in reventing Waste to insure at / reater ul.fimate~' recovery otI il and gas, and to protect orrelafive rights of' persons wning interests i/1 the ctn/yre oil field,, has not anged... ' .. ~. questions this the .:'.Any ~uestions regarding. change may. be directed' to C°mmJssi0n by calling (907) '279.1433...: . :. /~?Russell, A. Douglass .commissioner, AlaSka Oil and/ Gas Conservation C0~ission and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Subscribed and sworn to before Notary Public in and for the State of Alaska. Third Division. Anchorage, Alaska MY COMMISSION EXPIRES Alaska Oit & Gas Cons. Gom~tss\o~ Anchorage NOTICE OF CHANGE OF LOCATION OF PUBLIC HEARING STATE OF ALASKA Alaska Oil and Gas Conservation Commission NOTICE IS HEREBY GIVEN THAT the Alaska Oil and Gas Conservation Commission has changed the location of the hearing scheduled for September 9, 1993 at 9:00 a.m. The location has been moved from the Commission offices to the Z. J. Loussac Library, Assembly Chambers, 3600 Denali, Anchorage, AK. Subject of the hearing, to show cause as to whether any action is necessary to prevent or to assist in preventing waste, to insure a greater ultimate recovery of oil and gas, and to protect correlative rights of persons owning interests in the Pt. McIntyre oil field, has not changed. Any questions regarding this change may be directed to the Commission by calling (907) 279-1433. Russell A Douglass Lt Commissioner Alaska Oil and Gas Conservation Commission Published August 25, 1993 #9510 STOF0330 08-5747 $37.05 AFFiDAViT STATE OF ALASKA, ) THIRD JUDICIAL DISTRICT. ) Eva M. Kaufmann being first duly sworn on oath deposes and says that he/she is an advertising representative of the Anchorage Daily News, a daily newspaper. That said newspaper has been approved by the Third Judicial Court, Anchorage, Alaska, and it now and has been published in the English language continually as a daily newspaper in Anch'orage, Alaska, and it is now and during all said time was printed in an office maintained at the aforesaid place of publication of said newspaper. That the annexed is a copy of an advertisement as it was published in regular issues (and not in supplemental form) of said newspaper on August 7, 1993 OF PUBLiCATiON , Notice Of Public Hearing STATE OF ALASKA AlaSka, Oil and Gas " Conservation CommiSsion , · NOTiCE ,$' .ER'EBY SIV'/ EN'THAT the Alaska Oil and~ Gas Conversation, acting upon| its own mbtlon in accordancel with AS ':31.05.0~0, has schecl-I ule~. a ';publiC. hearing, ,and ex-I tends 'an"lnvitati0n .to 'all ' thoseJ conce'rnedto show Cause as toI whether any .actiOn is'. neces-I sary to prevent or to 'assist inl preventing waste, to insure al greater ultimate recovery ofl 011 ahd. gas, Or to protect cor-I ,,relative rights of persons own-I in'g interests in the 'Pt. Mcln-I tyre' oll field, as defined underJ cOnServation Order No; 317. ',~he hearing on this matterll WI}l. be held at 9:00 'a,m.,[ september 9, 1993, 3001 porcu-ii pi.eDrive, Anchorage, Alaskall 99501.. As a r&sult of this lhqui-I fyi,the commissiOn,, may , ~- ~.~' pf.~r:',~ ar,~..~TU'~-~ .Sl.~:~I ~' ..L: '3~ .".r.~ ~1 .~$ ~.'~ ',-<ir I ~$-(~.~ ---~1r' '5 ,-~af ~onl" i"." "'~, , ;?;-1~13 ...~/s?Dav d' W:,: J0hnston ..':Cha rman..:'i ': .Pub i S~" August 11993 ..' and that such newspaper was regularly distributed to its subscribers during all of said period. That the full amount of the fee charged for the foregoing publication is not in excess of the rate charged private individuals. Subscribed and sworn to be~/ore me this ..~.~.. day of Notary ?ubll¢ In and the State of Alaska. Third Dlvi~lon. Anchorage, ^laska ~¥ COMMISSIOIq r~PIR£$ JULY 3~ '~ 9'94 ~laska Oi~ ~ Gas Bans. Anchorage Notice of Public Hearing STATE OF ALASKA Alaska Oil and Gas Conservation Commission NOTICE IS HEREBY GIVEN THAT thc Alaska Oil and Gas Conservation, acting upon its own motion in accordance with AS 31.05.060, has scheduled a public hearing and extends an invitation to all those concerned to show cause as to whether any action is necessary to prevent or to assist in preventing waste, to insure a greater ultimate recovery of oil and gas, or to protect correlative rights of persons owning interests in the Pt. McIntyre oil field, as defined under Conservation Order No. 317. The hearing on this matter will be held at 9:00 a.m., September 9, 1993, 3001 Porcupine Drive, Anchorage, Alaska 99501. As a result of this inquiry the Commission may consider forced unitization of the Pt. Mclntyre and Stump Island reservoirs as authorized by AS 31.05.030 and 31.05.110. Interested parties may confirm this hearing by calling (907) 279-1433. Chairman Published August 6, 1993 ORIGINAL OMM :OMM - ';OMM ~ · '::::S EN,~ _II SR ENG SR ENG ENG"ASST ,,, ENG ASST GEOL ASST ,':;EOL ASST S-T~ TECH sTA'¥-~E~'H PRUDHOE BAY UNIT APPLICATION FOR THE THIRD EXPANSION OF THE UNIT AREA AND FORMATION OF THE Pt. McINTYRE PARTICIPATING AREA DECISION AND FINDINGS OF THE DIRECTOR OF THE DIVISION OF OIL AND GAS AUGUST 18, 1993 RECEIVED AU 6 1 9 199~ Alaska Oil .& Gas Cons. Commi~o~ ~chorage PRUDHOE BAY UNIT APPLICATION FOR THE THIRD EXPANSION OF THE UNIT AREA AND FORMATION OF THE PT. McINTYRE PARTICIPATING AREA SUMMARY OF DECISION: On March 18, 1993, ARCO, BPX, and Exxon, the Pt. McIntyre Working Interest Owners (producers or lessees), applied to expand the Prudhoe Bay Unit (PBU) and to form the Pt. McIntyre Participating Area (PMPA) within the proposed expanded unit area. After a thirty day public comment period, the department extensively reviewed the statutes, both the former and current oil and gas unitization regulations, and the Prudhoe Bay Unit Agreement (PBUA). Based upon the producers' application, the producers' appeal of the recent PBU contraction decision, and this review, the application is denied. The producers have not demonstrated that expanding the PBU to encompass the Pt. McIntyre Reservoirs under the terms that they have proposed is necessary and advisable to protect the public interest. I. BACKGROUND The PBU is an oil and gas unit located on the Alaska North Slope (ANS). The state approved this unit effective April 1, 1977. The original PBU application proposed to unitize 111 state leases, all of which were executed on the Division of Lands DL-1 lease form. The original unit area consisted of approximately 245,767 acres. ARCO Alaska, Inc. (ARCO) and BP Exploration (Alaska) Inc. (BPX) jointly operate the PBU on behalf of all 14 working interest owners (WIOs). On February 29, 1984, the Department of Natural Resources (DNR) approved the first expansion of the PBU to include all or portions of an additional 7 state leases, comprising approximately 5760 acres. The expanded unit area comprised approximately 251,437 acres. On November 9, 1984, the DNR received an application to simultaneously expand the Duck Island Unit (DIU) boundary and contract the then current PBU boundary. The application, submitted by ARCO, BPX and the Exxon Corporation (Exxon), sought to amend the boundaries of the two units so that those leases believed to be wholly or partially underlain by the Endicott Reservoir would thereafter be in a separate unit, the DIU. Lands overlying the Endicott Reservoir that were then within the PBU were proposed to be excluded from the PBU and included within the DIU. The area proposed for contraction from the PBU included three leases comprising approximately 7680 acres. DNR approved the November 9, 1984 application effective February 22, 1985, on the condition that the WlOs of the two units file an application within one year to conform the boundary between the two units to follow the trend of the Mikkelsen Bay Fault. This condition was designed to ensure that the lands in the western boundary of the DIU were restricted to those overlying the Endicott Reservoir, and that those lands in the northeastern part of the PBU were restricted to those overlying the Lisburne Reservoir. In response to the condition imposed by the DNR, the producers applied on November 21, 1985, to expand the PBU and simultaneously contract the DIU to effect the boundary adjustments. ARCO and BPX submitted this application on behalf of all the WlOs of the two units. The application was approved effective February 22, 1986. Thereafter, the PBU comprised approximately 248,007 acres. On April 1, 1987, pursuant to the PBUA's provisions, the PBU automatically contracted. This contraction, on the 10th anniversary of the PBU, was intended to result in the unit area thereafter including only those leases within an approved participating area (PA). However, certain leases (the Tracts) not within an approved PA were granted a five year deferral of contraction to April 1, 1992. After this mandated contraction of the unit area, the PBU contained 104 leases encompassing approximately 233,419 acres. In early 1992, the producers requested a second deferral of contraction for the Tracts for another year. On March 25, 1992, DNR responded that it would delaY a decision on the second deferral application until after it had reviewed geologic data that the producers promised to provide by September 30, 1992. The producers failed to meet that date and requested that they be allowed until May of 1993 to provide the data. DNR informed the producers in no event would it delay the deferral decision beyond the first quarter of 1993. On March 31,1993, the producers requested a third deferral for yet another year. On April 14, 1993, I issued my decision as director of the division of oil and gas (DO&G) refusing to delay further the contraction of the Tracts from the PBU. Thus, the Tracts consisting of Tract 5 (ADL 34626), certain parts of Tracts 6 (ADL 34627) and 7 (ADL 34624), and Tract 8 (ADL 28297), were eliminated from the PBU. I concluded that a deferral of more than five years past the agreed upon original contraction date had been sufficient to allow the producers to confirm whether those lands qualified to be in a PA and to request and secure a decision on the merits of their application. ARCO and Exxon have appealed my contraction decision to the commissioner and requested a decision on the appeal be deferred until a decision has been issued on the expansion application. The Initial Participating Area (IPA), which includes two PAs, the Oil Rim and Gas Cap, consists of the leases and portions of leases within the PBU that have been determined to be capable of producing or contributing to production of hydrocarbons from the Prudhoe Bay Reservoir (Permo-Triassic) in paying quantifies. Only leases that are either partially or wholly included within the IPA can have hydrocarbon production from the Prudhoe Bay Reservoir allocated to them. The IPA was approved simultaneously with the approval of the PBU Agreement on June 2, 1977. The IPA contains all or parts of 92 leases totaling approximately 213,546 acres. A third PA within the PBU, the Lisburne Participating Area (LPA), was approved by the DNR effective December 1, 1986. Production commenced from the Lisburne Reservoir in the LPA on December 15, 1986. Currently, the LPA contains all or parts of 38 leases totaling approximately 80,039 acres. A fourth PA within the PBU, the West Beach Participating Area (WBPA), was approved by the DNR effective February 22, 1993. The WBPA contains all or parts of five leases totaling approximately 2,347 acres. Production commenced from the Kuparuk Formation in the WBPA on April 8, 1993. II. APPLICATION FOR THE THIRD EXPANSION OF PRUDHOE BAY UNIT AREA AND FOR THE FORMATION OF THE PT. McINTYRE PARTICIPATING AREA On March 18, 1993, the producers applied to expand the PBU and to approve the formation of the PMPA within the expanded PBU area pursuant to 11 AAC 83.356 and Article 9.1 of the PBUA. The proposed third expansion would add all or portions of six state oil and gas leases, ADL 34627 (Tract 6), ADL 34624 (Tract 7), ADL 28297 (Tract 8), ADL 28298 (Tract 115), ADL 34622 (Tract 116), and ADL 365548 (Tract 117), totaling approximately 9696 acres, to the PBU for a total expanded PBU of approximately 243,115 acres. Two of the leases were issued as a result of state Lease Sale No. 14 (Prudhoe West to Canning River), held on July 14, 1965. The leases, ADL 28297 and ADL 28298, were issued on state lease form DL-1 (Revised Oct. 1963) providing for a 12.5 percent royalty to the state. A reduction of the royalty rate from 12.5 percent to a discovery royalty rate of 5 percent for all production allocated to the lease ADL 28297 was granted on March 6, 1991. The reduced royalty rate is effective for the period April 1, 1988 through March 31, 1998. Royalty reduction was granted for ADL 28297 because the Pt. Mclntyre accumulation was discovered by the drilling of the Pt. Mclntyre State No. 3 well on that lease. Three of the leases were issued as a result of state Lease Sale No. 18 (Prudhoe), held on January 24, 1967. These leases, ADL 34622, ADL 34624, and ADL 34627, were also issued on state lease form DL-1 (Revised Oct. 1963) providing for a 12.5 percent royalty to the state. The last lease, ADL 365548, was issued as a result of state Lease Sale No. 45A (North Slope Exempt: Canning River to Colville River), held on September 24, 1985. This lease was issued on state lease form DO&G-24-84 (Royalty)(Rev. 8/84) which provides for a 16.667 percent royalty, and also stipulates that the state's royalty share of any oil or gas produced from the lease will be exempt from field costs. Simultaneously with the application to expand the PBU, the producers applied to approve the formation of the PMPA within the expanded PBU. The unit expansion acreage and the acreage proposed for the PMPA encompass two reservoirs, the Pt. Mclntyre Reservoir (consisting of the Kuparuk and Kalubik Formations) and the Stump Island Reservoir (Seabee Formation), which are purported to be capable of producing or contributing to the production of hydrocarbons in paying quantities. The PMPA application was submitted pursuant to 11 AAC 83.351 and Section 5.3 of the PBUA. The proposed PMPA would comprise all or pans of the six individual oil and gas leases proposed for the unit expansion, and would total approximately 10,828 acres. The application also included a proposed plan of development and operations for the PMPA, interim PMPA Tract'Participation Factors, confidential geological and geophysical data in support of the proposed PA, a proposed well test allocation methodology for allocating production from all the producing reservoirs that will share the Lisburne Production Center (LPC), a copy of the Third Amendment to the Lisburne Special Supplemental Provisions to the PBU Operating Agreement, and proposed methods for reporting the allocated production and gas reserve/gas debits from each PA sharing the LPC. Later, a copy of the Pt. Mclntyre Special Provisions to the PBU Operating Agreement was provided to DNR. Also provided at a later date, June 24, 1993, were the final PMPA Tract Participation Factors. The application requested that DNR approve both the PBU expansion and the PMPA effective July 1, 1993. Before the public notice required under 11 AAC 83.311 was issued, an opportunity was provided to the producers, without any prejudice to their appeal rights, to modify the proposed PBU expansion area to include the Tracts which were contracted out of the PBU by my April 14, 1993 decision. The producers intended that these lands be included within the expanded PBU and proposed PMPA. Noticing the entire proposed unit expansion and PA as originally contemplated by the producers before the contraction of the Tracts would have avoided the requirement of another public notice and thirty day public comment period if the producers did not prevail in their appeal to the commissioner of the contraction decision. The producers declined to modify the proposed PBU expansion area set forth in the March 18, 1993 application. On May 14, 1993, the DO&G determined that the expansion application was complete under 11 AAC 83.306. On May 19, 1993, public notice was published in the Anchorage Daily New~ and in the Tun0ra Times, as required by 11 AAC 83.311. Copies of the public notice were provided to interested parties in compliance with 11 AAC 83.311, as well as to the City of Barrow, the North Slope Borough, the Arctic Slope Regional Corporation, the Alaska Department of Environmental Conservation, the Alaska Department of Fish and Game, the Alaska Department of Natural Resources, Division of Land and Water Management, and the Alaska Oil and Gas Conservation Commission (AOGCC). During the 30 day public notice period allowed under 11 AAC 83.311, no comments were received from the public, interested parties, or state or local agencies. III. DISCUSSION OF DECISION CRITERIA Pursuant to AS 38.05.180(p) and 11 AAC 83.303(c), the DNR commissioner or his designee may approve expansion of a unit area if it is determined that expansion is "necessary or advisable to protect the public interest." Approval must be based on the criteria in 11 AAC 83.303(a) and the factors enumerated in 11 AAC 83.303(b). If the expansion would not protect the public interest, the proposed unit expansion must be disapproved. Article 9.1 of the PBU Agreement (PBUA), which permits expansion of the PBU if approved by the director,~ restates the commissioner's discretionary power under AS 38.05.180(p) and 11 AAC 83.303. Article 5.3 of the PBUA reflects the commissioner's discretionary power under AS 38.05.180(p) and 11 AAC 83.351 to approve or disapprove formation of a participating area. Article 5.3 requires the lessees to apply for expansion of participating areas using specified criteria and procedures but does not change the commissioner's discretion to approve establishment, enlargement, or contraction of lands reasonably proven to be within the reservoir limits. The producers have argued that because a portion (slivers) of certain of the Tracts which they originally proposed to include within the PMPA were within the PBU before contraction, the commissioner lacks discretionary power to disapprove expansion to include all acreage adjacent to those slivers which may overlie PMPA. The slivers contain less than 5 percent of the recoverable reserves currently attributed to the Pt. Mclntyre reservoirs. My April 14, 1993 decision contracted the slivers out of the PBU. Because the producers have appealed that decision, the effect of the contraction decision has been stayed pending the commissioner's decision on appeal under DNR's appeal regulations, 11 AAC 02.060. If the commissioner affirms my decision, the producers admit that their argument, that they have a contractual right to expand the PBUA to encompass the proposed expansion area, fails. However, even if the commissioner reverses the contraction decision and determines that the slivers should still be within the PBU, the commissioner's discretionary authority to deny expansion or to condition expansion remains unchanged. The producers argue that because the slivers, which overlay a portion of the Kuparuk Formation within the proposed PMPA, ~When the PBU was executed, the state director of the division of minerals and energy management, the predecessor agency of the DO&G, was responsible for contraction and expansion decisions. are within the PBU (because of the stay of the contraction decision), all of the Pt. McIntyre leases which overlie the Kuparuk Formation must be included in the PBU. The producers contend that once that additional area is included, the Kalubik Formation which overlies the Kuparuk Formation within the proposed PMPA, must also be included in the PBU.2 (Because the slivers contain less than five percent of the recoverable reserves projected for Pt. Mclntyre production, the producers' argument is like the dog's tail wagging the dog.) Their position rests on two arguments. I reject both. The first relies on 11 AAC 83.356(a) which provides that a "unit must encompass the minimum area required to include all or part of one or more oil or gas reservoirs," That regulation does not mandate that where two reservoirs are side by side or where one reservoir partially overlies another, both must be in the same unit; by its very terms, the regulation provides that a unit must encompass, at a minimum, only part of a reservoir? The producers read the regulations to provide that the minimum area that must be included is all reservoirs. This reading ignores the "part of one" language in the regulation. A unit area may include part of one reservoir, one complete reservoir, one complete reservoir and part of another reservoir, or any one of a number of combinations. At a minimum, it must include, part of a Reservoir. In other words, a unit cannot be formed without at least a portion of a reservoir, but it can be formed with only that minimum area. Over time as more geologic data become available the unit area must be contracted to exclude areas that do not contain any reservoir. 11 AAC 83.356(b). 11 AAC 83.356(a) is consistent with AS 38.05.180(p) which gives the commissioner discretion to approve or disapprove a unit consisting of "all or a part of an oil or gas pool, field, or like area" when it is "necessary or advisable in the public interest." Even if the slivers are within the PBU, neither 11 AAC 83.356(a) nor AS 38.05.180(p) take away the commissioner's discretion in this regard. Any other interpretation renders 11 AAC 83.303 and the remaining provisions in 11 AAC 83.356 meaningless. The producers also argue that Article 9.1 of the PBUA mandates that the entire Pt. Mclntyre reservoir must be within the PBU because the slivers were within the PBU area. Article 9.1 provides: 2 The producers further contend that if the PMPA is included in the PBU, then they may deduct "field costs" from the state's royalty share of the PMPA production under the 1980 Settlement Agreement. See infra § 111.4.6. 3In the case of an exploratory unit, the minimum area is "part of one...potential hydrocarbon accumulation .... "The West McArthur River Unit is an exploratory unit that includes only a part of a potential hydrocarbon accumulation. The Kuparuk River Unit is a producing unit that initially included only a part of the oil or gas accumulation from which it produces. The Unit Area may be enlarged from time to time so as to include any additional lands reasonably determined to be within any Reservoir any portion of which is within the Unit Area. The lands to be included shall be based on such subdivisions of the public land survey as may be approved by the Director, but not less than the area approved by the well-spacing order affecting such lands for such Reservoir. After due consideration of all pertinent information, the Director shall render his decision, separate as to each lease or lands therein submitted for commitment. I reject the lessees' argument that Article 9.1 of the PBUA mandates expansion and, thus, limits the commissioner's discretion. The "may" and "may be approved" language in Article 9.1 makes it clear that an approval by the director is necessary for expansion of the unit area and that his approval is discretionary. Further, if expansion was mandated and automatic, the language requiring the director to issue a decision would be meaningless. Again, the criteria in 11 AAC 83.303 would be applicable to the director's consideration.4 4Exxon representatives argued in an August 12, 1993 meeting with state representatives that the unitization regulations in effect in 1974 do not permit the commissioner to consider the economic consequences to the state of unit expansion. The unitization statute gives the commissioner authority to approve unitization when it is "necessary or advisable in the public interest." AS 38.05.180(p). Current 11 AAC 83.303 list the criteria to be used in determining whether unitization is necessary or advisable to protect the public interest. Included in the criteria are the "economic costs and the benefits to the state." 11 AAC 83.303(b)(5). Although the former 1974 unitization regulation did not list specific factors to be considered in determining whether unitization was in the public interest, it still required that the commissioner decide the same ultimate question. Moreover, the 1974 version, like the current one, specifically requires the commissioner to protect the interest of the state. It is inconceivable that in determining whether unitization is in the public interest, the commissioner could not consider the economic costs and benefits to the state. The "public interest" standard, as it existed in 1974, is one of broad discretion which permits the commissioner to consider a multitude of criteria and factors. See Hammond v. North Slope Borough, 645 P. 2d 750, 758 (Alaska 1982) (in describing the DNR commissioner's finding that a lease sale will best serve the interests of the state, the court said that a "best interests determination is almost entirely a policy decision, involving complex issues that are beyond this court's ability to decide"); Alaska Survival v. State, 723 P. 2d 1281, 1287 (Alaska 1986) (a best interest determination a decision is arbitrary if the commissioner fails to consider an important factor). Further, the director's decision approving the PBUA makes clear that Article 9.1 was never intended to provide for expansions to include reservoirs or pools that had not even been discovered when the state approved the PBUA in 1977. See Decision and Findings Re Application for Approval of Unit Agreement, Prudhoe Bay dated May 25, 1977 (1977 Findings). When the PBUA was approved, several reservoirs were known. Id, at 3. The size of these reservoirs was subject to dispute and some lessees felt the proposed unit area was too small. Article 9.1 was the vehicle to handle this problem. If the lessees had. geological data which showed that acreage outside the unit boundaries was "productive in the same [then known] pool as acreage in the Unit, it [could] be brought into the unit under the provisions of Article 9.''s The state never contemplated that Article 9 would be used. to expand the PBU to include reservoirs or pools that would be discovered more than ten years after the formation of the PBU. Thus, under the statutes, the unitization regulations, and the terms of the PBUA, the commissioner retains the discretion, after consideration of the criteria in 11 AAC 83.303, to approve or deny expansion of the PBU to include the PMPA.6 In accordance with AS 38.05.180(p) and 11 AAC 83.303, the commissioner will approve a proposed expansion of a unit area, a proposed PA, or a proposed production or cost allocation formula if the commissioner finds that each requested approval is necessary or advisable to protect the public interest. To find that any or all of the requested approvals are necessary or advisable to protect the public interest, the commissioner must find that the requested approval will: (1) promote the conservation of all natural resources; (2) promote the prevention of economic and physical waste; and (3) provi.de for the protection of all parties of interest, including the state. In evaluating the above criteria, the commissioner will consider: (1) the environmental costs and benefits; (2) the geological and engineering characteristics of the potential hydrocarbon accumulation or reservoir(s) proposed for inclusion in the participating area; (3) prior ~Ilae director's decision also makes clear that if existing pools were expanded, he could "condition" the expansion on the producers' agreement to various stipulations. 1977 Findings at3 &5. 6Interestingly, although the producers now maintain that expansion is mandated and the commissioner has no discretion, they filed their application to expand the PBU pursuant to the very regulations that give the commissioner discretion. Furthermore, their current position that the PBUA mandates that the PBU be expanded whenever a portion of a new reservoir underlies the PBU area is inconsistent with their past practices. Portions of both the Kekiktuk Formation in the Duck Island Unit and the Kuparuk Formation in Kuparuk River Unit underlie the PBU. Nevertheless, the producers applied to form separate units (the Duck Island and Kuparuk River Units, respectively) rather than expand the PBU to include these new formations, and the various commissioners, acting within their discretion, approved the separate units. exploration activities in the proposed participating area; (4) the applicant's plans for exploration or development of the proposed participating area; (5) the economic costs and benefits to the state; and (6) any other relevant factors (including mitigation measures) the commissioner determines necessary or advisable to protect the public interest. Further, 11 AAC 83.351(a) provides that, upon formation, a PA may include only land reasonably known to be underlain by hydrocarbons and known or reasonably estimated through use of geological, geophysical, or engineering data to be capable of producing or contributing to the production of hydrocarbons in paying quantities. "Paying quantities" is defined by 11 AAC 83.395(4) to mean: quantities sufficient to yield a return in excess of operating costs, even if drilling and equipment costs may never be repaid and the undertaking as a whole may ultimately result in a loss; quantities are insufficient to yield a return in excess of operating costs unless those quantities, not considering the costs of transportation and marketing, will produce sufficient revenue to induce a prudent operator to produce those quantities. An application for approval of a PA must be evaluated under these standards, as well as those of 11 AAC 83.303. The following evaluates this application under these criteria and considerations. (A) Prom0t~ th~ Conservation of All Natural Rcs0~jrces, The unitization of oil and gas reservoirs and the formation of PAs within unit areas to develop hydrocarbon-bearing reservoirs is a well accepted means of hydrocarbon conservation. Without unitization, the unregulated development of reservoirs tends to be a race for possession by competitive operators. The results can be: (1) overly dense drilling, especially along property lines; (2) rapid dissipation of reservoir pressure; and (3) irregular advance of displacing fluids. These all contribute to the loss of ultimate recovery or economic waste. The proliferation of surface activity; duplication of production, gathering, and processing facilities; and haste to get oil to the surface also increase the likelihood of environmental damage (such as spills and other surface impacts). Requiring lessees to comply with conservation orders and field rules issued by the AOGCC would mitigate some of these impacts without an agreement to unitize operations. Unitization, however, provides a practical and efficient method for maximizing oil and gas recovery, and minimizes negative impacts on other resources. The formation of a PA to encompass the area overlying the two Pt McIntyre Reservoirs will allow them to be efficiently developed. Adoption of a comprehensive operating agreement and plan of development governing that production will help avoid unnecessary duplication of development efforts on and beneath the surface. The Pt. Mclntyre producers are also the same owners of the existing LPC which will process the Pt. Mclntyre production. These producers have negotiated agreements among themselves to share the existing excess production capacity of the Lisburne facilities, and they have a separate plan of development that will optimize the recovery of the hydrocarbon reserves from the Pt. Mclntyre Reservoirs. The state has participated in the producers' attempts to reduce the need for additional major processing facilities and thus to minimize any additional surface impacts and costs. The state has agreed to allow commingled production through the existing LPC and has worked with the producers to provide for a well test-based production allocation methodology for any current and future reservoir sharing the LPC. Furthermore, producing hydrocarbon liquids from the two Reservoirs through the existing LPC reduces the environmental impacts. Using the existing facilities, gravel pads, and infrastructure eliminates the need to construct additional processing facilities. Although expanding the PBU to encompass the two Pt. Mclntyre Reservoirs and the leases overlying those reservoirs would promote resource conservation, creating a separate unit, under terms and conditions more favorable to the public interest, would accomplish the same goal. In fact, in numerous meetings with the producers after the application was received, they presented no substantive reasons which lead me to believe that the conservation goals could not be accomplished by a separate unit agreement with terms and conditions more favorable to the public interest compared to those the producers seek to impose on the state by this application. (B) Tho Provention of Egonomi¢ and Physical Waste, Traditionally, under unitized operations, the assigmnent of undivided equity interests in the oil and gas reservoirs to each lease largely resolves the tension between lessees to compete for their share of production. Economic and physical waste, however, could still occur without an equitable cost sharing formula, and a well designed and coordinated development plan. Consequently, unitization must equitably divide costs as well as production, and plan to maximize physical and economic recovery from any reservoir. It must also treat the royalty owner fairly. An equitable allocation of hydrocarbon shares among the WlOs discourages hasty or unnecessary surface development. Similarly, an equitable cost-sharing agreement promotes efficient development of reservoirs and common surface facilities and encompasses rational operating strategies. Such an agreement further allows the WlOs to decide well spacing requirements; scheduling, reinjection and reservoir management strategies; and the proper common, joint-use surface facilities. Unitized operations greatly improve development of reservoirs beneath leases which may have variable productivity. Marginally economic reserves, which otherwise would not be produced on a lease by lease basis, often can be produced through unitized operations in 10 combination with more productive leases. Facility consolidation saves capital and promotes better reservoir management by all WlOs. Pressure maintenance and secondary recovery procedures are much more predictable and attainable through joint, unitized efforts than would otherwise be possible. In combination, these factors allow less profitable areas of a reservoir to be developed and produced in the interest of all parties, including the state. Although expanding the PBU to unitize the leases encompassing the Pt. McIntyre Reservoirs prevents economic and physical waste, creating a separate unit, under terms and conditions more favorable to the public interest, would accomplish these same goals. (C) The Pr0~iecti0n of All Parties in Interest, Including the State. Expansion of the PBU will not be approved unless all parties of interest, including the state, can be protected. 11 AAC 83.303(a)(3). There has been no showing that the state's interests, particularly its economic interests, are protected by expansion of the PBU to include the proposed PMPA area, as opposed to forming a new unit area under the terms of a separate unit agreement. Some of the specific negative consequences to the state of approving the expansion of the PBU to include the proposed PMPA will be discussed in the section discussing the economic costs and benefits to the state (Section III.4.a.-g. below). The state does not seek an unfair advantage, rather it seeks to prevent an unmitigated loss. The producers' proposal to expand the PBU under their terms gives them many economic benefits, but does not share the benefits with the state. (D) Consideration of Factors In reviewing the above criteria, the following factors were considered: (1) The Environmental Costs and BenefitS of Unitized Development This factor has been previously addressed in section III.A. (2) Geological and Engineering Characteristics, and Previous Exploration of the Proposed Expansion Area and Proposed Participating Area In March 1988, the Pt. Mclntyre No. 3 well discovered the Pt. Mclntyre Reservoir. Since the discovery well was drilled, approximately twenty-four wells have penetrated the Pt. Mclntyre Reservoir within the proposed PMPA. Of these twenty-four wells, four (Pt. Mclntyre No. 3, No. 4, No. 5, and No. 7) have been certified by DNR as capable of producing in paying quantities. Development drilling continues within the proposed PA from two permanent drill site locations, DS PM-1 and DS PM-2. 11 The producers supported their application with geological, geophysical, and engineering information. These include Kuparuk Formation structure maps, total oil pore foot and total hydrocarbon pore foot maps, individual geologic zone net-to-gross maps, porosity and water saturation maps by geologic zone, individual well logs for the available Pt. McIntyre wells, and tract volumetrics for the tracts within the proposed PA. This information supports the determination that the proposed tracts are appropriate for inclusion into a PA or a separate unit. (3) The uroducers' plans for development for the proposed unitized area The planned development program for the proposed PMPA reservoirs includes the directional drilling of 75 to 90 total wells on an average well spacing of 80-acres from the two Pt. McIntyre drill site locations, DS PM-1 and DS PM-2. The initial development combines patterned waterflood operations in portions of the Kuparuk Formation after field start-up, and produced gas reinjection into the gas cap. The possibility of using enhanced recovery techniques to increase recovery will be evaluated in the future. Pt. McIntyre, Lisburne, and West Beach production will be commingled at the LPC. Pt. McIntyre will also share existing PBU infrastructure to minimize duplicating facilities. Commingling procedures and the methodology for allocating production to the appropriate fields sharing the LPC will be conducted in accordance with conditions approved by various state agencies, including DNR, DOR and AOGCC. (4) The economic COSTS and benefits to the state, a) Maximization of Production/Facility Sharing The producers claim that expansion protects the interests of all parties, including the state, because it maximizes hydrocarbon recovery and will increase revenues from the Pt. McIntyre leases. They say that the state's direct economic benefit from expansion will be approximately $800 million over the life of the Pt. McIntyre field. These same benefits, however, may be accomplished at less economic cost to the state by forming a new unit separate from the PBU, like the Duck Island and the Kuparuk River Units. Although the producers claim that the existing and underused LPC cannot be used to process Pt. Mclntyre oil if Pt. Mclntyre is not brought within the PBU, there is no good reason why a new unit may not share this same excess capacity. In fact, use of the LPC by a third party through the payment of a fee would benefit all parties by reducing capital investments in stand-alone production facility and by extending the economic lives of both the shared processing facilities and all the associated fields by spreading operating costs over a larger number of produced barrels. 12 Using the capacity of existing facilities will encourage greater production and ANS resource development by reducing capital investments and per barrel operating costs. Thus, the state agreed to allow commingled production through the LPC and worked with the lessees to get a facility sharing allocation methodology. The state understood that the lessees from other areas outside the PBU, including areas of known discoveries which are currently uneconomic to development using stand-alone facilities, possibly could share PBU facilities. The lessees have apparently changed their position on the potential availability of PBU facilities to process hydrocarbons from non-unit properties. This is inconsistent with the representations they made on several earlier occasions when requesting the state to allow commingling and facility sharing allocation. They have offered no explanation why sharing the LPC with production originating outside the PBU is now impossible. Finally, additional recovery of hydrocarbons, in and of itself, is not determinative of the state's best interest. The terms and conditions of production must also protect the state's interests. b) Field Costs One major economic disadvantage to expansion of the PBU is that it would subject the Pt. Mclntyre leases to a field cost allowance for the royalty share of oil and for any gas that may be produced after commencement of a major gas sale on the North Slope. Under the terms of the PBUA and the 1980 Field Cost Settlement Agreement, the state currently pays field costs of $0.79 per barrel for every barrel of in kind and in value royalty oil taken from the PBU and any expanded area of the PBU. If the PBUA and 1980 Settlement Agreement is made applicable to the PMPA or the state otherwise agreed to pay field costs, the state would bear a major cost (in excess of $25 million in nominal terms). Furthermore, allowing field costs conflicts with the present policy of the state, as well as the legislature's directive enunciated in AS 38.05.180(0, that the state not pay field costs for royalty oil. A detailed review of the field cost issue follows. i) Introduction The legislature, which is constitutionally charged with development of the state's natural resources for the maximum benefit of all the people of Alaska, has had as its longstanding policy that the producers/lessees may not deduct field costs from the state's royalty share. Alaska Const. art. VIII, §§ 2 & 12; AS 38.05.180(0; AS 31.05.110(h).7 Under its 7 Judge, now Justice, Compton has noted the importance of these constitutional provisions. 13 constitutional charge, the legislature authorized the DNR commissioner to establish an oil and gas leasing program including the authority to issue leases under specific conditions and to approve units when it is in the public interest to do so. AS 38.05.180(0 & (p). The legislature has declared state policy with respect to the creation and operation of units both in the Alaska Land Act (AS 38.05) and in the Alaska Oil and Gas Conservation Act (AS 31.05). The legislative policy prohibiting the deduction of unit expenses (which incorporates all the expenses included in the term "field costs") has existed since the passage of the Alaska Oil and Gas Conservation Act in 1955 and the Alaska Land Act. Nevertheless in 1978, the legislature amended both statutes to eliminate any uncertainty about this longstanding policy. Specifically, in 1978, the legislature amended AS 38.05.180 to make explicitly clear that the state's royalty share is "free and clear of all lease or unit expenses." Similarly, in 1978, the legislature amended AS 31.05.110 to make it clear that regardless of whether a voluntary or involuntary unit is formed, the "landowners' royalty...shall be paid to...the landowners...free and clear of all unit expense.''8 These constitutional provisions require that the legislature set the terms of oil and gas leases in such a manner as to provide the maximum benefit for its people. No "term" could be more critical to its people than the monetary return realized on the depletion of their natural resources. If "production" under AS 38.05.180(a) does not mean what the State claims it means, then the legislature has impermissibly delegated a constitutional duty to an administrative agency. The legislature did not do so. ANS Royalty_ Litigation, No. 1JU-77-847 Civil at 18 (Alaska Super., April 6, 1979)(emphasis in original) ("1979 Decision"). 8Producers that hold leases located over the same oil field commonly share exploration and development expenses through some relationship which divides the production and costs relative to ownership interests in the leases. "Unitization" is a method used to accomplish this purpose. When state leases are involved, producers may apply to the commissioner to form a unit with the state as a party to the unit agreement. This is referred to as a "voluntary" unit. If the producers cannot agree to the terms and conditions for a voluntary unit, either by petition by the producers or the state, or by motion by the Alaska Oil and Gas Conservation Commission (AOGCC) itself, the AOGCC can compel unitization. Additionally, under the DL-1 lease form, paragraph 32, and AS 38.05.180(p), the commissioner can force the producers to unitize by "prescrib[ing] a [unit] plan under which the lessee must operate." This is referred to as "involuntary" unitization. If, however, the producers petition the AOGCC to form an involuntary unit, the AOGCC's authorizing statute mandates that the state's royalty share be "free and clear of all unit expense." AS 31.05.110(h). 14 Given the mandates contained in these two statutory provisions, I believe that, because the Commissioner, or I, as his designee, have the responsibility to administer the leasing program according to the legislature's explicit policy, I should not approve an application to form a voluntary unit or to expand an existing unit to which the state is a party if the applicant proposes to burden the state's royalty share with field costs unless I am legally compelled to do so.9 As mentioned earlier in this Decision and Findings, I have concluded that, except for the "slivers," I am not legally obligated to allow a field cost deduction for any of the area proposed to be included in an expanded PBU area. ii) State's consistent position The state has consistently taken the position that its royalty share is free of field costs under the state's "DL-1 leases.''~° Regarding the ANS, the dispute over field cost deductions 9 The state has taken the position that under AS 38.05.180(a), as enacted in 1959, the legislature did not give the commissioner discretion to enter into leases which provide for a royalty of less than 12-1/2 percent. See AN$ Royal~y Litigation State's Reply dated 5/31/78 at 44-47. Although in approving units under AS 38.05.180 the commissioner has the discretion to change the royalty requirements of a lease, this discretion should not be exercised when it would contravene the legislature's explicit intent except in a highly unusual situation. x0 The first oil and gas leases issued by the state are commonly called "DL-1 Leases." It is fair to say that many of the provisions in the final DL-1 Lease were initially drafted and recommended by the Western Oil and Gas Association ("WOGA"). For example, WOGA recommended inserting the phrase "at the well" after the word "value" in the basic royalty provision in the proposed state lease form. WOGA also recommended adding a provision for an allowance for cleaning and dehydrating the state's royalty oil. Both of these recommended language changes became part of the final version of the DL-1 Lease and both were relied on by the producers as support for their claim to field cost deductions during the 1977-1979 summary judgment proceeding. There have been several revisions to the original DL-1 form, but until 1979, the state competitive leases all bore the DL-1 designation and they all contained similar language regarding the lessees' royalty obligation. In 1979, the state lease form was substantially revised. Included in the revisions was an explicit provision that royaLty share is free of any field costs. That language continues in the lease form used in current state competitive lease sales. Like the original DL-1, industry was primarily, if not entirely, responsible for drafting the PBUA. Indeed, industry drafted the PBUA after first refusing to sign the state's model unit 15 crystalized during the summer of 1977, shortly after the giant Prudhoe Bay field came into production. During this period, then Commissioner LeResche notified the producers that "[r]oyalty payments made on the basis of a . . . price or value at the flow stations or gathering centers or at the pads from which the wells have been drilled.., will not be regarded as fulfilling the royalty obligations owed the State." In essence, Commissioner LeResche was informing the producers that any costs incurred by them in producing the oil before its delivery to the Lease Automatic Transfer Point (LACT) meter, i.e., field costs, could not be deducted from the state's royalty share. On September 2, 1977, the state began the litigation now referred to as the "ANS Royalty. Litigation." The state sued the producers, seeking a declaratory judgment that under the DL-1 leases the producers were not allowed to deduct field costs. On April 6, 1979, the superior court granted the state's motion for summary judgment holding that AS 38.05.180(a) prohibited the producers from deducting field costs from the state's royalty when the state takes its royalty "in value" (RIV). 1979 Decision at 5. The court stated that "[f]ield costs are costs of production" and since royalty is to be paid free of production costs, the state's royalty share does not bear these costs. 1979 Decision at 20.n The court also held, however, that cleaning and dehydration costs, a portion of field costs, are deductible when the state takes its royalty "in kind" (RIK), noting that when the state takes its royalty share in kind it "competes" in the selling of oil with the producers. 1979 Decision at 5 & 20. Further, the court held that the commissioner is prohibited from taking the state's royalty in kind if the amount realized would be less than if taken in value. 1979 Decision at 5. This meant that when the state acted as a competitor with the producers by taking its royalty in kind, the state was required to obtain a premium over the in value price from its in kind purchasers sufficient to pay for cleaning and dehydration costs. In sum, the court affirmed the state's policy position that its royalty share was free of field costs. The state continues to maintain its right to a royalty free of field costs. Although the field costs issue pertaining to any oil production and to gas production after a major gas sale from the PBU was settled in part (see discussion below), the state continues to assert in the AN$ Royalty_ Litigation that the state's royalty share for gas production before a major gas sale is free of field costs. Additionally, as discussed below, the state has required as a condition agreement. Accordingly, I believe that any ambiguity in the PBUA should be construed against industry and not the state. See Royalty Litigation State's Memorandum in Support of Motion for Summary Judgment re Field Gas Supply Option dated July 2, 1993, at 51. n The court also accepted the state's argument that since the leases had been issued pursuant to the legislature's authorization in AS 38.05.180 and since that statute provided for a minimum royalty of 12-1/2 percent, deducting field costs would violate the statute because it would reduce the royalty below the 12-1/2 percent minimum. 16 of its approval of every unit application submitted after 1979 except one, that the producers waive any claimed right to field costs under the DL-1 leases. The commissioner has the discretion to require, as a condition of approving unit formation or unit expansion, the waiver of the right to deduct field costs from the royalty share even if the DL-1 leases explicitly provided that the producers were entitled to deduct field costs. The right to renegotiate royalty terms of leases as part of unitization has been recognized for years. Both the DL-1 leases and the voluntary unitization statute expressly contemplate that upon unitization lease provisions may be renegotiated. Paragraph 32 of the DL-1 lease form provides: "Lessor may with the consent of Lessee establish, alter, change, or revoke drilling, producing, rental, minimum royal_ry, and royalty_ re{!uirements of this lease if committed to any such.., unit agreement." (emphasis added). AS 38.05.180(p) is substantially similar and provides: "The commissioner may with the consent of the holders of the leases involved, establish, change: or revoke drilling, producing and royalty requirements of the leases.., in connection with the institution and operation of a unit plan." (emphasis added). Under this authority, the ANS producers, including Arco, BPX, and Exxon, in the past have agreed to renegotiate various lease terms including DL-1 lease terms. See Commissioner's Decision and Findings re Hemi Springs Unit Agreement dated January 15, 1984 at 3-4. Even the royalty rate itself has been renegotiated under this authority. For example, as a condition of approval of the Milne Point Unit, the commissioner required those producers to agree that the royalty rate on certain leases within that unit be raised from a 12¥~% royalty rate stated in the leases to a 20% rate. (In other unit applications, DNR has considered adjusting the royalty rates in the DL-1 leases proposed to be committed to a unit, but determined that under the specific circumstances of each unit, raising the rates was not in the state's best interest. Id. at 8.) The Milne Point producers did not have to consent to this condition, but the approval of a voluntary unit, as they had requested, would have been denied. Similarly, the producers, including Arco, BPX, and Exxon, have agreed on various occasions to renegotiate the DL-1 leases as part of unitization to make clear that field costs would not be deducted from the royalty share in exchange for the substantial benefits of unitization and lease extensions that they were seeking. See Gwydyr Bay, Milne Point, Hemi Springs, and Becharof unit agreements. Again, the producers did not have to renegotiate, but the proposed voluntary unit would have been denied. There is plenty of precedent for requiring the producers to waive any claimed right to field costs as a condition of approval of a unitization request. Similarly here, the producers do not have to agree to waive field costs; but if they do not, neither I nor the commissioner must approve a voluntary expansion of the PBU as they have requested. A remedy for the producers if they find this condition unacceptable is to petition 17 the AOGCC to form a separate involuntary unit? The state has consistently maintained that the DL-1 leases do not bear field costs, and that even if they arguably do, the producers must give up any such claim before the state will approve an application for a voluntary unit or for expansion of the PBU. The reason for this is obvious -- the alternative whether arrived at through an AOGCC proceeding or under a plan prescribed by the commissioner would produce the same and, obviously, preferable result from the state's perspective -- production of the state's royalty share free of field costs. iii. The legislature's policy The legislature's view on whether field costs should be allowed against the state's royalty share has been made crystal clear. In 1978, the oil and gas leasing statutes were extensively amended by the legislature. AGO 1092955. Part of the reason for the comprehensive amendments was to confront the problems which were by then recognized in determining the state's royalty share resulting from the several disputes in the ANS Royalty_ Litigation. AGO 1092955; ANS Royalty Litigation, Findings of Fact and Conclusions of Law, dated August 13, 1980, at 4 (Findings). The then director of research for the legislative affairs agency noted that the bill contained language to "insure that future leases are not subject to the sort of dispute over [field] costs as the state is now litigating with the.., producers." AGO 1093219. In passing the comprehensive revision, the legislature clearly and expressly stated that the state's royalty share shall be free of field costs. A royalty share is reserved to the State, it shall be delivered in pipeline quality and free of all lease and unit expen~e~, in0uding bllt not limited to separation, cleaning, dehydration, gathering, saltwater disposal, and preparation for transportation off the lease or unit area. AS 38.05.180(0 (emphasis added). Also in 1978, the legislature amended the Oil and Gas Conservation Act (Title 31) to clarify that if an oil and gas field is unitized, regardless of whether the unit is formed voluntarily or involuntarily, the royalty share was free of field costs. The Act provides: A one-eighth part of the unit production allocated to each separately owned tract shall be regarded as royalty to be distributed to and among, or the proceeds of it paid to, the royalty owners free and clear of all unit expense and free of any lien therefore. ~2Additionally, as previously discussed, the DNR commissioner has authority to compel an involuntary unit. 18 AS 31.05.110(h) (emphasis added). As part of the ANS Royalty_ Litigation in 1977-78, the state argued that subsection (h) expressly forbade the producers' taking of field costs against the state's royalty share. The producers disagreed, claiming that the subsection did not apply to the PBU because it was a voluntary unit. In 1978, the legislature amended AS 31.05.110 by adding subsection (q), which explidtly stated that subsection (h) was applicable to voluntary units. The state has recently argued that this 1978 amendment, which immediately followed the controversy over subsection (h)'s application to voluntary units, evidences the legislature's intent that even before 1978 it intended subsection (h) to apply to voluntary units. ANS Royalty_ Litigation, State's Memorandum in Support of Motion for Summary Judgment on Counts I-V, dated July 2, 1993, at 76-79. Regardless of whether subsection (h) applied to voluntary unitization before 1978, it undoubtedly applies now, and I must consider it in analyzing whether it is in the state's best interest to form a new unit or expand an existing unit areas under the specific facts and circumstances surrounding each application? In short, the Alaska legislature has explicitly stated that it intends that the state's (or any landowner's) royalty share as part of unitization shall be free and clear of all unit expense. iv) DNR'~ implementation of the legislature's policy Shortly after the amendments to the oil and gas leasing statutes, DNR amended its model form lease and unit agreement to conform with the legislature's policy. The first lease sale to be held after 1978 offered leases that reflected the amended statutes. Regarding field costs, the new lease form provided: Royalty_ paid in value shall be free and clear of all lease expenses (and any portion of such expenses which has occurred away from the leased area), including but not limited to expenses for separation, cleaning, dehydration, gathering, saltwater disposal, and preparing the oil, gas or associated substances for transportation off the leased area .... Royalty_ delivered in kind shall be free and clear of all lease expenses (and any portion of such lease expenses which is incurred away from the leased area), including, but not limited to expenses for separation, cleaning, dehydration, gathering, saltwater disposal, and preparing the oil, gas or associated substance for transportation off the leased area. ~3 The same criteria that apply to unit decisions apply to unit expansion decisions. See 11 AAC 83.303, .311, .316 & .356. 19 Form No.DMEM-A (revised August 27, 1979), ¶¶ 2 & 3 (emphasis added). The concept of a royalty share free of field costs has been carried forward to the current date. See Form No. DOG9208 (created August, 1992), ¶¶ 37 & 37. Indeed, BPX's lease in the proposed PMPA, which was issued in 1985, is a Form DO&G 24-84 (royalty) (rev. 8/84) lease providing that neither RIV nor RIK bears field costs. In addition, after the 1978 amendments, DNR's consistent position has been to require that any claimed right to field costs be waived by a producer seeking to voluntarily unitize a field. Of the twelve voluntary units formed since the effective date of the 1978 amendments, all but one have explicitly provided for no field costs?4 The state's model unit agreement form provides that the royalty share "shall be free and clear of all lease expenses". DNR Form No. 10-1128 (Unit Agreement) (Revised April 1990) at Art. 10.9. Four of the twelve units approved since 1979 have contained DL-1 leases. In order to gain the DNR's approval of the proposed units, the producers were required, consistent with the legislature's policy, to waive any argument that they were entitled under the DL-1 leases to deduct field costsfi The producers who have so waived field costs under DL-1 leases include Arco, BPX, and Exxon. See Gwyder Bay and Hemi Springs unit agreements. As discussed above, these precedents undercut any argument by them that the commissioner cannot require the waiving of field costs as a condition of his approval of an application to unitize or expand a unit area. v) The 1980 Settlement Agreement In 1980 the state and the producers settled the field cost issues in the ANS Royalty_ Litigation for oil production and for gas production after a major gas sale from the PBU. Despite the court's favorable summary judgment decision that the state did not have to bear field costs, the state agreed to pay the producers an equal fee for oil produced from the PBU whether the state's royalty share was taken in value or in kind. Admittedly, the 1980 Settlement Agreement was at odds with the policy adopted by the legislature in 1978 that the state's royalty share shall be free of field costs. Nevertheless, the state entered into the 1980 Settlement Agreement to obtain an early cash payment, to avoid both litigation risk and significant legal expense, to facilitate the state's right to take its royalty share in kind, and to allow the state to plan for the long-term disposition of its natural resources. Findings at 4-5. As a result of that settlement, however, the state has 14 The only exception to DNR's implementation of the legislative policy was in approving the formation of the KRU. This exception is discussed later in this Decision and Findings. ! ~5I have previously discussed the commissioner's authority to require a waiver of field costs. 20 paid the PBU producers in excess of 650 million dollars to date -- none of which the state would have had to pay under the 1979 Decision if the royalty was taken in value. In entering into the 1980 Settlement Agreement, the state and the producers were desirous that the Agreement would help to settle disputes. Unfortunately, the Agreement has actually fostered other misunderstandings and disputes which continue to the present day. First, I believe that it has paid more under the 1980 Settlement Agreement than it ever intended to pay. The producers dispute this. At the time of the 1980 Settlement Agreement, the producers estimated the recoverable reserves for the PBU at 9.6 billion barrels of oil. Thus, the state contemplated that its payment would be approximately the per barrel fee times the royalty share (one-eighth) of 9.6 billion barrels. The number of recoverable reserves has since been shown to be as much as 12 billion barrels of oil. As a result, the state will ultimately pay considerably more than it contemplated in 1980 based upon the expected production volume. In fact, BPX has recently stated publicly that it now believes the reserves may be raised by another billion barrels as the result of drilling additional development wells. Under anyone's interpretation of the DL-1 lease, however, the costs of drilling development wells is a cost to be borne solely by the producer. These new reserves are not reserves that the state contemplated that it would be responsible for sharing the costs to produce. Nevertheless, as a result of the 1980 Settlement Agreement, the state will continue to pay field costs for an additional billion barrels of production. Pt. Mclntyre production, whether from a new unit or a new PA in the PBU, will be processed through already existing facilities which the state shares the costs of under the 1980 Settlement Agreement. Yet, the producers wish to impose the same per barrel fee on Pt. Mclntyre reserves as the state currently pays for each PBU royalty barrel. As WIOs of the Lisburne facilities within the PBU, ARCO, BPX and Exxon have negotiated agreements with themselves as Pt. Mclntyre Owners in which they will recover a processing fee of $2.00 per barrel for their earlier investments in those facilities. However, they have made n.o provision for repaying the state for its proportionate share of those costs. Moreover, they insist that the state must pay again for those same facilities to process the royalty share of Pt. Mclntyre reserves through them! Second, the 1980 Settlement Agreement led to additional disputes between the producers and the state regarding the deduction of field costs for the state's royalty share as part of the Kuparuk River Unit (KRU) formation. Ultimately, the dispute was settled by a renegotiation of the leases' field cost terms as part of the unit formation, with the state again agreeing to pay a portion of the field costs. Importantly, for the state's economic protection, the producers significantly compromised their claimed field cost deductions from $0.882 per barrel to $0.395 per barrel as part of the settlement. The KRU Decision and Findings noted that the KRU settlement did not resolve the dispute for future units. Since 21 numerous other units would come before the state, it was likely that future litigation would ensue.~6 Third, that prophesy has been borne out as reflected by the current disputes surrounding whether the producers have an absolute right to expand the PBU and, thus, the ability to force the state to pay field costs by operation of the 1980 Settlement Agreement. The parties continue to argue about the acreage to which the 1980 Settlement Agreement applies. The Agreement's effect was limited by its terms to certain leases within the then existing PBU and to such other leases as the unit area may be expanded to include. The producers argue that the 1980 Settlement Agreement, in combination with the PBUA, deprive the commissioner of the discretion to deny an expansion request if any portion of a newly discovered reservoir underlies the PBU. They also argue that he has no authority to condition a proposed expansion on the waiving of field costs. As discussed earlier, this position is contrary to the statutory and regulatory best interest findings regarding unit expansions. Fourth, the producers have recently contended in the gas related portion of the AN$ Royalty. Litigation that the effect of the 1980 Settlement Agreement, which settled only PBU field cost issues for oil and for gas after a major gas sale, bars the state from asserting the same position that it asserted in its 1977 motion for summary judgment. They assert the state can no longer contend that AS 38.05.180 precludes a field cost deduction for gas before a major gas sale. Given that the PBU producers are likely to continue to attempt to expand the PBU to take advantage of the 1980 field cost allowance (and other economic benefits that accrue to them as a result of operating within the PBU), I believe that it is in the state's best interest to resolve the issue once and for all, not just for the current situation. vi) Conclusion ~6 As previously discussed, this is the only time since the 1978 amendments that the DNR Commissioner, acting within his discretion, has approved a unit which allowed field costs to be deducted from the royalty share. Field costs were allowed, however, as part of the formation of the Endicott Participating Area (Endicott PA) in the Duck Island Unit. Although the Duck Island Unit was formed before the effective date of the 1978 amendments, the Endicott PA within that unit was formed after the effective date. The field cost deduction of only $0.42 per barrel allowed for the Endicott PA is significantly less than the $0.80 per barrel requested by the producers here, although the fields 'are of similar size and, unlike the Endicott PA, the PMPA has the benefits of facility sharing. Given the significantly lower fields costs agreed to by the producers than those proposed here, I can understand how those commissioners, acting within the scope of their discretion, approved the respective unit and PA. This situation is distinguishable. 22 In summary, I do not believe that it is in the state's best interest to approve the expansion of the PBU to include the proposed PMPA if it means that the state's royalty share from the Pt. McIntyre leases, other than the slivers, would be burdened with field costs. First, as mentioned above, the state's longstanding position is that the royalty share should not bear field costs. Second, the legislature has made that position its explicit policy. Third, allowing field costs is not consistent with DNR's approval of other unitization requests. Fourth, allowing field costs would not resolve disputes between the state and the producers over this issue. Fifth, by providing for commingling, the state has provided the producers with benefits which should allow production of the field even if field costs cannot be deducted or even if production takes place from a separate unit. Sixth, allowing field costs would not be in the state's economic interest because it would deprive the state of in excess of $25 million dollars over the life of the Pt. McIntyre production, and potential other revenues if field costs were later allowed for other future units because of established precedent. The producers have stated that certain economic benefits will accrue to them aside from deducting field costs if the proposed PMPA is within the PBU. The producers have not proposed to share those benefits with the state in any form. Although it has been done several times before, they have adamantly refused to waive their claimed right to field costs so that the state can, at least, share in some of the additional economic benefits of unitization. I simply do not believe that the producers have presented any compelling reason why the legislature's policy that the royalty share is to be free of field costs should not be followed. c) Tract Allocation As required by 11 AAC 83.371, the producers submitted an allocation of production and costs characterized by them as a "value-based" allocation. The producers claim that expansion protects the interests of all parties, including the state, by equitably allocating production to lease tracts. But the producers agreed only among themselves how to allocate production to tracts and how to share facilities; their agreements were designed to protect only their equity interests. The state was not consulted by the producers, nor is there any evidence that its royalty interest was considered by them. Therefore, the producers' agreements do not necessarily protect the state's interests. The producers have argued that approval should be granted because disapproval will delay production of Pt. Mclntyre while the lessees renegotiate their agreements. However, protection of the state's interest with the formation of a separate unit agreement outweighs whatever benefits are derived from early production of Pt. Mclntyre under the PBUA. The proposed allocation essentially distributes working interest equity among the several leases by recognizing differing development costs and recoverable reserves among the leases. The basis for the calculation of value-based equity and allocations, as opposed to an allocation based on original oil in place (OOIP or black oil reserves) or some other 23 { technically based standard, was arrived at, as discussed above, through confidential negotiations among the producers with no advance notice or approval by the state. Although redistributing the equity owners' share of production may be warranted to promote unitized development, undoubtedly the royalty owner does not bear responsibility to underwrite such cost sharing arrangements--particularly where the royalty share is bartered without the royalty owners' assent. Where the royalty rates of all leases are the same within a unit or a proposed expansion area, negotiations among the equity owners to reallocate costs are irrelevant to the royalty owner. Regardless of which costs are borne by which lessee, the royalty owner's share of production is not reduced. But the royalty rates are not the same here. The proposed expansion area encompasses six leases. One lease provides for a royalty rate of 16 2/3 percent. Another lease was awarded a discovery royalty certification, and thus has a five percent royalty for a ten year term commencing the first day of the month following discovery. The other four leases have a 12 1/2 percent royalty rate. 'The producers' value-based tract allocation would reduce the state's royalty share by imputing a larger equity (tract allocation) to the five percent discovery royalty tract. Under the regulations, the commissioner must approve the production allocation before it /, takes effect. I cannot approve an allocation which reduces the state's royalty revenues / simply to accommodate a negotiated settlement of the WlOs' cost and revenue disputes. / Exxon, however, in meetings with DNR representatives on August 12, 1993, opined that this / is precisely what the state is bound to do if it approves the proposed expansion. Exxon reads the PBUA, the terms of the 1980 Settlement Agreement and the May 25, 1977 'Decision and Findings of the Director, Division of Minerals and Energy Management With Respect to Application for Approval of Unit Agreement, Prudhoe Bay~, in combination, to constitute a waiver of the commissioner's discretion to deny a specific allocation or to require amendment of a proposed tract allocation. Obviously, the commissioner's discretion in this regard cannot be questioned in the context of forming a new unit. I believe it is equally obvious that if the approval of the expansion is discretionary, it would not be in the state's interest to incur the additional risk of litigation to establish its authority to reject a disadvantageous tract allocation within an expanded area of the PBU. Although the state has not completed its review of the producers' proposed tract allocations, I would accept an allocation, for royalty purposes, based on black oil reserves. d) Royalty. in Kind (RIK) Issue In evaluating the state's economic interests under the alternatives of either expanding the PBU under the terms proposed by the producers or creating a separate unit, it is also proper to consider the effects of both alternatives on the state's existing royalty in kind contract relationships. Under the terms of the PBUA, the state must nominate its volumes of RIK 24 oil as a specific percentage of daily production from the unit area; it cannot nominate either a specific volume or from a selected PA in the PBU. Both the state and its purchasers are constantly faced with the need to adjust volumes to accommodate variances in production rates. In addition, there are strict limitations on the notice which the state must provide to the PBU WlOs of adjustments that it wishes to make to balance its RIK deliveries with changing production rates. Under the producers' interpretation of the PBUA, however, they are not obliged to consider the states's RIK contract relationships or the effects of their unilateral production decisions on those relationships. Although the state must give several months' notice of its intent to increase or decrease its in kind taking, the producers maintain that they are free to tender new production from expansion areas such as that proposed for Pt. Mclntyre, with virtually no advance notice and at the same percentage rate as the state's then current in kind unit wide nominations for its RIK sales. This would create additional hardships for the state's purchasers, as they would find themselves in the difficult position of having to arrange for additional pipeline space and marine transportation to accommodate the producers' scheduling and planning over which the purchasers have no control and for which they may have inadequate notice. The effects of this unbalanced relationship would fall particularly hard on Tesoro, one of the state's in kind purchasers. In an attempt to improve its financial footing, Tesoro has announced a major recapitalization program and has taken steps to implement what it terms a "market-driven strategy" to reduce costs and improve refining margins. Crucial to that strategy is the reduction and fine-tuning of the volumes of RIK oil which Tesoro purchases from the state to more closely match product demand. Tesoro has pursued this reduction over the past several months through reductions in its nomination in conformance with the terms of its RIK contract and the terms of the PBUA. As a consequence of the proposed expansion, Tesoro's efforts would be disrupted, potentially increasing the state's litigation risk. In discussions between the state and the producers, they have evidenced a complete disregard of this complication and an unwillingness to mitigate its effects as evidenced by the correspondence attached as Exhibits 1 - 6. Production of the Pt. McIntyre reserves from a new unit would enable the state to elect its in kind and in value nominations to avoid complications such as these. Moreover, either formation of a new unit or the applicants' willingness to amend the existing PBUA to allow nomination by participating area would avoid these prOblems. Either would also reduce the state's litigation risk. However, the applicants have rejected either alternative. e) Miscellaneous Economic Issues There are other economic costs to expansion of the PBU. Recently, it has become apparent that the state's and producers' interpretations of the PBUA and 1980 Settlement Agreement are radically different. As litigation over the agreements has proceeded in the pending gas 25 related portion of the ANS Royalty. Litigation, the producers have adopted an interpretation of these agreements that is very unfavorable to the state. For example, the producers have argued that under the Fuel Gas Supply Option (FGSO) in the PBU Operating Agreement, they are not obligated to pay royalties on gas sold among themselves. Before implementation of the FGSO, some PBU producers set ANS prices at an artificially low level apparently to influence their obligation to one another under the FGSO. Another issue currently being litigated is whether the liquid hydrocarbons recovered at the Central Gas Facility (CGF) and subsequently marketed as ANS crude oil are subject to field costs. These issues involve the potential loss of hundreds of millions of dollars to the state. Expanding the PBU to include the Pt. Mclntyre leases would subject the leases to the same litigation risks burdening the PBU and would increase the costs of an unfavorable decision to the state. For all of the above reasons, the economic costs of expanding the PBU to include the Pt. Mclntyre far outweighs the benefits to be derived from expansion. IV. FINDINGS AND DECISION Based on the foregoing, I find: 1. The decision of whether or not to expand the PBU under the conditions proposed by the producers is discretionary. 2. In evaluating whether to exercise my discretion to approve the proposed expansion, I must determine that it is in the state's best interest to do so considering the specific facts and circumstances surrounding the application. 3. In making a determination that the proposed expansion is in the state's best interest, it is necessary to evaluate the proposal in light of the statutes, the regulations and the contractual obligations to which the state is party. As set forth in the body of this decision, I have determined that it is not in the state's best interest to approve the proposed expansion of the PBU and to form the PMPA within an 26 expanded PBU. Therefore, the application to do so is denied. This decision, however, does not prejudice any rights which the applicants may have to amend their proposal to mitigate the negative effects on the state's interest which have been described in this Decision and Findings. See 11 AAC 83.316(b). If they decide to do so or apply to form a separate unit, this decision will be reconsidered. Under 11 AAC 02.010-.080, the producers have thirty calendar days after the date of delivery of the decision to appeal the decision to commissioner. To be timely filed, the appeal must be received by the Department of Natural Resources, at 5th Floor, 400 Willoughby Avenue, Juneau, Alaska, 99801-1724, within the thirty calendar days. Ja~s E. Eason, Director DNtsion of Oil and Gas CC: Harry A. Noah, Commissioner Alaska Department of Natural Resources David Johnston, Chairman AOGCC Attachments: Delegation of Authority from Commissioner to Director, Division of Oil and Gas Exhibits 1 through 6 PBU.EXP.PMPA.D&F.txt 27 DELE ,., i'lONS OF AUTHORITY FOR THE DIVIS . , OF OIL AND GAS Regulatory Purpose or Authority C;tati(~n A~;tion Vested in Authority Delegated 1 I AAC 82.400 Parcels Offered for Competitive Lease Commissioner No Delegation 11 AAC 82.405 11 AAC 82.410 11 AAC 82.445 Method of Bidding Minimum Bid Incomplete Bids Commissioner Commissioner Commissioner No Delegation No Delegation No Delegation 11 AAC 82.450 11 AAC 82.455 Rejection of Bids Tie Bids Commissioner Oommlssloner No Delegation No Delegation 11 AAC 82.460 Additional information Oommlssloner No Delegation i i AAC82.465 Award Leases Corem ssioner Director, Div. of Oil Gas (DOG) 11 AAC 82.470 issue Leases Commissioner Director, DOG ll AAC 82.475 11 AAC 82.600 !I AAC 82.605 Bid Deposit Return Required Bonds Approve/Deny Assignments of Oil and Gas Leases Commissioner Commissioner Commissioner Director, DOG Director, DOG Director, DOG 02.610 11 AAC 82.620 Segregate Leases Transfer of a Lease, Permit or Interest as a Result of Death Commissioner Commissioner Director, DOG Director, DOG 11 AAC 82.625 11 AAC 82.635 Elf. Date of Assignments Surrenders Commissioner Commissioner Director, DOG Director, DOG 11 AAC 82.640 i 1 AAC 82.645 Survey Requirement Conforming Protracted Description to Official Surveys Commissioner Commissioner No Delegation No Delegation Delegations of Authority Page 2 Regulatory Citation Purpose or Action 11 AAC 82.650 11 AAC 82.660 11 AAC 82.665 11 AAC 82.7OO 11 AAC 82.705 11 AAC 82.710 11 AAC 82.800 11 AAC 82.805 11 AAC 83.153 11 AAC 83.158 11 AAC 83.303 11 AAC 83.306 11AAC 83.311 11 AAC 83.316 11 AAC 83.326 11AAC 83.328 11AAC 83.331 Control of Lease Boundaries Excess Area; Partial Termination Rental and Royalty Relief Taking Royalty in Kind Bidding Method Notice of Sale Production Records Test Results Well Confidentiality Approve/Deny Lease Plan of Operations Unit Agreement Approval Accept Application for Unit Agreement Approval Publish Public Notice of Unit Agreement Application Approve/Deny Unit Agreement Require or Accept Nonstandard Unit Agreement Language Mandate Unitization (Involuntary Unitization) Approve/Deny Change in 11AAC 83.336 Grant Extension of Unit Term; Grant Suspension of Operations (Force Majeure); Terminate Unit Authority Commissioner Commissioner Commissioner Commissioner Commissioner Commissioner Commissioner Commissioner Commissioner Commissioner Commissioner Commissioner Commissioner Commissioner Commissioner Commissioner Commissioner Commissioner Authority No Delegation No Delegation No Delegation No Delegation No Delegation No Delegation Director, DOG Director, DOG Director, DOG Director, DOG Director, DOG Director, DOG Director, DOG Director, DOG Director, DOG No Delegation Director, DOG Unit Operator No Delegation Delegations of Authority Page 3 Regulatory Purpose of Authority Citatior~ Action Vested in Authority 11 AAC 83.341 11 AAC 83.343 Approve/Deny Plan of Exploration Commissioner Commissioner 11 AAC 83.346 Commissioner 11 AAC 83.351 11 AAC 83.356 11 AAC 83.361 11 AAC 83.371 11 AAC 83.373 11 AAC 83.374 11 AAC 83.383 Approve/Deny Plan of Development Approve/Deny Plan of Operations Approve/Deny Participating Area Expand/Contract Unit Area Certify Wells as Capat:)te of Production in Paying Quantities Approve/Deny Allocation of Cost and Production Formulas Sever Leases Declare Unit in Default Notation of Approval on Joinder Modification of Unit Agreement Approval of Federal or Private Party Unit Agreements 11 AAC 83.385 11 AAC 83.393 Commissioner Commissioner Commissioner Commissioner Commissioner Commissioner Commissioner Commissioner Commissioner Director, DOG Director, DOG Director DOG Director DOG Director, DOG Director DOG Director, DOG Director, DOG No Delegation Director, DOG Director, DOG No Delegation I hereby delegate the authority vested in me through AS '38.05.180 to the Director of the Division of Oil and Gas as noted above. This delegation of authority is effective until revoked by me. Harry A. Noal~. CommissioneT""-'"~~ .. Alasl~ Depcrtment of Natural Resources /, ~ /, ,/ ,/ / Date WALTER J. HICKEL, GOVERNOR DEI~F. OF NATUI~kI~ RESOURCI~S DIVISION OF OIL AND GAS P.O. BOX 1O7O34 ANCHORAGE, ALASKA PHONE: (907) 7152-2553 Apr~l 30, 1993 Von Hutchlns Sr. Operations Engtneer ARCO AK Inc. PO Box 100360 Anchorage, AK 99510-0360 Dear Hr. Hutchtns, The State of Alaska (State) is reouestlngthat ARCO remove the Point McIntyre and North Prudhoe Bay State RIK allocations from the July 1993 nomination. These two areas are not part of the Prudhoe Bay Unit and the State does not wish to make additional nominations from these two areas at this tlme. If you have any questions regarding this letter, please call Linda Reem at 762-2556. Sincerely, Cress Royalty Accounting Manager d' rlk; 1 r;4/30/93 Exhibit 1 May 5, 1993 Ms. Nancy I.,, (:ress Royalty Accou,ting Manager Department of Natural Resources Division of O11 and Gas P. O. Box 107034 Anchorage, Ala.~ka 99.510-7034 Re: July 1993 Royalty Nomi.ntio.s for i'oint Mci.tyre n.d North Prudhoe Bay Slnte Dear Ms. Cres.~: This letter respo,ds to your letter of April 30, 1993, to V. i.. Hutchins. ARCO recognizes that the Slale of Alaska must approve the prod,etlon of hydrocarbon resources from the Point Mclntyre and North Prudhoe Bay Areas and that there are a number of issues Ihal are not yet resolved. If those issttes can be resolved, there will be ,o ability lo te.(ler the expected Poi.t Mclntyre and/or North Prudhoe P, ay State production to 'FA I'S in July 1993. unless the r~enlly submitted nominalio, s are made now by ali of Ihe ()w.ers of the exacted pr~uction, includi.g lhe SI;~le. If those issues ca.not be ti~.ely resolved, it ss likely that a July 1993 start-up will be impossible. For example, il' the State requires a separate unit for Point Mclntyre, quality bank issues between I~oinl Mclntyre and Lisb.rne which will affect State RIK purchasers will hnve to be rent,Ired. U.der those circur.,aances, there would not be any penalty for hnving over-s~omi~mted July 1993 production Io TAPS, For the foregoing reaso, s, AR("O requests that the State apply its RIK percentage from the PBLJ tO the e.tire projected commi~gled July 1993 I.PC production as set forth in ARCO's Prod.clic.~ I:orecasl letter of April 30, 1993. Exhibit 2 Ms. Nancy L. Cress May 5, 1993 Page 2 Plea,,~e call me al 265-6538 (ir Rosy Jacobsen at 265-6549 if you have any questions concerning this matter. Sincerely yours, · · Engineering Supervisor Lisburne/Point Mclntyre Engineering /pfm DEPT. (~F NATURAL i~ES(~URCES DIVISION OF OIL AND GAS WALTEfl J. t/ICI(EL. GOVERNOI 7, 1.1 ," PO BOX t07t33¢ ANCHOR.~(3E. ALASKA g9510.7034 PHONE: Ig0T) 782.2553 May 6, 1903 J. L. Harris, Engineering Supervisor Lisburne/Point Mclntyre Engineering ARCO Alaska, Inc. P. O. Box 100360 Anchorage, Alaska 99510-0360 Dear Mr. Harris: I am in receipt of your May 5, 1993 letter to Ms. Nancy Cress regarding July 1993 royalty nominations for Pt Mclntyre and North Prudhoe Bay State. I have carefully reviewed the rationale provided In your letter for ARCO's belief that it is appropriate to apportion royalty production from Pt. Melntyre and North Prudhoe Bay State No. 3 according to the state's current royalty nominations for Prudhoe Bay production. Nevertheless, I am unpersuaded by any of the arguments which you have made that there is a rational basis for determining that it is tn the state's interest to accept your proposed nominations. I would like to reiterate, as Ms. Cress has before, that the state has not nominated, and we do not desire to nominate, any in-kind deliveries from either l't. Mclntyre or North Prudhoe Bay State at this time. As you are no doubt aware, we have royalty in-kind contracts with Tesoro and Mapco which limit the oil they are entitled to take to either a percentage or a fixed volume of royalty oil from Prudhoe Bay Unit production, ltowever, as neither Pt. Mclntyre nor Pruflhoe Bay leases are part of the Prudhoe Bay Unit, it is inappropriate that you should unilaterally nominate on behalf of the state oil for in-kind taking to the benefit (or detriment) of our in-kind purchasers. Accordingly, please revise your nominations to reflect the state's wishes immediately. Sincerely, / /James E. Eason I~"Director CC: Glenn A. Olds, Commissioner Bruce Botelho, Deputy Attorney General Jim Baldwin, Assistant Attorney General Patrick Coughlin, Assistant Attorney General Bill Van Dyke, Lease Administrati{~n/Rovaltv Accoutering Manager Nancy Cress, Accountant Mike Welch, Mapco Alaska Petroleum Exhibit 3 Don Reep, Tesoro Alaska Petroleum Company WALTER J. HICKEL, GOVERNOR DEPT. OF NATURAL RESOURCES DIVISION OF OIL AND GAS PO. BOX 107034 ANCHORAGE, ALASKA 99510-7034 PHONE: (9073 762-25,53 (907)762-2547 June 3, 1993 Colin Howard, Vice President & Chief Counsel ARCO Alaska, Inc. P. O. Box 100360 Anchorage, Alaska 99510-0360 Dear Colin: This is a followup to the telephone conversation which you, Patrick Coughlin and I had earlier on June 3, 1993. Patrick and I called you to discuss the implications of the August 1993 LPC production forecast dated May 28, 1993 which arrived with a cover letter from Mr. V. L. Hutchins. I expressed my concern about the continuing nomination of Pt. Mclntyre production as if it was production from the Prudhoe Bay Unit and allocation of that production to R1K and RIV components, notwithstanding my earlier letters to ARCO requesting that you revise those nominations to reflect that the Pt. Mclntyre production is not part of the Prudhoe Bay Unit and that the state has made no RIK nominations affecting that anticipated production. Based upon our conversation, I understand that ARCO intends to reply to my earlier letters, but that it has not yet coordinated that reply with its partners at Pt. Mclntyre. In the meantime, I wanted to confirm my understanding of one specific portion of our conversation. You stated that, should the application to form the Pt. Mclntyre Participating Area within an expanded Prudhoe Bay Unit Area not be approved, these nominations really will not be an issue because the Pt. Mclntyre owners do not intend to tender any Pt. McIntyre oil to TAPS absent approval by the state of the application. As we discussed further in our conversation, I believe it is important to confirm this understanding because otherwise the state would need to notify Alyeska of a potential dispute over ownership of oil being tendered to TAPS. Exhibit 4 Colin Howard June 3, 1993 Page 2 I,elleve that I Itave accurately stated the substance of this portion of our conversation. have it wrong, please let me know so that, if necessary, I can promptly notify TAPS. Sincerely, re eS E. Eason ctor cc*, Glenn A. Olds, Commissioner, Department of Natural Resources Harry Noah, Commissioner Designee, Department of Natural Resources Bruce Botelho, Deputy Attorney General, Department of Law Patrick Coughlin, Assistant Attorney General, Department of Law Gayle Simmons, Vice President in Refining, Tesoro Alaska, San Antonio, Texas Mike Welch, Senior Accounting Supervisor, Mapco Alaska, North Pole, Alaska ARCO Alasl(a. Inc. Legal Del3artment Post Office Box 100360 Anchorage, Alaska 99510 Telephone 907 265 6541 Colin C. Howard Vice President and Chief Counsel June 17, 1993 :q 15',3 E iVED, Mr. James E. Eason Director Division of Oil and Gas Alaska Department of Natural Resources P.O. Box 107034 Anchorage, AK 99510 RE: Point McIntyre Production Allocation/Offtake Schedule Dear Mr. Eason: This confirms our earlier conversation concerning the commingled production forecast for the Lisburne Production Center. As Operator, ARCO believes that it has no alternative but to continue to issue such forecasts, including projections of Point McIntyre production. Such forecasts allow all owners, including the State of Alaska and its RIK purchasers, to be able to protect their rights to have access to TAPS. Such access to TAPS will be desirable in the event the State approves the Application to expand the Prudhoe Bay Unit and create a Point McIntyre Participating Area. As an Point McIntyre Working Interest Owner, ARCO believes that it has no alternative but to pursue expansion of the Prudhoe Bay Unit and creation of a Point McIntyre Participating Area. As we have discussed, the sharing agreements required to utilize Prudhoe Bay Unit facilities would be greatly complicated, if not make impossible, if such agreements were for a non-unit operation. Additionally, dividing commingled production into different nominations to TAPS will create perpetual imbalances between the Working Interest Owners and the State and its RIK purchasers due to the nomination procedures imposed by the tariffs approved by FERC and the APUC. Separate nominations '~ouid also greatly complicate quality bank payments with respect to RIK purchasers -~hich will only be made ~;orse if any changes are made to the quality bank in the current proceedings. Exhibit 5 aRCO AlasKa. inc. Is a SuO$1dlar¥ o! Atlantlcfl'i~hNei~lComoan¥ James E. Eason June 17, 1993 Page 2 With respect to the effect TAPS tariffs nomination procedures have on divided co~tmingled production, we do not believe that a State challenge to those procedures would result in any change simply for the lack of any practical solution. The potential for such problems is created by the approval of commingling upstream of TAPS, not the tariffs. With respect to Point McIntyre. field start-up and actual delivery of its production to TAPS, ARCO believes that the State can prevent such start-up and related deliveries by withholding final or temporary approvals. We do not believe that any such withholding of approvals and resulting delay of Point McIntyre start-up would be in the best interests of any party, including the State. As I mentioned to you, ARCO hopes that the State will preserve the option for a Point McIntyre start-up as part of an expanded Prudhoe Bay Unit. The State can preserve such an option by advising its Prudhoe RIK purchasers as follows: First, tha~ the Prudhoe RIK purchasers may or may not receive an allocation of Point McIntyre production. And second, that they should take whatever steps they deem desirable to protect their ability to receive such production in their TAPS nominations.under those circumstances. Please call if you have any questions or would like additional information. Sincerely, Col in C. Howard ARCO Alaska, Post Oil[ce 6ox 1~ Ancho~a AI~ ~51~ T~epho~ ~7 2~ ~5 James D. Weska Senior V'me President Mr. Harry Noah Commissioner Department o[ Natural Resources P.O. Box 107034 Anchorage, Alasha 99510 DIV. OF"O'!L,& GAS/ Subject: Point McIntyre Dear Commissioner Noah: This letter is in response to the State's counterproposal relating to Point McIn~e interim approvals and project start-up which was f-axed to us at the dose of business on Friday, July 2. Although we are encouraged that the State shares the desire to "advance the project and to protect all parties interests.., while preserving the State's and the Producers' administrative and legal rights and remedies," we are extremely disappointed with both the general approach and the specific substance of the State's counterproposal Attached is a specific list of comments and questions which more fully addresses our concerns. Because a delay in start-up is neither, in the State's nor the owners' best interest, we would hope that the expansion of the Prudhoe Bay Unit (PBLD ~n be finalized with the State. If the State would explain its concerns regarding the start-up of Pt. Mclnt~e within the PBU along the concepts proposed in my fax of June 30,1993, it would help us understand why the State believes that its rights and positions would not be preserved by our proposal, and why a counterproposal was deemed necessary. In addition, the counterproposal suggests that we produce hydrocarbons as a "tract-by- tract operation" during the interim period. However, a "tract-by-tract operation," which is apparently neither a unit operation nor a lease operation, is not addressed or defined by State statute or regulation. Therefore, an entire "set of rules" or agreements would first need to be developed for the interim period. Defining new rules woukI not only be a complex and time-consuming process, but it would most likely add a new subset of legal disputes. In our proposal, the interim period is well defined by existing statutes, regulations, agreements and contracts which already govern the PBU. Exhibit 6 ARCO ~ Lin:. it · .~t~ldl~W o! Atl~n~ Rlg~fle4~ C~hy · JUL 09 '93 l l:5?AM ARCO AK 21 FL I. D. WeekstH. 1~..., July 9,1995 Page 2 Finally, the State's counterproposal does not meet the requirements specified by the Alaska Oil and Gas Conservation Commission Conservation Order 317, dated July 2, 1993, which requires the subject leases be in a unit prior to production. Our proposal satisfies this condition. The Division of Oil and Gas counterproposal does not. Under our proposal, Point Mclntyre would be a unitized operation both during the interim period and ~ter final resolution of the outstanding issues. Thus, we believe all State agencies' requirements for start-up will be met. Harry, you said you would not deal with these issues under the time pressure of start- up. I respect and agree with that. It is unreasonable to expect us to behave any ciifferenfly. Negotiating a new, separate unit agreement prior to start-up puts us in the same position you refuse to be in. The same issues in contention now will be in contention whether Pt. Mclntyre is in an expanded PBU or a new unit. Not expanding the PBLI now resolves nothing and only creates further delay. Something like my June 30,1993 proposal is the only practic.~l way to enable early production from Pt. Mclntyre and preserve all parties' rights and obligations, and I urge you to accept it. We look forward to discussing these issues with you in person. Sincerely, J. D. Weeks Senior Vice President Attachments I. E. Bason J. B. Golden A. D. Simon Detailed Comments Point Mclniy~ Field DNR Counterproposal of July 2,1993 2~ ~.tate Statement:. "Your application to operate the Narth Prudhoe Bay State No. 3 well (NPBS #3) as a tract operation demonstrates that the producers, i/they desired, could make arrangements to share facilities with the l_isburne and Initial Partidpating Areas to produce Point Mchttyre as a tract operation." .Comment: ARCO Alaska's application to DNR regarding the NrPBS #$ well, dated May 17,1993,I was filed in accordance with Article 4.4 of the Prudhoe Bay Unit Agreement ("PBUA") and Article 8 of the Prttdttoe Bay Unit Operating Agreement CPBUOA"). In that application, ARCO requested approval to operate the NPBS #3 as a "Tract Operation." As the State is aware, the term "Tract Operation" is defined not by statute or regulation, but by the PBUA and PBUOA. Thus, 'a Tract Operation can.not occur outside of the Prudhoe Bay Unit. It is precisely because the NPBS #3 well is within the Prudhoe Bay Unit and already covered by existing facility sharing agreements that the expeditious development of the N'PBS accumulation has been made possible. S..tate ProPos_a_h '"the Point Mclntyre leases will be produced as a.tract-by-tract operation on an interim basis." Comment: We are unaware of any definition in State statutes or regulations which defines a "tract-by-tract operation." As such, we believe the lack of governing procedure virtually guarantees protracted disputes and a lengthy process attempting to define an approach acceptable to all parties including multiple State agendes, TAPS, the State's RI~ purchasers, and potentially other admirdstrative agencies. Furthermore, numerous and complex existing agreements between the producers would need to be amended under this approach. The Alaska Oil and Gas Conservation Commission CAOGCC") has concluded that "the unitized management, operation, and further development of the Point Mcln~e and Stump Island oil pools is reasonably necessary to effectively carry on pressure maintenance and enhanced oil recovery operations to maximize ultimate recovery." Further, the AOGCC's requirement that "regular production may not begin until the interests of the workin§ interest and royalty owners are integrated in accordance with the provisions of 20 AAC IThe North Pmdhoe Bay State No. 3 well spudded on lanuary 2, 1993, and reached TD on February 1, 1993, with a bottomhole location situated on ADL 28297 within the Prudhoe Bay Unit. On April 14, 1993, the DNR issued a notice of contraction impacting the lease which is currm~y under appeal to the Commissioner. Perforating and testing of the well was completed by April 19, with estimated daily flowing rates of approximately 3000 b/d. Application was filed with the DNR on May 17, 1993, for 1) Certification of NPBS No. $ as capable of producing in paying quantities, 2) Request for Tract Operation of NPBS No. 3, and 3) Filing of the Plan of Development and Operation for North Prudhoe Bay Reservoir. Page 2 . 25.517" (Rule 1, Conservation Order No. 317) requires unitized operations before production can begin. For these reasons, the "tract-by-tract" ope. ration proposed by the State is inconsistent with the AOGCC's requirements. State Proposal: "An example of a similar interim methodology is the manner in which the Kuparuk River Unit leases were produced before approval of that Unit." .Q.9.1~11.¢~: Although there does not appear to be any formal documentation of the interim producing arrangement at Kuparuk, decisions and findings of the Commissioner Department of Natural Resources note that production commenced on a lease basis on December 13, 1981, and the Unit was approved on March 26, 1982. However, the decisions and findings also states that production was from five leases solely owned by ARCO Alaska. These leases have the same royalty burden and identical lease forms. Production was also achieved from a standalone processing plant and it is our impression that production was allocated to the lease from which it was produced. In contrast, the State's proposal would allocate Point Mclntyre production on a "unitized" basis (without a corresponding Unit Agreement) to encompass six leases of three ownership types, two of which will not be under active production. This production will occur through a commingled versus standalone system. For these reasons, any analogy between Kuparuk and Point McIntyre is inappropriate. State Proposal: "Royalty (interim) production will be allocated...on reserves." ..Co~rn men t: We are unable to deduce the reasoning for solely utilizing "black oil" reserves as a basis for allocating production on an interim basis. AS 31.0§.110(c)(2) requires that equity allocation be based upon value, not solely '"olack off" reserves. 5. S_ta.l:e Propose!; "All royalty' will be paid in value." , Comment: As noted in footnote 14 of our Appeal To The Commissioner, filed on June 4, 1993, a change in the nomination process will cause a perpetual imbalance between the producers and the State's royalty-in-kind purchasers. (See Attachment 1) State Prop_osal: "The Commissioner of the Department of Natural Resources will determine the final tract allocations." Comment: 11 AAC 83.351 and 83.371 clearly define the Commissioner's authority to approve tract allocations or "find irt writing that the formula does not equitably allocate production and costs among leases." However, these regulations do not empower the Commissioner to determine final.allocations. Page , 8~ Thus, the State's proposal is contrary to State regulation and would result in a reduction of the producers' existing administrative rights, State_P. roposah "The producers shall have the right to appeal..." Comment: We interpret points 4 and 5 of the State's proposal to merely suggest the full course of administrative and judicial process remains in force and is not modified in any fashion by an interim agreement. Although more minor in nature, we would see the sequence of determination of issues to be 1) a decision on "Appeal To The Commissioner," dated June 4, 1993, concerning deferral of contraction of certain leases from the Prudhoe Bay Unit, 2) a decision on producers' application made on March 18, 1993, to expand the Prudhoe Bay Unit and form the Point McIntyre Participating Area, and 3) with expansion of the Prudhoe Bay Unit field cost deductions would be as defined by the 1980 Settlement Agreement, absent an expansion of the Prudhoe Bay Unit the amount of deduction for cleaning and dehydration would need to be resolved. State Proposal: "If the leases ultimately become part of the Prudahoe Bay Unit, then none of the State's royalty will be royalty in kind until 120 days...unless the State...is able to make arrangements with its RI]( purchasers." _~_oa~B.I]~31: As noted in part 5 above, we believe that the State's request for 120 days illustrates the complexity which will result if the nomination process is changed, pursuant to the State's counterproposal. 11: ~I HKL,U HR. ~1 ~ L i,,~ Attachment environment, fish and wildlife, to mitigate possible damage to surface acreage, and to prevent economic and physical, waste. Inclusion of ~e Subject Tracts in the Prudhoe Bay Unit is vital to the pr~tuction of the Pt. Mclntyre reservoir. It is clear that the administrative hur6tes to producing Pt. McIntyre outside the umbrella of :he Prudhoe Bay Unit are signi~cant and costly, and would result in lengthy delay in Pt. McIntyrc start, up. For example, if the Pt. Mclntyre reservoir were to be excluded from thc Prudhoe Bay U nk, the Pt. Mclntyre Owners either must produce thc rcservoir as lease operations or must apply to the Department to form a new unit. For either to occur, the Pt Mclntyre, Lisburne, and Prudhoe Bay Owners must nego. tiate and execute new agreements regarding the sharing of' facilities, infrasu-ucture, powc'r, water, and gas management, among other firings. The agrccmcnts covering these subjects have mkcn up to lhrce years w ne§ociate; thc agreements which would be required among these parties if the Pr. McIntl~ reservoir were not included in the Pmdhoe Bay Unit would be more complicated and could possibly require at least as much rime :o negotiate and execute. Furthermore, royalty implications, tax partnership, quality bank, common carrier and revenue sharing concerns, and TAPS nomiuation and allocation procedures I4 must bc idcntificd and satisfactorily addressed, and the necessary agreements must _:-.._., ,_.....- _ ..... . ~aFor e~aml)le, if ptodu~lm h'om att af Pt.. M~Xnt,,/m is ~ot nomina~d to TAPS as panel the TAPS nominatinn and allm:atam pmcednn~ will caum a petw-""' imbalanc~ between thc lmXim:cts and tim Sta~s Rovait,/tn Kind The imbalance will result from the fact that nominations to TAPS are based upon ~ pmdnctton whereas allocations of shipment via TAPS ate based upon actual production. This d_iffcrence can be ea_~!y shown by examp~ Comminel~ LI~ l:h'oduction ~mated Ac~ai Pt. Mctntym 70M STB/D 00M STB/D L.isboma 27M STB/D 30M STB/D Wes~ Bear. it 3M STB/D 4M STB/D If tile estimated 100M STB/D is tendcrexi as one nomination as pan of Lisbunle Production Center pro(iuction from the Prudhoe Bay Unit, the RIK purchasers will receive their full share of the lesser actual production. If thc estimated 100M STB/D is tendetext separately, Pt. Mclntyre will b~ allocated 70~b of the actual commingled production and Lisburne/Wesl Beach will be allocated 30%. In this example, Pt. Mctnp/m would receive 70% of 94M STB/D or 65.8M STB/D and Lisbume/West Beach woutd receive 30°I, at' 94M STB/D or 28.2M STB/D bc negotiated. In addition, either l~asc operati. 'ohs or operation under a new unit would require a new round of agency approvals. The new circumstances would complicate agency decision- making, ar best, and at worst may preclude issuance of the required approvals. The situation could easily dcgcncrate into a web of litigation, iunhcr adding costs and delaying resolution. In sum, thc exclusion of thc Subject Tracts from the Pradhoe Bay Unit necessitates enormous administrative tasks which could delsy production start-up for years. During that ~im_c, c-very party, including the State, w~uld be precluded from enjoying the revenue from Pt. McIntyre production. Because the criteria of 11 AAC I/3.303 arc met, and due to the circumstances of uh¢ Pmdhoc Bay Unit, the conwacdon of the Subject Tracts should continue to be deferred. · B. Only!ands wMch are "not included or entitled tQ.l~ iucl,,de~in a Panicipatin_g~ ^~_" can ~ lawfully contract4. _ Article 9.3 of the Prudhoe Buy Unit Agreement CPBUA") states: Any lands not included or entitled to be included in a Participating Area on the tenth (lOth) anniversary of the Effective Daie shall be excluded from thc Unk Area and from this a~cement. Because the Department approved the dcfcrral of the conwaction of the Subject Tmcu through March 31, 1993 (Al!'?_chrnent C), PBUA 9.3 has been effectively ~mendcd to read as follows: Any lands not included or entitled to be included in a Participating Area on March 31, I993 shall be excluded from thc Unit Area and from this agreement. Under this provision lands can only be excluded from the Prudhoe Bay Unit if they are not included or entided to be included in a participating area on March 31, I993. In the present case, portions of the Subject Tracts ~ entiflcd to be included in a participating area on March 31, 1993 and are still entitled to be incIudect in a participating area. Indeed, the Pt. Mclntyre instead of the 34M STB/D acm.,y produced. Unless the State has elected RIK from ail fields in equal petceut,$~ for exactly the same RIK purchasem, ~he RIK purchasers will reccive their shat~ of 2~.2M STB/D instead of a share of the 34M STB/D to which they would be en,iflext ~o receive. 12 August 31, 1993 Alaska Oil and Gas Conservation Commission 3001 Porcupine Dr. Anchorage, Alaska 99510 Re: Pt. McIntyre Public Hearing Dear Commissioners: I am writing this letter in regard to the public hearing notice on Pt. McIntyre. I am currently being sued by Exxon Corporation to extinguish my rights in the Pt. McIntyre field. A federal judge in Texas has ruled in favor of Exxon. I, along with Mr. Miklautsch and Mr. Hamel, am appealing the federal court's ruling. The appeal is being heard on September 8, 1993 in New Orleans, Louisiana. Pending the results of my appeal, I expect the State of Alaska to put aside, in escrow, any monies that are due. If I lose the appeal in New Orleans, I am going to thoroughly investigate the State of Alaska's collusion with Arco and Exxon to keep Pt. McIntyre from being produced from the time it was first discovered in the 1976 - 77 drilling season. Arco and Exxon have acknowledged in writing presented to the State of Alaska that the field had been discovered in 1988. In fact, the field was discovered by Gulf Oil during the 76-77 drilling season when both Pt. McIntyre #1 and Pt. McIntyre #2 were drilled. At the time, Arco, Exxon and the State of Alaska knew that the field was capable of commercial production. The State of Alaska is required by law, and its own rules and regulations, to protect the rights of every individual and company involved in a field. I was never privy to the information that the State shared with Arco and Exxon. But I trusted the State of Alaska to protect the rights and interests that I had in that field as required by law. Again I am asking the Stat~ of Alaska to protect my rights and asking that any money from production on leases ADL 34622 and ADL 34623 be placed in escrow. I am .also asking the State to provide me with all data pertaining to the producing area and the technical public information that applies to those two leases. C. Burglin $ E P - 8 199 Alaska Oil & Gas Cons, Comt~iss[o~ Anchorage C. Burglin L~nd Cons~t~nt P,O. Box I31 Fairbanks, Alaska 9970? (907) ~2-5149 P. 1/? Fax# 907~452-5203 FACSIMILE COVER SHEET TO: FROM: NO. OF PAGES: ~)~' SgNDER INITIALS' (INCLUDING COVER SHEET) RE: If you have any questions or problems, please call (907)452-5149, "' .... ."OCT 14......",93,..08:.03 CLIFF BURGLIM A].~"~i~'.!'~";i.. AOflC¢, an4 u],t~.ma~eZy, baaed upon..~he cer~lf2ca~on ':',':'~'~'~';:":'~'y' ~he' 8tat~, of Alaska that .~h~ P~,'. M~Zngy~" w~ll '",C'~9a~le,.,':of,'producin~ oil" and gas in' commarica! quantites (Exhibit "D".)"'"'Vi~' a,, . ,. vl~' hha~ th~ w~ll i~ capable of.pro~u~ing ~00 BOPD ...'such '"'a' fac% is supDo~ted . by the sworn testimony -' of ",~,mDre'~'n~a%lve of ARCO upon. a~pearin~' before the AOGCC h'paring held March 24, 1993 in Anchorage, Alaska. ,.. , , . '8'7" FU:rthe'r Affiant' Sayeth ~0t; '~',.,,. ~., AFFIANT: CLIFFORD BURGLIN THIRD JUDICIAL DISTRICT STAT~. OF ALASKA On thim day personally appeared before me tn~ duly undersigned au=hoPity ~lifford ~., Burglin ~ho having identified himsel, f to me did sta~e under oath that ~his is a true and accurate . ~ep~e~enta~.ion~ of the faatz and opinion~ regarding the ~ circums%an~es surrounding ADL 3462'2 and ADL 34623 located in the kno~ by him to be a true and accurate record of such facts ~=ade ~0 t~ b~t Of h.i~ ab[!ity. ,- ,, :,~ '[ ...... ",,,. w,*', ~ ~ ' .. ~ -, ~,, % '%'"~'".h, ~ ~,, ,, .,,~,, -' '~' ,., ', F IE'.Ii~I"'I : !["IFE' ['"1 F'CI:STF4L SEFE'~,.~ICE I::'H;:d~E l..lO, ' 713 5'"5. .. . { OIG ~0~ ~ V I b 0F CO~E~TIV~ RIGHTS, OTHER ISSUES INCLUDIMG THOSE OF WASTE PRESENTLY PENDING BEFORE AGENCIES OR REPRESENTATIVES OF THE FEDE~L GOV~R~NT This motion is presented on this the 9 th day of September, 1993, before a duly constitutcd Commission representing the State of Alaska subject to the fol]owlmg; Movant Jack 0. Hakki%a does hereby~ certify that he i~ a citizen '~i ~e Unit'ed States of America, th&t his date of bir~.h in 6/26/40~ and that he was bern in Wil~imanti~ in the State of Conne~IG~%.. The Movant recievee mail at P. O. BOX 61604 Fairbanks, AlaSka 99706-1604 and the M~van%m~m telephone number is (907)-457-7902. Movant Albert ~, ~awyer ~oe$ hereby certify that he is a citizen of the United States of America, that his dat~ of birth is 7/19/24, and that he was born in Alkton in th~ State of Michigan. The M¢¥'an~ rasides at 3205 Spenard R~. AnChorage, Alaska and th~ ~ovant~m telephone number is (907)-B63-4599. Movant Mark Alexander does hereby certify that he is a citizem of the United~$~ates ~f America, that his date of bir~h i~ 5/4/$~, and that he was born il~ t~ State of New Mexico. The ~Qva~%% resides at 7502 Alcomita Houston, Te×as 77083 and the Mcr&ntis telephon, e number i~ (713)-561-6589, 1. That the Movant files this Motion on behalf of Jack O. Hakkiia, Albert H. Sawyer, Mark Alexander, and the citizen~ of the united States of America with specific ~eference to the correlative rights associated with P.L.O. sate ~571 (U,S. Survey 4044) and two other P.L.O. site~ known to be encompassed within the proscribed limits of tt~e Pt. MoIntyre (a.k.a.) Pt. G~ologic Structure. 2. In additiun to a claim of correlative rights, Movan= Alex~nd~r f~rth~r asserts a claim to the right as a United citizen expressing an Interest in ~eeking %~ end,rcm conservation of resources of the State of Alaska. This right of Interest is heid in Gommon with the ,ubligat. ion of the Commission ~or "the prevention of waste" pursua~%t to 20. AAC ~.517 (b) The right of Interest claimed by th~ Movant was acknowledged by Court Order in paragraph #4 of the Order of Dismissal issued in civil action NO. H-92-~41 date~ September 17 , 1992 as recorded in the United States Dimt~ic% C~urt :f~r th~ Southern Distri~ of Texas, HOuston., Divi~i~n. 3. The individuals heretofor~ identified me Movant~ hereby assert and prement their statements c,f q~a!if!cationm in or,er to clai~n an "Interest"' in ADL 34622 and ADL 34623 which' much rlght is allegedly protected under the cci.or of Alaskan Admini~trative Code 20 AAC 25.517. 3A. The Movants m~k an interpr~tation from th~ Commission relative to the use of th~ term "In'tere~t~' in ~m~ula~ion 20 AAC 25.571 (~) by acknowledging and illuminating the un~pecifled degree tc which the term ~'Intare~t'~ rolatc~ to the protection of correlative right~ in ~he abseDce ~f an agreement which ooncern~ Intere~t~ other than mineral interemt~ and in th~ presence of an agr%ament which concerns Interests o~:he~ than mineral interests. 3B. The Movants meek a'~ inter~retation of tho basis that allows th~ ~tat~ of Alaska the meanm with which the Commis~ion "integrates the int~r~st~ ~£ ali per~ons owning an intcrogt in the pool or portion of th~ pool.'~ Accordingly, in as much as 20 AAO 25.517 (~) does not by d,,finition exclude a broad interpretation of the word "inter, st" the Movants ~laim that their Inter~st~ a~e held jointly an~. ~everally and stipulate that Inte~est. s are ~ubject to oral and written agreements. The Movants c~t% Alaskan Administrative Code Title 20 Chapter 2s Subsection 570 D~FINITIONS which omits defining in~erest nor impose a limitation% or other r~$triction upon the word "inter%~t". 3c. Thc Movan~s cit~ 11 AAC 02,205 ~TATEMENT OP QUALIFICATIONS (4) (e) (1) Which enabl%$ the confiden~ia! a~sociation of an untnc~po'rated buminess enterprise to re!e~se a statement describing the busi. ness relationshi~ between ~he members. In accordance therewith the Movants ~ subm_t the foll~wing statement to the commission. Th~ principals a~e end,ged ~y means o~ an un~.ncorporated &ssoclatlor, whose purposes are based upon the ae~ulsltion and dispomition of Interests or options on Intere'mts. 4. Aa a caveat to issuing a final unitization or pooling agreement the MOVants ~eek a ~r~liminary ruling from the commission to declare ~'all confidential information" relative to t.he former P.L.O. sites without exception, "open for ~ubllc inspection~' on the ba~is that =he rt~ht to protest the issuanc~ of fmderal patents on thes~ Public Lands is s~ill a valid ~ubsi~ting right of each and every U.S. citizen and, tha~ "full. disclosure'* is necessary in the ~'in~e~?est" of conservatiou and in %he in%crest of preserving the correlative rights of th~ Movant~ and their right to protest the issuance of fedm~al 9atent~o 5. The Movants would produce as evidence and present before the Commission certain documents proffere,~ in accordance with 20 AAC 25.260 w'hich ~on~ern an allegation of illegal production. The Movant~ stipulate that %he com_~ission mak~ availab!~ for public inspection all eonfldential info'rmation regarding the "flOW testing'~, of the...Pt. Storkers~n #1' Welt, =he Kup Delta 5i'-1 well, an~ the K~ap Delta 51-~ well, The Movants offer the op!nol~ that certain well r'eoords depict evidenGe c,f comingled fl~w test data, ~vidence of comtngllng, and evidence of the implementation of downhole 9~ocedures an~ practises wh~[ch call into question %he possible acquisition of "confidential" data and the circumstanues regarding the ~lease ~f such data to agencies of thz ~'ederal -2- · , government. Th6 ~ovantm refmrmnee ~p'~cif!c Schlumbcrgur field tickets ~ invoices previously presented t~ th~ Alaskan Attorney C~~lls O£flce an~ to agencies of the federal gQvernm-nt. S~mply put :his evidence when ¥iewed in its totality does or doe~ ~Ot substantiate the existence of the Storkersen Geologic Structure a.k.a, the Pt. McIntyre ~eoiogic Structure(~) made the basis of an affidavit filed with the state of Alaska dated on or a~out De~ember O~ ~. The Movants seek a preliminary finding from the Commission that in accordance with 20 AAC 25.530 the' comr~ission hereby agrees ~o withol~ all pending actio;~ and meetings of the Commi~sion until a written response is in the possession of the Movant Ma~k Ale×an~e~ with ~mgard to specific information ~ubmitted to the Bureau of Lan~ Management, the Federal Bu~u of Investigation, the Alaskan Attorney General'~ Offices, the solicitor ~eneral's office O~ the United $~ates of America (Anchorage offioe), the Office of the Inspecter Genera5 of the Department of Inter, or, ~hm ~ffi~e of the Secretary of the Department of Interior, ~ha office's of the ~onorablm Congressman William Archer of the State ~f TeXas and that these responses are judged to be cons!calve, Drobative, or di~positive in the efforts of the Commission. 6A. The Movants seek a preliminary finding that ~he Commission compel m~oh responmem ~o be produced in mvidence and presented before the Commission relative to the aforementioned wells, ~he aforementioned pub].ic land orders, and with specificity regarding the Pt. Storkersen Geologic Structure identified in the AffidaVit of first discovery filed in conjunction with the Pt. Storkersen #1 well to~ether with all exhibits and attachments therm%o and that much info,etlon by ord~r of this Commission be ~reserved, present~d, ~nd made a part of the official public record prior to issuing a finding regarding pooling, unitization, or waste and the disposition of the correlative rights and intereite of the MOVa~ts and others. 7. The Movants ask that the Commission address the lim~.tations of Alaskan statute 31.05.150 in any instance where it can be mhown that in the specific instance ¢itied the ,'person'' referred to by AS 31.05.160 as defined by AS 31.05.170 (10) may in fact and in some rare instance become either the Attorney General of Alaska or an Assistant Attorney General. in which instance the State of Alask~ would in ~hat rare instance represent both the party Plaintiff and the Party Defendan~ under oolor of title thus mreating a ~evice or other mean~ by which t.o ~ender AS 31.05.160 impotent. 7B. The Movants seek ~ ruling from the Co~uuis~ion acknowledging the fact that current and past p~acti, ses and procedures as exemplified With regard ~O ADL 3462~ and ADL ~4623 precipitated multiple lawsuits and enabled unrecordedl agreements of various ilk and kind, ~ not routiRely fall under the perv]~w of the Alaskan natural resource agencie~ and depar~..ments thu~ thes~ -3- F~'!3r'i ' ,f'l~' I'I F'O',=:T~L '::~,-..';'.-;E 682 R'_-3F', 1922 F'HOHE NFl. ' -' - ~ em'--"'"~ ,"1.3 ._. _,, ,_,~ TO: 987 272 5192 P. in~tanc~ can and have adversely affected mineral title and in oertain in~tance~ will continue to result in damage to the correlative ri~ht~ of other mineral int~em~ Qwnars especially when th~ mi~%~ra% interest owner is not thm lessee of record or is not the Operator. Respectfully submit:ed, Albert H. Sawyer /-'~ CERTIFICATIONS Ba it known that on thi~ day I, Albert H. Sawyer state under oath that thm m~at~ments of facts and opinion~ ~xp~e~se~ in ~his Motion are within the knowledge of this Movant true and ~orrm¢~, This Movant caused to be mailed a copy of this Motion to Jack O, Eakkila for the limited purpo~ o~ a.%lowing Jack O. Hakkila to ~.e such a d~cum~nt before a co~u~i~sio~ of ~h& S~a~e of Alaska for the purposes, and intentions depicted herein an~ hereby. Be it kno~n that on =hi~ day I, Jack O. Hakkila state under oath that the statements of facts and opinions expressed in this Mo%ton a~ within the knowledge of this Movant =rut and correct. Thi~ Movant cau£od this Motion to be filed and p~esent~d before a commission of the State of Alaska for the purposes and intentions depicted herein and hereby.. ack O, Hakkila ', E;EF', E19 ' 95 t 1: 07. Er,lI LY F'ICI<ETT , F'F,'CIPI ' !i,'IF..: r.1 POSTAL ~ ..... , ' .~ ~. .. E,C~2 F:'3S 1922 TO: F'htEtt'..IE t'40, ; ,"7].. 3 ?"-~ '37S4 Be it known that on this day ~, Mark Alexander state undm~ oath that the statements of fac~ and opini~nB expressed in thi~ Motion are within the knowledge of tlhis Movant true and This Mov&nt caused to be matiud a co]9y of %him Motion to 3&ck Hakkila for the limited purpoee of allowing ~ack O. Hakkila to file such a document before a ~ommi~giion of th& ~tate of Alamka for thu purposes and intentions depicted hermin and hereby. . ./?...-/ ...... Mova~.,~ Mark Alexander -5- E ON COMPANY, U.S.A. POST OFFICE BOX 2180 · HOUSTON, TEXAS 77252~2180 · (713) 656-3431 LAW DEPARTMENT GARY E. BAKER COUNSEL August 10, 1993 Notice of Interest- Pt. Mclntyre Show Cause Hearing Mr. David W. Johnston Chairman Alaska Oil and Gas Conservation Commission 3001 Procupine Drive Anchorage, Alaska 99501-3193 Dear Mr. Johnston: Exxon has received a copy of the Commission's August 6, 1993 notice that the Commission will conduct a show cause hearing on September 9, 1993 to determine whether any action is necessary to prevent or to assist in preventing waste, to insure a greater ultimate recovery of oil and gas, or to protect correlative rights of persons owning interests in the Pt. Mclntyre oil field as defined under Conservation Order No. 317. Exxon is a working interest owner in the Pt. Mclntyre oil field and is an interested party in the scheduled hearing. Exxon hereby gives notice of its interest and reserves its right to participate in all aspeCts of this proceeding, including, but not limited to, any pre-hearings, conferences, meetings, the hearing and any post hearing conferences and meetings that might arise during this proceeding. It is requested that the Commission and any other interested party forward. copies of all documents, pleadings, motions, correspondence and etc. filed in this matter to Exxon through the undersigned. Exxon interprets the notice to mean that the September 9, 1993 hearing will be limited to the issues of waste, insuring a greater ultimate recovery of oil and gas and protection of correlative rights. The possibility of a forced unitization hearing on the Commission's own motion would come, if at all, only after these issues have been determined. In other words, the September 9, 1993 hearing will not be a forced unitization hearing. Please advise if our interpretation of the notice is incorrect. J~ ~ ~EIV ~ D A DIVISION OF EXXON CORPORATION A U G 1 1 199,~ Alaska 0il & "," Anchorage Mr. David W. Johns - 2- 8/10/93 Please feel free to contact me if you have any questions or if I can be of assistance. Very truly yours, Eaw Department Exxon Company, U.S.A. P. O. Box 2180 Houston, Texas 77252-2180 Telephone (713) 656-3431 Fax (713) 656-6123 Counsel for Exxon Corporation GEB:jpC/unit C: Mr. Harry Noah, Commissioner Department of Natural Resources 400 Willoughby Avenue Juneau, Alaska 99801-1724 Mr. James E. Eason, Director Department of Natural Resources Division of Oil and Gas P. O. Box 10734 Anchorage, Alaska 99510-7034 Mr. Mark P. Worcester, Senior Attorney ARCO Alaska, Inc. P. O. Box 100360 Anchorage, Alaska 99510-0360 Mr. John Reeder BP Exploration Alaska, Inc. 900 East Benson Boulevard Anchorage, Alaska 99508 RECEIVED Alaska 0il & Gas 00ns. 00[[l[~issiot'~ Anch0rag9 ALASKA OIL AND GAS CONSERVATION COMMISSION WALTER J. HICKEL, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 TELECOPY: (907) 276-7542 6ugust5,1993 Mr. Mark P. Worcester Senior Attorney ARCO Alaska, Inc. P.O. Box 100360 Anchorage, AK 99510-0360 Mr. Harry Noah Commissioner Department of Natural Resources 400 Willoughby Avenue Juneau, AK 99801-1724 Dear Mr. Worcester and Commissioner Noah: The Commission, upon its own motion in accordance with AS 31.05.060, has scheduled a public hearing extending an invitation to all concerned to show cause as to whether any action is necessary to prevent or to assist in preventing waste, to insure a greater ultimate recovery of oil and gas, or to protect correlative rights of persons owning interests in the Pt. Mclntyre oil field, as defined under Conservation Order No. 317. As a result of this hearing, the Commission may consider forced unitization of the Pt. Mclntyre and Stump Island reservoirs as authorized by AS 31.05.030 and 31.05.110. The Commission has scheduled the hearing for September 9, 1993, 9:00 a.m. at 3001 Porcupine Drive, Anchorage, Alaska 99501. Public notice for this hearing is attached.. Chairman Attachment cc: James Eason, Director, Division of Oil & Gas ~ printdd on recycled paper b y G~:i'J. ARCO AlasKa. Post Office Box 100360 Anchorage, Alaska 99510-0360 Telephone 907 263 4275 Anclrew D. Simon Manager Lisburne/Point Mclntyre April 30, 1993 HAND DELIVERED Dr. Glenn A. Olds Commissioner State of Alaska Department of Natural Resources Division of Oil and Gas P.O. Box 107034 Anchorage, Alaska 99510-7034 RE: Appeal from the April 14, 1993 Decision of Director of Division of Oil and Gas Regarding ARCO's Request for Deferral of Contraction of Prudhoe Bay Unit Tracts 5, 6, 7, and 8: ADLs 34626, 34627, 34624, and 28297 Dear Commissioner Olds: Attached is ARCO Alaska, Inc.'s ("ARCO") appeal to the above-referenced decision of the Director of the Division of Oil and Gas, which contracts four tracts out of the Prudhoe Bay Unit (the "Decision"). The Division had previously approved the deferral of the contraction of the Prudhoe Bay Unit as to these tracts until March 31, 1993. ARCO believes the Decision to contract the Prudhoe Bay Unit was made in error for the reasons listed in the appeal, and because each of the four tracts are included in proceedings pending before the Division: Tracts 6, 7, and 8 are included in ARCO's Application for Expansion of the Prudhoe Bay Unit and Formation of the Pt. McIntyre Participating Area; and Tract 5 is included in ARCO's Application for Formation of the West Beach Participating Area. (The Division recently approved ARCO ' s Application for Formation of the West Beach Participating Area as to all leases except Tract 5 -- ARCO is concurrently filing an appeal to the Commissioner to include Tract 5 in the West Be. ach Participating Area ) EXHIBIT B J U L. ARCO AIIIII, i. Inc. ;s · Sul~llamW ot Alllnttc Rlchflt~l COmlZlll¥ Alask;~ t,~tl & ~,:~;.,,$ Col"ts. Anchor'at~je Dr. Glenn A. Olds April 30, 1993 Page 2 ARCO hopes to resolve the issues raised in the attached appeal through informal discussions with the Director. However, ARCO is cognizant that certain regulations would prohibit the filing of an appeal regarding the Decision if more than 30 days pass after the date of delivery of the Decision to ARCO. For this reason, ARCO is filing the attached appeal to preserve its rights should informal discussions not result in a mutually favorable conclusion within the 30-day period. Finally, ARCO wishes to inform the Division that the construction and modification work necessary to start up the Pt. McIntyre field is progressing at a rate faster than expected. Accordingly, we are projecting a start-up date of July 1, 1993. Please call with any questions or concerns you may have. Sincerely, Andrew D. Simon ADS/RMJ EncloSure cc w/Encl.: Jim Eason, Director STATE OF ALASKA BEFORE THE DEPARTMENT OF NATURAL RESOURCES Appeal from Decision of Director of Division of Oil and Gas Regarding Contraction of Prudhoe Bay Unit Tracts 5, 6, 7, and 8; ADLs 34626, 34627, 34624, and 28297, dated April 14, 1993 ARCO Alaska, Inc., on behalf of the Prudhoe Bay Unit Working Interest Owners, and ARCO Alaska, Inc. ("ARCO") and Exxon Corporation ("Exxon"), in their separate capacities as leaseholders ("Leaseholders"), hereby appeal from the April 14, 1993 Decision of the Director of the Alaska Department of Natural Resources with respect to Contraction of Prudhoe Bay Unit Tracts 5, 6, 7, and 8; ADLs 34626, 34627, 34624, and 28297 (the "Decision"). A copy of the Decision is attached as Exhibit A to this appeal. This appeal is made pursuant to 11 AAC 88.155 and 11 AAC 02.010(c). Lease- holders intend to file additional written materials in support of this appeal pursuant to 11 AAC 02.030(b). I · SPECIFICATION OF DECISION BEING APPEALED 11 AAC 02.030(a) (5) Leaseholders are appealing the April 14, 1993 Decision of the Director of the Alaska Department of Natural Resources with respect to Contraction of Prudhoe Bay Unit Tracts 5, 6, 7, and 8; ADLs 34626, 34627, 34624, and 28297. Leaseholders appeal the Decision to the extent that it con- tracts the following lands from the Prudhoe Bay Unit ("PBU"): T12N, R15E, U.M., Secs. 21 and 22: Ail (ADL 34626 (Tract 5)); T12N, R15E, U.M., Sec. 19: N/2, Sec. 20: N/2 (ADL 34627 (Tract 6)); T12N, R14E, U.M., Sec. 23: Ail, Sec. 24: N/2 (ADL 34624 (Tract 7)); T12N, R14E, U.M., Sec. 22: Ail (ADL 28297 (Tract S)) . Leaseholders do not appeal the Decision to the extent that it approves the deferral of contraction of the following lands from the PBU: RE E VED Alaska Oil & Gas Oons. Anchorage T12N, R15E, U.M., Sec. 19: S/2, Sec. 20: S/2 (ADL 34627 (Tract 6) ); T12N, R14E, U.M., Sec. 24: S/2 (ADL 34624 (Tract 7)). II. SPECIFICATION OF REMEDY REQUESTED 11 AAC 02.030(a) (6) The DNR, by a Decision dated February 25, 1987 (the "1987 Decision") (attached as Exhibit B), has already approved the deferral of the contraction of the PBU as to Tracts 5, 6, 7, and 8 until April 1, 1992. The DNR further deferred contraction until March 31, 1993. (Decision, pg. 2.) By letter dated March 31, 1993 (copy attached as Exhibit C) , Leaseholders requested further deferral of Tracts 6, 7, and 8 until ARCO's application to expand the PBU and form the Pt. McIntyre Participating Area is finally determined by the state. In that letter, Leaseholders also requested further deferral of Tract 5 until April 1, 1994. A portion of Tract 5 is included in ARCO's Application for Formation of the West Beach Participating Area, which is currently on appeal before the Commissioner. Leaseholders request that the DNR defer contraction of the PBU as requested in the March 31, 1993 letter. III. SPECIFICATION OF GROUNDS ON WHICH APPEAL IS BASED 11 AAC 02.030(a) (61 It was error to contract Tracts 5, 6, 7, and 8 from the PBU for the following reasons: 1. Prudhoe Bay Unit Agreement paragraph 4.2 provides that lands which are covered by approved plans of development and operation cannot be contracted from the PBU so long as operations are being diligently conducted pursuant to those plans. Plans of development and operation with regard to Tracts 5, 6, 7, and 8 have been approved by the Director of the DNR, and operations have been diligently conducted pursuant to those plans. 2. Prudhoe Bay Unit Agreement paragraph 4.2 provides that lands shall not be excluded from the Unit Area while bona fide drilling operations are being conducted on such lands, with at least one well being commenced each calendar year and followed by -2- a good-faith attempt to complete such well during the winter drilling season. Leaseholders have conducted such bona fide drilling operations on the subject leases. 3. Prudhoe Bay Unit Agreement paragraph 9.3 provides that lands shall be contracted from the PBU if "not included or entitled to be included in a Participating Area." Tracts 5, 6, 7, and 8 are entitled to be included in a participating area for all of the reasons outlined in the Pt. McIntyre and West Beach applications, filed with the DNR, for formation of participating areas. 4. Prudhoe Bay Unit Agreement paragraph 9.1 provides for the enlargement of the PBU "so as to include any additional lands reasonably determined to be within any Reservoir any portion of which is within the Unit Area." ARCO has submitted an Application for Expansion of the Prudhoe Bay Unit and Formation of the Pt. McIntyre Participating Area, which encompasses portions of Tracts 6, 7 and 8, and has submitted an appeal of the DNR's decision regarding the Formation of the West Beach Participating Area, which encompasses portions of Tract 5. These applications provide the basis for which Tracts 5, 6, 7, and 8 are "reasonably determined to be within any Reservoir" which is within the PBU. Tracts 5, 6, 7, and 8 should not have been excluded because Leaseholders have the contractual right to expand the PBU to include these Tracts. 5. Although the Prudhoe Bay Unit Agreement controls over any contrary regulation on this point, contraction deferral satisfies the criteria set forth at 11 AAC 83.303. The contraction will not promote the prevention of economic and physical waste and will not provide for the protection of all parties of interest, including the state. 6. Although the Prudhoe Bay Unit Agreement controls over any contrary regulation on this point, 11 AAC 83.356(b) provides that the Commissioner can delay contraction of a unit area if the circumstances of a particular unit warrant. The circumstances of the PBU warrant deferral of unit contraction in the present case. These circumstances include the Leaseholders' compliance with the terms of the 1987 Decision, the pending Unit Area and Participating Area expansion applications, and the other reasons for deferral set forth in this appeal. 7. Although the Prudhoe Bay Unit Agreement controls over any contrary regulation on this point, 11 AAC 83.356(a) provides that a unit "must encompass the minimum area required to include all or part of one or more oil or gas reservoirs, or all or part of one or more potential hydrocarbon accumulations." The relevant portions of Tracts 5, 6, 7, and 8 contain proven or potential hydrocarbon accumulations. -3- 8. Although the Prudhoe Bay Unit Agreement controls over any contrary regulation on this point, 11 AAC 83.356(e) provides that the Commissioner will, in his discretion, contract the unit area to include only that area underlain by one or more oil or gas reservoirs or one or more potential hydrocarbon accumulations and lands that facilitate production. The relevant portions of Tracts 5, 6, 7, and 8 contain proven or potential hydrocarbon accumulations. 9. Prudhoe Bay Unit Agreement paragraph 4.2 requires the Director to give notice to the affected Working Interest Owners before excluding lands from the Unit Area for failing to file or follow an approved plan of development. Although the Prudhoe Bay Unit Agreement controls over any contrary regulation on this point, 11 AAC 83.356(e) provides that the Commissioner will give the unit operator and working interest owners of the leases or portions of leases being contracted from a unit reasonable notice and an opportunity to be heard. On April 15, 1993, ARCO received the Decision, which notified ARCO that the Tracts would be contracted from the PBU; the Decision stated that the contraction was effective on April 1, 1993. (Decision, pg. 3.) Thus, Leaseholders were not given prior notice of the exclusion of the subject leases and Leaseholders had no opportunity to be heard. 10. Although the Prudhoe Bay Unit Agreement controls over any contrary regulation on this point, the regulations in effect on the effective date of the Prudhoe Bay Unit Agreement support contraction deferral. 11. Leaseholders complied with and relied upon the terms of the Decision of the Commission dated February 25, 1987 (attached as Exhibit B). 12. The Decision states that the Department has delayed the contraction of Tracts 5, 6, 7, and 8 until March 31, 1993. (Decision, pg. 2.) The circumstances of the Prudhoe Bay Unit that justified contraction deferral until March 31, 1993 have not changed. 13. The Decision states that further deferral of the con- traction of the Tracts is not warranted, because past deferrals "gave the Leaseholders ample time to determine whether the leases were capable of commercial production, and, if so, to request that they be included within an appropriately defined participating area." (Decision, pg. 2.) Leaseholders have requested that Tracts 5, 6, 7, and 8 be included within appropriately defined participat- ing areas, and Leaseholders have determined that the leases are capable of commercial production. Further, on January 24, 1992, February 28, 1992, and on many occasions thereafter, Leaseholders notified the DNR that they would apply to the DNR for formation of -4- the Pt. McIntyre Participating Area and expansion of the Prudhoe Bay Unit no later than May of 1993. 14. Sustained production from the Pt. McIntyre Participating Area is scheduled to commence approximately July 1, 1993. Contrac- tion will almost certainly delay start-up of sustained production, which is not in the best interests of either the state or the Leaseholders. 15. The Decision does not set forth the DNR's analysis in detail. For example, the DNR merely states that the continued delay in contraction of the Tracts is not warranted given the "particular circumstances of these tracts" and the "criteria of 11 AAC 83.303." The DNR does not state what the "particular circumstances of these tracts" are, nor does it list the criteria of 11 AAC 83.303 and state how the criteria are not met. Lease- holders have requested access to relevant documents that might shed light on the basis for the Decision. The request for additional documentation is attached as Exhibit D. Therefore, Leaseholders reserve the right to present additional grounds for relief when the underlying reasons for the Decision become known to Leaseholders. IV. STATEMENT OF ADDRESS FOR NOTICES OR DECISIONS 11 AAC 02.030(a) (7) Rosanne M. Jacobsen ARCO Alaska, Inc. ATO 2088 P.O. Box 100360 Anchorage AK 99510-0360 (907) 265-6549 (907) 265-6998 (fax) Gary E. Baker Law Department Exxon Company, U.S.A. P.O. Box 2180 Houston, TX 77252-2180 (713) 656-3431 (713) 656-6123 (fax) Ve IDENTIFICATION OF AFFECTED LEASES AND LANDS 11 AAC 02.030(a)(8) This appeal to delay contraction of PBU Tracts 5, 6, 7, and 8 affects the following leases and lands: T12N, R15E, U.M., Secs. 21 and 22: All (ADL 34626 (Tract 5)); T12N, R15E, U.M., Sec. 19: N/2, Sec. 20: N/2 (ADL 34627 (Tract 6)); -5- T12N, R14E, U.M., Sec. 23: Ail, Sec. 2.4: N/2 (ADL 34624 (Tract 7)).; T12N, R14E, U.M., Sec. 22: Ail (ADL 28297 (Tract 8)) . VI. REQUEST FOR HEARING 11 AAC 02.030¢a) (9) Leaseholders request a hearing to make presentations concern- ing the legal and factual issues involved in the appeal. The issues that need to be decided are 1) whether the contraction of Tracts 6, 7, and 8 should continue to be deferred until ARCO's application to expand the PBU and form the Pt. McIntyre Participating Area within the PBU is finally determined by the state; and 2) whether the contraction of Tract 5 should continue to be deferred until April 1, 1994. These are mixed issues of law and fact. Moreover, each of the grounds specified in Section III involves issues of law and fact. In accordance with 11 AAC 02.050(b), Leaseholders request that the hearing process include such normal due process procedures as the right to present oral testimony, cross-examine witnesses, and file post-hearing briefs. VII. NOTICE OF INTENT TO FILE ADDITIONAL MATERIALS 11 AAC 02.030¢b) Leaseholders intend to file a brief and/or additional written materials, which may include exhibits, in support of this appeal. Leaseholders filed a public records request, attached as Exhibit D, to request access to the Division's records on these matters. Leaseholders reserve the right to supplement their factual and legal claims in this appeal after all relevant records -6- have been made available. The Commissioner is also requested to include these relevant records in the record. DATED this ~ day of April, 1993 at Anchorage, Alaska. ARCO Alaska, Inc. Andrew D. Simon Manager, Lisburne and Pt. McIntyre Exxon Corporation By: Joel W. Kiker Production Manager, Alaska Interest Organization Exxon Company, U.S.A., a Division of Exxon Corporation -7- DEPT. OF NATURAL RESOURCES DIVISION OF OIL AND GAS WALTER J. HICKEL, GOVERNOR RO. BOX 107034 ANCHORAGE, ALASKA 99510-7034 PHONE: (907) 762-2553 (907) 762-2547 April 14, 1993 ARCO Alaska, Inc. P.O.Box 100360 Anchorage, Alaska 99510-0360 Atto: Peter L. Goebel Landman Subject: Request for Deferral of Contraction of Prudhoe Bay Unit Tracts 5, 6, 7, and 8; ADLs 34626, 34627, 34624, and 28297 Dear Mr. Goebel: On March 31, 1993, ARCO Alaska, Inc. and Exxon Corporation (collectively "Leaseholders") requested that the Division of Oil and Gas (Division) further delay contraction of certain tracts in the Pmdhoc Bay Unit (PBU). Specifically, they asked that: (1) contracfio, n of Tracts 6, 7, and 8; (ADLs 34627, 34624 and 28297) be delayed until the state issues its determination regarding the application to expand the PBU and form the Pt. Mclntyre Participating Area within the PBU; and that contraction of Tract 5 (ADL 34626) be delayed until April 1, 1994. Under thc terms of the PBU Agreement, these tracts were scheduled to be contracted out of the PBU on April 1, 1987 because they were not committed to an approved participating area by that date. 11 AAC 83.356(b) gives the commissioner discretion to delay the contraction of an unit area if the circumstances of that particular unit warrant such a delay. The primary purpose of the contraction delay was to give the Leaseholders a reasonable amount of time to determine the commerciality of these tracts and to determine whether they should be included within a participating area. RE~' [IV~D J U .... 7 !,993 Alaska Oil A Gas Cons. uor,¢missior~ EXHIBIT A Anch0ra~e Peter L. Goebel April 14, 1993 Page 2 The scheduled contraction of these tracts has previously been delayed twice. A five year delay was approved conditionally from April 1, 1987 to April 1, 1992. The 1987 decision specifically stated that "[s]hould these leases not be included within an approved participating area on April 1, 1992,... [they] will be contracted out of the Prudhoe Bay' Unit as of that date." However, a further delay was approved from April 1, 1992 to March 31, 1993. Thus, contraction has already been delayed for six years. These delays gave the Leaseholders ample time to determine whether the leases were capable of commercial production, and, if so, to request that they be included within an appropriately defined participating area. Over seven months ago, the Division notified Arco that the state would be unwilling to delay a final decision regarding the contraction of the four tracts beyond the first quarter of 1993. The Division has reviewed the reasons set forth in your March 31st request to further delay contraction, as well as the previous correspondence and history regarding the delays of contraction for the four tracts. As of this date, I need not decide whether a further delay in contraction of the following lands: T12N, R15E, U.M., Sec. 19: S/2, Sec. 20:S/2 (ADL 34627 (Tract 6)); T12N, R14E, U.M., Sec 24:S/2 (ADL 34624 (Tract 7)); is necessary. These lands have been included in the recently approved West Beach Participating Area and thereby continue to be pan of the PBU. But, Tract 5, certain pans of Tract 6 and 7, and Tract 8 are still not within an approved participating area. Considering the particular circumstances of these tracts, as well as the criteria of 11 AAC 83.303, the continued delay in contraction of the following lands from the PBU is not warranted: T12N, R15E, U.M., Secs. 21 and 22: All (ADL 34626 (Tract 5)); T12N, R15E, U.M., Sec. 19: N/2, Sec. 20:N/2 (ADL 34627 (Tract 6)); T12N, R14E, U.M., Sec 23: All, Sec. 24:N/2 (ADL 34624 (Tract 7)); Peter L. Goebel April 14, 1993 Page 3 T12N, R14E, U.M., Sec 22: All (ADL 28297 (Tract 8)). These lands are eliminated from the PBU effective as of April 1, 1993. The leases or portions of leases eliminated from the PBU as of April 1, 1993 will not automatically terminate with the contraction. Under the terms and conditions of the respective leases, each lease is extended by the presence of a well certified as capable of production in paying quantities. The Leaseholders have requested that portions of the eliminated acreage be included within the proposed Point Mclntyre Participating Area. The Leaseholders should amend their application to extend the PBU and form the Point Mclntyre Participating Area within the PBU to include consideration of this contracted acreage as part of the proposed expansion if they still desire the contracted lands to be within the PBU. The Division will consider the criteria governing expansions as it pertains to all of the prOposed acreage in the complete application to expand the PBU boundary and form the Pt. Mclntyre Participating Area in determining whether such actions are in the state's best interest. Finally, revised Exhibits "A" and "B" are required to reflect the new unit boundary. Within sixty days of receipt of this letter, please submit the revised exhibits to the Pmdhoe Bay Unit Agreement. Sincerely, es . Eason cc: Glenn A. Olds - Commissioner, ADNR Raga Elim - ADNR Patrick Coughlin - ADOL David Johnston - AOGCC James D. Weeks -ARCO Carol Wilkinson PBU.I:rrMCDEF4.Txt State of Alaska Before the Department of Natural Resources APPEAL TO THE COMMISSIONER from Director's April 14, 1993 Decision ,ARCO and Exxon's Brief J lJ L 2 7 199~ Alaska Oil & Gas Cons. Oommissior~ Anchorage TABLE OF CONTENTS I. II. III. INTRODUCTION STATEMENT OF FACTS LEGAL ARGUMENTS A. Contraction deferral satisfies the criteria set forth at 11 AAC 83.303 and is warranted by the circumstances of the Prudhoe Bay unit B. Only lands which are "not included or entitled to be included in a Participating Area" can be lawfully contracted C. Lands covered by an approved plan of development cannot be contracted from the Prudhoe Bay Unit so long as operations are being diligently conducted pursuant to those plans D. The Prudhoe Bay Unit cannot be contracted if bona fide drilling operations are being diligently conducted on any lands not then included in a Participating Area E. Tracts 5, 6, 7, and 8 should not have been contracted because Leaseholders have the contractual right to expand the Prudhoe Bay Unit to include these Tracts F The unit should note contracted to exclude land covered by an approved plan or exploration or development The Prudhoe Bay Unit must encompass the Pt. McIntyre, West Beach, North Prudhoe Bay, and Gull Island reservoirs The unit should not be contracted to exclude land underlain by proven or potential hydrocarbon reservoirs Leaseholders complied with and relied upon the terms of the decision of the Commissioner dated February 25, 1987 The Prudhoe Bay Unit cannot be contracted absent reasonable notice and an opportunity to be heard G HI Ie J. IV. REQUEST FOR HEARING V. RE~DY REQUESTED VI. CONCLUSION APPENDIX A APPENDIX B 12 14 15 16 16 17 17 18 20 20 21 21 LIST OF AT'FACHMENTS I. INTRODUCTION On July 1, 1993, the Pt. Mclntyre reservoir will be physically ready to commence production of between 50,000 to 75.000 barrels of oil per day. This accomplishment is the result of years of preparation and the expenditure of hundreds of millions of dollars. In anticipation of a summer 1993 start-up, the Pt. Mclntyre working interest owners (the "Pt. Mclntyre Owners") have spent the past several years negotiating facility sharing agreements among themselves and the Prudhoe Bay and Lisburne owners. Additionally, over the past years, the Pt. Mclntyre Owners have worked closely with the state agencies in order to secure timely approval of a summer 1993 start-up. All this work was based upon the premise that the Pt. Mclnt~e reservoir would be a part of the Prudhoe Bay Unit. Throughout this process, ARCO Alaska, Inc. ("ARCO") and Exxon Corporation ("Exxon") (hereinafter "Leaseholders") advised the Department of Natural Resources ("Department") of their intent to expand the Prudhoe Bay Unit and form the Pt. Mclntyr¢ Participating Area within the Prudhoe Bay Unit. On March 18, 1993, the Pt. Mclntyre Owners filed an application to expand the Prudhoe Bay Unit and form the Pt. Mclntyre Participating Area. Attachment A. On March 31, 1993, Leaseholders requested that the Department defer contraction of the Prudhoe Bay Unit as to Tracts 6, 7 and 8, which overlie the Pt. Mclntyr¢ reservoir. Attachment B. Leaseholders requested that contraction be deferred until the Department finally decided the pending application to form the Pt. Mclntyre Participating Area in the Pi'udhoe Bay Unit. Leaseholders also requested that contraction of Tract 5 be deferred until April 1, 1994. On April 14, 1993, the Director of the Division of Oil and Gas denied Leaseholders' request for contraction deferral. Attachment C. Instead, the Director declared that the leases contracted out of the Prudhoe Bay Unit retroactively to April 1, 1993. It is from this decision that Leaseholders are appealing, t Attachment D. 1Leaseholders note that the Director's April 14. 1993 decision is stayed due to Leaseholders' timely appeal. 11 AAC O2.O60. Although Pt. Mclnt.vre will be physically ready to commence production on July 1, 1993, start-up will be indefinitelv delayed if the Owners are required to begin the facility sharing and agency approval process over again. However, this is what will happen if Pt. Mclnt.vre cannot be produced as part of the Prudhoe Bay Unit. It is arbitrary and grossly unfair to contract the subject tracts and, at the last minute, require the Owners to pursue a different and lengthy procedural path to bring production on line. It is not in the best interests of the State for the Department to delay the start-up of Pt. Mclnt.vre production. For the reasons set forth below, the Department should delay contraction of the subject tracts until it has finally decided the pending application for expansion of the Prudhoe Bay Unit and formation of the Pt. Mclntyre Participating Area. II. STATEMENT OF FACTS On April 1, 1977, ADLs 34626 ("Tract 5"), 34627 (Tract 6"), 34624 (Tract 7"), and 28297 ("Tract 8") (hereinafter "Subject Tracts") were committed to the Prudhoe Bay Unit. Attachment E. The Pt. Mclntyre reservoir is one of four reservoirs underlying portions of the Subject Tracts.2 ARCO and Exxon each hold a 50 percent interest in each of the Subject Tracts. Article 9.3 of the Prudhoe Bay Unit Agreement ("PBUA") provides that any lands not included in a Participating Area on the Unit's tenth anniversary (i.e., April 1, 1987) shall !~ excluded from the Unit Area. Attachment F. Although five exploratory wells had been drilled in the regi0n3 (Attachment G), the Subject Tracts were not included in a participating area by 1986 because Leaseholders and the Prudhoe Bay Unit owners had concentrated their efforts on efficient production of the Prudhoe Bay and Lisburne reservoirs. Consequently, in October of 1986, Leaseholders requested that the Department defer contraction of the Subject Tracts in accordance with 11 AAC 83.356(b). (Attachment H contains relevant correspondence.) The 2Appendix A sets forth a narrative description of the reservoirs underlying the Subject Tracts. 3The wells are the North Prudhoe Bay No. 1 and 2, Gull Island No. 1, Abel State No. 1, and West Beach No. 3B. Appendix B describes the Exploration and Development drilling activities conducted on the Subject Tracts. purpose of this deferral was to allow Leaseholders to further test and evaluate the Subject Tracts so that the commerciality of the underlying reservoirs could be confirmed. Because these reservoirs are remote, relatively small, and geologically complex, some of these reservoirs would be uneconomic if developed with stand-alone facilities. Substantial sharing of facilities is required for commercial development. By decision dated February 25, 1987, as amended (the "1987 Decision"), the Department deferred contraction of the Subject Tracts until April 1, 1992.4 Attachment I. By 1991, Leaseholders determined that the reservoirs could be commercially developed. The Pt. Mclntyre Owners first notified the State by letter dated November 13, 1991 that they intended to apply for the formation of the Pt. Mclntyre Participating Area within the Prudhoe Bay Unit. Attachment H. The Owners also met with the Department in January of 1992 to discuss their plans to develop Pt. Mclntyre and to apply for formation of the Pt. Mclntyre Participating Area within the Pmdhoe B ay Unit by May of 1993 when the drilling and evaluation of equity wells would be complete.5 As stated above, the 1987 Decision deferred contraction of the Subject Tracts until April 1, 1992. On February 28, 1992, Leaseholders requested that contraction of the Prudhoe Bay Unit be deferred until September 1, 1993 with respect to Tracts 6, 7, and 8, to allow the Pt. Mclntyre Owners enough time to petition the State for formation of the Pt. Mclntyre Participating Area and expansion of the Prudhoe Bay Unit. Leaseholders also requested that contraction of the Prudhoe Bay Unit be deferred until April 1, 1994 with respect to Tract 5. 4The deferral was granted on the condition that Leaseholders satisfy two conditions: (A) Leaseholders must drill a well prior to April 1, 1992 which would delineate reserves on Tracts 7 and 8; and (B) Leaseholders must commit prior to April 1, 1992 to drill a well which would delineate reserves on Tracts 5 and 6. Leaseholders satisfied both of these conditions prior to April 1, 1992. Condition (A) was met when the Pt. Mclntyre No. 3 was completed on Tract 8 in April of 1988. In addition, three other wells were drilled and completed on Tracts 7 and 8 prior to April 1, 1992. Condition (B) was met when Leaseholders committed, in their letter to the Department dated February 28, 1992, to drill Pt. Mclntyre Well F-2 to a bottomhole location in Tract 6 in the second quarter of 1992. The F-2 was spudded in May of 1992. 5In February of 1992, the Owners submitted a plan of development covering Tracts 6, 7, and 8 (which detailed the operations which were planned to facilitate production of the Pt. Mclntyre reservoir as part of the Prudhoe Bay Unit), and a plan of exploration covering Tract 5. Attachment H. The Owners met again with the Department on December 3, 1992 and March 16, 1993 to discuss their plans to apply for the formation of the Pt. Mclntyre Participating Area and the expansion of the Prudhoe Bay Unit. In a series of letters during the summer of 1992, the Department stated that it would delay its decision on Leaseholders' request for contraction deferral. Attachment H. By letter dated September 3, 1992, the Director of the Division of Oil and Gas stated that he was "unwilling to delay a decision regarding the original deferral of contraction beyond the first quarter of 1993." By the end of the first quarter of 1993 (i.e., March 31, 1993), the Department had still not rendered a decision on Leaseholders' February 28, 1992 request for deferral of contraction until September 1, 1993. In the meantime, Leaseholders had applied for two participating areas: the Pt. McIntyre Participating Area (Tracts 6, 7, and 8) and the West Beach Participating Area (Tracts 5, 6, and 7), which were applied for on March 18, 1993 and November 20, 1992, respectively.6 Attachments A and J. The application for the formation of the Pt. McIntyre Participating Area and the expansion of the Prudhoe Bay Unit is complete and notice of the application has been published. Attachment K. The request for the formation of the West Beach Participating Area was approved by the Department on April 2, 1993 with respect to all tracts except Tract 5.7 Attachment L. Because the Department had not ruled on Leaseholders' February 28, 1992 request for contraction deferral, on March 31, 1993, Leaseholders renewed their request for contraction deferral. Attachment H. Leaseholders requested that the Department defer contraction of the Prudhoe Bay Unit as to Tracts 6, 7, and 8 until the pending application to expand the Prudhoe Bay Unit and form the Pt. McIntyre Participating Area within the Pmdhoe Bay Unit was finally decided by the Department. Leaseholders requested that contraction be deferred as to Tract 5 until April 1, 1994. 6Note that ARCO and Exxon (the "West Beach Owners") applied for formation of the West Beach Participating Area, and ARCO, Exxon and BP Exploration (Alaska), Inc. ("BP") (the "Pt. McIntyre Owners") applied for formation of the Pt. McIntyre Participating Area and expansion of the Prudhoe Bay Unit. Although BP does not hold an interest in the Subject Tracts, BP and Leaseholders, as owners of the Pt. McIntyre reservoir, have jointly entered into agreements, invested in drilling and facility modifications, and sought required agency approvals to prepare the Pt. McIntyre field for production. 7Leaseholders are currently appealing the Department's decision to exclude Tract 5 and understand that the Department has a~eed to include the relevant portion of Tract 5 in the West Beach Participating Area. By decision dated April 14, 1993, the Department responded to Leaseholders' request for contraction deferral. Attachment C. Despite Leaseholders' intensive good faith activities in compliance with the 1987 Decision and in accordance with approved plans of development and operation, the Department summarily contracted the Subject Tracts8 from the Prudhoe Bay Unit effective April 1, 1993, stating, "Leaseholders [had] ample time to determine whether the leases were capable of commercial production, and, if so, to request that they be included within an appropriately defined participating area." The Department did not explain this statement, which is erroneous because Leaseholders did apply for formation of the West Beach Participating Area and Pt. Mclntyre Participating Area on November 20, 1992 and March 18, 1993, respectively. Further, the Department did not notify Leaseholders of the contraction until two weeks i~fter the effective date -- an ex post facto deadline. Finally, the Department completely failed to discuss its analysis of the appropriate regulatory criteria which ostensibly support the Decision. To date, Leaseholders, together with BP, have invested more than $287,000,0009 in drilling and facilities to prepare the Pt. Mclntyre and West Beach reservoirs for production. Total development expenditures are expected to exceed $700,000,000. Prudhoe Bay Unit facilities, such as the Lisburne Production Center, are being modified to handle the increased 8Those portions of the Subject Tracts which encompass the West Beach Participating Area were not contracted. The portions of the Subject Tracts which were contracted and which are being appealed are identified in Part V of Leaseholders' April 29, 1993 Appeal from Decision of Director of Division of Oil and Gas Regarding Contraction of ?rudhoe Bay Unit Tracts 5, 6, 7 and 8. Attachment D. 9The $287,000,000 figure includes: *$110,000,000 to drill, complete and test the Pt. Mclntyre wells; *$90,000,000 to expand the Pt. Mclntyre #1 drill pad to enable the drilling of development wells and location of production equipment; *$50,000,000 to construct the Pt. Mclntyre #2 drill pad to enable the drilling of development wells and location of production equipment; *$31,000,000 to modify the Lisburne Production Center ("LPC") to enable it to process the increased production from the Pt. Mclntyre and West Beach fields. (The planning and design of the LPG modifications began in 1989; actual modification of the LPC will begin in June of 1993. Additional expenditures of $38,000,000 are budgeted to complete the modification.); and *$7,000,000 to acquire and process a 3-D seismic program. production, and pipelines and other facilities are being constructed to enable Pt. Mclntyr¢ production to utilize Prudhoe Bay Unit facilities. Twenty-eight wells have been drilled in the West Beach/Pt. McIntyre area since 1988; twelve of these wells were drilled on the Subject Tracts. Attachments E and G. Well No. P1-13 is currently being drilled on Tract $. Sixty to seventy additional development wells are planned to be drilled over the next three years. The Pt. McIntyre, West Beach, and North Prudho¢ Bay Owners have also negotiated various agreements necessary for field production among themselves and the Prudho~ Bay and Lisburne Owners. Examples of these agreements, some of which required three years to negotiate, include agreements to determine equity, operating agreements, various infrastructure sharing agreements, gas management, and source water agreements, among others. These agreements are premised on the inclusion of the Pt. McIntyre Participating Area within the Prudhoe Bay Unit. Finally, the agency approvals required for start-up, with the exception of the application for formation of the Pt. McIntyre Participating Area and expansion of the Prudho~ Bay Unit, have either been granted or are imminent,l0 These agency approvals, if not expressly conditioned upon the inclusion of the Pt. McIntyre Participating Area within the Prudho~ Bay Unit, were granted with the expectation that the Pt. McIntyre Participating Area would Ix: included within the Prudhoe Bay Unit. Preparation on all of these fronts has progressed to the point that the Pt. McIntyre reservoir will be capable of production in July of 1993. In sum, the Department arbitrarily contracted the Prudhoe Bay Unit at the same time the Leascholders were prudently proceeding to start up the Pt. McIntym and West Beach reservoirs and were testing the Sadlerochit reservoir in North Prudhoe Bay No. 3. The lengthy delay in start-up of Pt. McIntyre production which will almost certainly result from the contraction of the 10The Alaska Oil and Gas Conservation Commission issued Field Rules for West Beach on February 25, 1993 (Attachment M), and Field Rules for Pt. Mclntyre are expected to issue in mid June, 1993. The Department of Revenue has approved the production ~location methodology present in the Pt. Mclntyre Field Rules. Attachment N. The Owners first approached these agencies in 1990 to obtain approval of the production allocation methodology. Prudhoe Bay Unit would not benefit the state or Leaseholders. For the reasons shown below, the decision to contract the Subject Tracts from the Prudhoe Bay Unit was error. IH. LEGAL ARGUMENTS A. Contraction defcrr~l satisfies the criteria set forth at 11 AA(~ 83.303 and is warranted by the circumstances of th~ Pr~clhoe Bay Unit. On March 31, 1993, Leaseholders requested that the Division of Oil and Gas defer contraction of the Subject Tracts pursuant to 11 AAC 83.356(b). Attachment B. Leaseholders requested that with respect to Tracts 6, 7, and 8, contraction be deferred until the pending application to expand the Prudhoe Bay Unit and form the Pt. Mclntyre Participating Area is finally determined. Leaseholders also requested that contraction of Tract 5 be deferred until April 1, 1994. On April 14, 1993, the Director of the Division of Oil and Gas denied the contraction deferral request, stating that the Subject Tracts were eliminated from the Prudhoe Bay Unit effective April 1, 1993. Attachment C. The April 14, 1993 decision states: "Leaseholders [had] ample time to determine whether the leases were capable of commercial production, and, if so, to request that they be included within an appropriately defined participating area." The Director did not explain this statement, which is erroneous because Leaseholders did apply for formation of the West Beach Participating Area and the Pt. Mclntyre Participating Area on November 20, 1992 and March 18, 1993, respectively. Attachments A and J. An analysis of 11 AAC 83.356(b) 11 and the criteria set forth at 11 AAC 83.30312 shows that it was error for the Division to deny deferral of unit contraction before such time as it could 1111 AAC 83.356(b) states: The commissioner will, in the commissionerts discretion, after considering the provisions of 11 AAC 83.303, delay contraction of the unit area if the circumstances of a particular unit warrant. 1211 AAC 83.303 sets forth the following criteria: (a)(1) promote conservation of all natural resources, including all or part of an oil or gas pool, field, or like area; (2) promote the prevention of economic and physical waste; and render a final decision on the pending application to expand the Prudhoe Bay Unit and form the Pt. McInt~e Participating Area. In its 1987 Decision, the Department approved the deferral of the contraction of the Subject Tracts through April 1, 1992. Attachment I. (As discussed above, the deferral was contingent upon the fulfillment of two conditions; both conditions were fulfilled.) In approving the deferral, the Department discussed each of the 11 AAC 83.303 criteria and considerations in detail and found each was met. That discussion, which is incorporated by reference, included the following findings by the Department: "Unitize0 development and operation of lands containing a reservoir or potential hydrocarbon accumulation has long been recognized as a valuable conservation mechanism. , , and the -- ultimate production of hyclrocarbons is maximized." "[U]nitization enhances the management of potential impacts to fish and wildlife, mitigates possible damage to surface acreage, and minimizes the negative impacts on other resources." "Unitization acts to ensure the r~revention of economic and physical waste by providing for an eq;aitable cost sharing formula and a well reasoned exploration and development plan for the areas of interest." "RetCntign of the lands in ouestion within the Prudhoe Bay Unit will prevent economic and r~hvsical waste by eliminating redundant expenditures for a gi:veh level of exploration and production, and avoiding loss of ultimate recovery through the adoption of a unified reservoir management strategy and utilization (3) provide for the protection of all parties of interest, including the state. (b) in evaluating the above criteria, the commissioner will consider (1) the environmental costs and benefits of unitized exploration or development; (2) the geological and engineering characteristics of the potential hydrocarbon accumulation or reservoir proposed for unitization; (3) prior exploration activities in the proposed unit area; (4) the applicant's plan for exploration or development of the unit area; (5) the economic costs and benefits to the state; and (6) any other relevant factors, including measures to mitigate impacts identified above, the commissioner determines necessary or advisable to protect the public interest. of existing unit facilities and infrastructure in exploration and development of the lands in question." "By the retention of the lands in question within the Prudhoe Bay Unit, all parties are assured ~ f~ir allo¢lttion Of production and ¢o~t~ consistent with the value of their leases, and the state is a~;vr¢cl adequate protection of all economic, e..nvironmental, archaeological, public ~afety, and other considerations constituting the public interest." "Develot)ment of the lands in questiQn wguld be exoedited and encouraged by retention of the lands in question within the Prudhoe Bay Unit, thereby permitting the shared use of the Prudhoe Bay facilities." "Retention of thc lancls in question within thc PrlJOhQC Bay Unit maximizes the economic value of the lands to the state, as the likelihood of the early development of the hydrocarbon accumulations underlying the leases is increased, the physical recovery of any hydrocarbons is maximized, and the expenditure of redundant capital outlays is eliminated. As a result, the state's long-term royalty and tax revenues will be augmented .... " "Because of the unique geologic and engineering characteristics of the postulated hydrocarbon accumulations, it is likely that retention of the lands within the Prudhoe Bay Unit will facilitate and expedite their early development. Expedited production will be in the state's economic interest, due to the time value of the revenues received." (emphasis added) These f'mdings were accurate in 1987; they are accurate today. The Department submitted no new facts or changed circumstances that would overcome and reverse these findings. The Department merely stated "[c]onsidering the particular circumstances of these tracts, as well as the criteria of 11 AAC 83.303, the continued delay in contraction.., is not wan'anted." Attachment C. The Department did not state what the "particular circumstances of these tracts" are, nor did it list the criteria of 11 AAC 83.303 and state how the criteria, which were met on the preceding day, were not met on April 1.13 13On April 1, 1980, ARCO, Exxon and the other North Slope producers entered into an agreement with the State of Alaska settling some of the "upstream" royalty issues C1980 Settlement Agreement") in the so-called Amerada Hess litigation (Civil Action No. 77-847, First Judicial District at Juneau). The 1980 Settlement Agreement provides, among other things, that a Field Cost Allowance may be deducted from the value of the Pmdhoe Bay Unit royalty in value oil and that the State shall be liable for a Field Cost Allowance with respect to Prudhoe Bay Unit royalty in kind oil. The 1980 Settlement applies to all lands to which the Prudhoe Bay Unit previously became effective and to "all other land to which the Unit Agreement may hereafter be extended." 1980 Settlement Agreement Para. 1.13. See Attachment O. Thus, the 1980 Settlement Agreement is applicable to all lands encompassed by future Prudhoe Bay Unit expansions, including the pending expansion application covering the Pt. Mclntyre reservoir. The decision states: "These delays gave Leaseholders ample time to determine whether the leases were capable of commercial production, and, if so, to request that they be included in an appropriately defined participating area." Attachment C. This statement implies that Leaseholders did not submit applications for participating areas regarding the Subject Tracts. To the contrary, by April 14, 1993, the Department had approved the West Beach Participating Area (as to Tracts 6 and 7) (Attachment L), and the Pt. Mclntyre Owners had formally applied for the formation of the Pt. Mclntyre Participating Area and the expansion of the Prudhoe Bay Unit. Attachment A. The circumstances which fulfilled the 11 AAC 83.303 criteria have become more compelling, not less compelling, since February 25, 1987. Since 1987, Leaseholders have proceeded expeditiously and prudently to discover and develop the hydrocarbon reserves underlying the Subject Tracts. Leaseholders, relying upon the 1987 Decision, have prepared the necessary inter-company agreements, have drilled wells and modified and installed facilities at a cost of more than $287,000,000 to date, and have secured all necessary agency approvals to begin start-up [with the exception of AOGCC's Pt. Mclntyre field rules (expected in mid June of 1993) and the Department's approval of the Pt. Mclntyre Participating Area and Prudhoe Bay Unit expansion (pending)]. Thus, all preparations for July 1993 production are nearly,complete, and all agency approvals are either granted or imminent, with the exception of the Department. Implicit in the preparations and agency negotiations were the purposes set forth in the 1987 Decision; namely, to expedite development and maximize recovery of the Pt. Mclntyre and West Beach fields, to eliminate the expenditure of redundant capital outlays, to minimize the impact on the It would be improper for the State to exclude Pt. Mclntyre from the Prudhoe Bay Unit for the purpose of avoiding the effects of the 1980 Settlement Agreement. Exclusion of Pt. McIntyre would indefinitely delay the anticipated July 1, 1993 start-up of Pt. Mclntyre. It is not in the State's best interest to impose such a delay simply for the opportunity to re-litigate the issue, on which a judgment has already been rendered, of whether the Pt. Mclntyre leases require the deduction of a Field Cost Allowance. Moreover, since Pt. Mclntyre field costs are higher than Prudhoe Bay Initial P,'u'ticipating Area costs, Leaseholders believe that such litigation would result in a higher field cost allowance for the Pt. McIntyre leases. 10 environment, fish and wildlife, to mitigate possible damage to surface acreage, and to prevent economic and physical waste. Inclusion of the Subject Tracts in the Prudhoe Bay Unit is vital to the production of the Pt. McIntyre reservoir. It is clear that the administrative hurdles to producing Pt. McIntyre outside the umbrella of the Prudhoe Bay Unit are significant and costly, and would result in lengthy delay in Pt. McIntyre start-up. For example, if the Pt. McIntyre reservoir were to be excluded from the Prudhoe Bay Unit, the Pt. McIntyre Owners either must produce the reservoir as lease operations or must apply to the Department to form a new unit. For either to occur, the Pt McIntyre, Lisburne, and Prudhoe Bay Owners must negotiate and execute new agreements regarding the sharing of facilities, infrastructure, power, water, and gas management, among other things. The agreements covering these subjects have taken up to three years to negotiate; the agreements which would be required among these parties if the Pt. McIntyre reservoir were not included in the Prudhoe Bay Unit would be more complicated and could possibly require at least as much time to negotiate and execute. Furthermore, royalty implications, tax partnership, quality bank, common carrier and revenue sharing concerns, and TAPS nomination and allocation procedures 14 must be identified and satisfactorily addressed, and the necessary agreements must 14For example, if production from all of Pt. Mclmyre is r~ot nominated to TAPS as l~art of the Pmdhoe Bay Unit, the TAPS nomination and allocation procedures will cause a perpetual imbalance between the producers and the State's Royalty In Kind purchasers. The imbalance will result from the fact that nominations to TAPS are based upon estimated production whereas allocations Of shipment via TAPS are based upon actual production. This difference can be easily shown by example: Commingled LPC Production Es~;ima[ecl AC~al Pt. Mclntyre 70M STB/D 60M STB/D Lisburne 27M STB/D 30M STB/D West Beach 3M STB/D 4M STB/D If the estimated 100M STB/D is tendered as one nomination as part of Lisburne Production Center production from the Prudhoe Bay Unit, the RIK purchasers will receive their full share of the lesser actual production. If the estimated 100M STB/D is tendered separately, Pt. Mclntyre will be allocated 70% of the actual commingled production and Lisburne/West Beach will be allocated 30%. In this example, Pt. Mclntyre would receive 70% of 94M STB/D or 65.8M STB/D and Lisburne/West Beach would receive 30% of 94M STB/D or 28.2M STB/D 11 be negotiated. In addition, either lease operations or operation under a new unit would require a new round of agency approvals. The new circumstances would complicate agency decision- making, at best, and at worst may preclude issuance of the required approvals. The situation could easily degenerate into a web of litigation, further adding costs and delaying resolution. In sum, the exclusion of the Subject Tracts from the Prudhoe Bay Unit necessitates enormous administrative tasks which could delay production start-up for years. During that time, every party, including the State, would be precluded from enjoying the revenue from Pt. Mclntyre production. Because the criteria of 11 AAC 83.303 are met, and due to the circumstances of the l:'rudhoe Bay Unit, the contraction of the Subject Tracts should continue to be deferred. B, Only lands which 0x¢ "ngt included or entitled to be included in a Participating Area" can be lawfully contracted. Article 9.3 of the Prudhoe Bay Unit Agreement ("PBUA") states: Any lands not included or entitled to be included in.a Participating Area on the tenth (10th) anniversary of the Effective Date shall be excluded from the Unit Area and from this agreement. Because the Department approved the deferral of the contraction of the Subject Tracts through March 31, 1993 (Attachment C), PBUA 9.3 has been effectively amended to read as follows: Any lands not included or entitled to be included in a Participating Area on March 31, 1993 shall be excluded from the Unit Area and from this agreement. Under this provision lands can only be excluded from the Prudhoe Bay Unit if they are not included or entitled to be included in a participating area on March 31, 1993. In the present case, portions of the Subject Tracts w¢r~ entitled to be included in a participating area on March 31, 1993 and are still entitled to be included in a participating area. Indeed, the Pt. Mclntyre instead of the 34M STB/D actually produced. Unless the State has elected RIK from all fields in equal percentages tbr exactly the same RIK purchasers, the RIK purchasers will receive their share of 28.2M STB/D instead of a share of the 34M STB/D to which they would be entitled to receive. 12 Owners' application for formation of the Pt. Mclntyre Participating Area was tiled with the State on March 18, 1993. The legal standards for inclusion in a participating area are set forth by 11 AAC 83.351. 11 AAC 83.351(a) states: The participating area may include only the land reasonably known to be underlain by hydrocarbons and known 9r reasonably estimated through use of geological, geophysical, or engineering data to be capable of producing or contributing to production of hydrocarbons in paying quantities. (emphasis added) 11 AAC 83.395(4) defines "paying quantities" as: quantities sufficient to yield a return in excess of operating costs, even if drilling and equipment costs may never be repaid and the undertaking considered as a whole may ultimately result in a loss; quantities are insufficient to yield a return in excess of operating costs unless those quantities, not considering the costs of transportation and marketing, will produce sufficient revenue to induce a prudent operator to produce those quantities. Each of the Subject Tracts includes acreage reasonably known or reasonably estimated to be capable of producing or contributing to the production of hydrocarbons in paying quantities, because the West Beach, Pt. Mclntyre, North Pmdhoe Bay, and Gull Island reservoirs underlie the Subject Tracts. See Appendix A. The applications for the formation of the West Beach and Pt. Mclntyre participating areas and for tract operations on the North Prudhoe Bay State No. 3 (Attachments J, A and P) discuss in detail, the supporting geological, geophysical, and engineering data. Further, each of the Subject Tracts contains a well which has been certified to be capable of producing in paying quantities.15 Because the Subject Tracts were entitled to be included in a participating area as of March 31, 1993, the Decision to contract these Tracts was error. 15These wells are the Pt. Mclntyre No. 3 (Tract 8), the Pt. Mclntyre No. 5 (Tract 7), the West Beach No. 3 (Tract 6), and the Gull Island No. 1 (Tract 5). In addition, Leaseholders have requested that the North Prudhoe Bay State No. 3 (Tract 8) be certified as capable of producing in paying quantities. Attachment P. 13 C. Lands covered by an approved plan of development cannot be contracted from the Prudhoe Bay Unit so long as operations are being diligently conducted vursuant to those plans. PBUA 4.2 states: if Unit Operators have timely submitted a plan of development and operation on a Reservoir basis (or portion thereof), coveting a portion of such lands, and such plan has been approved by the Director, then land~ cgver¢cl by .such plan q>f clevelopment an.d ot>eration shall not be excluded from the Unit Area so long as or~erations are being diligently conducted pursuant thereto. (emphasis added) PBUA 4.2 further states: Development and operation of the Unit Area, as it may be enlarged or contracted, pursuant to a plan or plans submitted and approved by the Director in accordance with this Section 4.2, shall be deemed full performance of all obligations for develot>ment and ot>eration with rest~ect to each and every Tract included in such pian or plans, regardless of whether thet:e is any develor~ment of any particular Tract or Tracts of the Unit Arei~, notwittistanding anything to the contrary in the lease. (emphasis added) The first plan of development and operation for lands not included in the Initial Participating Areas was submitted on April 1, 1977 as Exhibit E-~ .to the PBUA. Attachment F. This was approved by the Department by the approval of the PBUA. (PBUA 4.2) PBUA 4.2 requires the submittal of a further plan of development and operation for lands not then included in a Participating Area. On February 28, 1992, a plan of development and operation was submitted for Pt. Mclntyre (Tracts 6, 7, and 8)and a plan of exploration was submitted for Gull Island (Tract 5). Attachment Q. These plans were deemed approved by the Department pursuant to 11 AAC 83.343(c) and 11 AAC 83.341(b). Thus, ARCO and Exxon timely submitted plans of development and operation for Tracts 5, 6, 7, and 8, which have been approved by the Department. Furthermore, ARCO and Exxon have diligently conducted operations pursuant to the plans of development and operation. The Pt. Mclntyre Owners have invested hundreds of millions of dollars to evaluate the reservoirs and to modify and construct facilities to allow the production of the reservoirs. Twenty-eight wells have been drilled to date, one well is currently drilling, and sixty to seventv wells are planned for the next three years. Attachments E and G. 14 Facilities have been modified and constructed such that Pt. McIntyre will be capable of production in July of 1993. Preparations and expenditures for the West Beach reservoir production are completed, and production began on April 8, 1993. (As noted above, PBUA 4.2 does not require that these operations actually occur on Tracts 5, 6, 7, and 8, because activities conducted pursuant to a plan of development and operations is deemed full performance of all obligations for development and operation with respect to each and every Tract.) Because Leaseholders have diligently conducted operations pursuant to approved plans of development and operation for Tracts 5, 6, 7, and 8, contraction of the Prudhoe Bay Unit to exclude these tracts was error. D. Th¢.P~dhoe Bay Uni[ canno[ be contracted if bona fide drilling operations are bein_u diligently conducted on any lands not then included in a Participating Area. PBUA 4.2 states' If Unit Operators fail to submit an acceptable ,.further plan of development and operation or fail in a substantial respect to conduct the operations included in an approved plan, the Director may ur~on notice to Unit Operators and the affected Working IntCres~ Owners exclude from Unit Area any lands not then included in a Participating Area; provided, however, that such lands ~hall nQ[ be excluded while bona fide drilling or~erations are heine conducted on any such lands and continued diligently, with at lehst one well being ¢0mmenced on each calendar year and followed bv a ~ood faith attemr~t to comt~lete such we~l di~rine the winter drilling seasoft. (emphasis added) Even if ARCO and Exxon had nq)[ timely submitted plans of development and operation, and had not conducted operations pursuant to these plans in a "substantial" respect, contraction of the Prudhoe Bay Unit is not permitted without notice and so long as bona fide drilling operations are being diligently conducted on such lands. Twenty-eight wells have been commenced and completed since 1988 (twelve of which are on the Subject Tracts)16 and Well Pl-13 is currently drilling. It is interesting to note that Well PI-16 was being drilled on April 1, 1993, when the 16As noted above, PBUA 4.2 does not require that these operations actually occur on Tracts 5, 6, 7, and 8. 15 Unit ostensibly contracted. Well Pl-17 was drilling and the North Prudhoe Bay No. 3 was being tested, both on Tract 8, on April 15, 1993 when ARCO received notice of the contraction. For these reasons, contraction of the Prudhoe Bay Unit to exclude Tracts 5, 6, 7, and 8 was error. E, Tracts 5. 6. 7. and 8 should not have been contracted because Leaseholders have the contractual right to exr)and the Pmdhoe Bay Unit to include these Tracts. -- _ PBUA 9.1 states: The Unit Area may be enlarged from time to time so as to include any additional lands reasonably determined to be within any Reservoir any portion of which is within the Unit Area. The Pt. Mclntyre reservoir, as reasonably determined, underlies Tracts 6, 7, and 8. Appendix A. A portion of the Pt. Mclntyre reservoir was within the boundaries of the Pmdhoe Bay Unit when the Pt. Mclntyre Owners applied for formation of the Pt. Mclntyre Participating Area and expansion of the Prudhoe Bay Unit prior to the Depamnent's attempt to contract the Pmdhoe Bay Unit. Thus, Leaseholders have a contractual right to expand the Prudhoe Bay unit to include those portions of Tracts .6, 7, and 8 which contain the Pt. Mclntyre reservoir. Additionally, Tracts 5, 6, 7 and 8 should remain in the Prudhoe Bay Unit because the West Beach reservoir underlies Tracts 5, 6 and 7, and the North Prudhoe Bay Reservoir underlies Tracts 7 and 8. Appendix A. Because Leaseholders have a contractual right to expand the Prudhoe Bay Unit to include the Subj'ect Tracts, it was error to contract the Subject Tracts from the Pmdhoe Bay Unit. F. The unit should not be contracted to exclude land covered bv an approved plan or exploration or development, 11 AAC 83.356(e) prohibits the contraction of the Subject Tracts from the Prudhoe Bay Unit because the Subject Tracts are covered by approved plans of exploration and development. 11 AAC 83.356(e) states: Not sooner than 10 years after the effective date of the unit agreement, the commissioner will, in the commissioner's 16 discretion, contract the unit area to include only that land covered by an approved unit plan of exploration or development .... As shown in Section C above, the Subject Tracts are covered by approved unit plans of exploration and development: Thus, it was error to contract the Subject Tracts from the Prudhoe Bay Unit. G. The Prudhoe Bay Unit must encomp~t~$ the Pt, Mclntyr¢, We~[ Beach. North Prudhoe Bay. and Gull Island reservoir~ 11 AAC 83.356(a) states: A unit must encompass the minimum area required to include all or pan of one or more oil or gas reservoirs, or all or pan of one or more potential hydrocarbon accumulations. The Subject Tracts overlie proven oil and gas reservoirs and potential hydrocarbon accumulations. The Pt. Mclntyre reservoir underlies Tracts 6, 7, and 8, the West Beach reservoir underlies Tracts 5, 6, and 7, the North Prudhoe Bay reservoir underlies Tracts 7 and 8, and the ..:. Gull Island reservoir underlies Tract 5. See Appendix A. .~ Because the Subject Tracts overlie proven oil and gas reservoirs and potential hydrocarbon accumulations, it was error to contract the Subject Tracts from the Prudhoe Bay Unit. H. The unit should not be contracted to exclude land underlain by provCn or potential hydrocarbon reservoirs. l~ 1 AAC 83.356(e) states: Not sooner than 10 years after the effective date of the unit agreement, the commissioner will, in the commissioner's discretion, contract the unit area to include only that land covered by an approved unit plan of exploration or development, or that area ondcrlain by one or more oil or gas reservoir~ or one or more pot.~ntial hydrocarbon accumulations and lands that facilitate production as set out in (b) of this section. (emphasis added) As described in Section G above, the Subject Tracts overlie proven oil and gas reservoirs and potential hydrocarbon accumulations. See Appendix A. Because the Subject Tracts overlie 17 proven oil and gas reservoirs and potential hydrocarbon accumulations, it was error to contract the Subject Tracts from the Prudhoe Bay Unit. I. Leaseholders .complied with and relied upon the terms of the decision of the Commissioner dated February 25. 1987. In October of 1986, it became evident that evaluation of the Subject Tracts was not complete enough to request that they remain committed to the Prudhoe Bay Unit by April 1, 1987, and, therefore, the Subject Tracts were subject to contraction. Leaseholders requested the Department to defer contraction of the Subject Tracts in accordance with 11 AAC 83.356(b). Attachment H. The purpose of this deferral was to allow Leaseholders to further test and evaluate the Subject Tracts so that the commerciality of the underlying reservoirs could be confirmed. The size and location of these reservoirs are such that they can only be economically developed if existing Prudhoe Bay Unit facilities are utilized. By decision dated February 25, 1987, as amended (the "1987 Decision"), the Department granted the Subject Leases a contraction deferral until April 1, 1992 on the condition that Leaseholders satisfy two conditions: (A) A well to delineate the hydrocarbon reserves underlying ADL 28297 [Tract 8] and ADL 34624 [Tract 7] must be drilled and completed prior to April 1, 1992; and (B) A commitment by the lessees to drill a second well to delineate the hydrocarbon reserves underlying ADL 34626 [Tract 5] and ADL 34627 [Tract 6] must be made by April 1, 1992. (Attachment I) By'letter dated April 6, 1988, the Department also stated: "[s]hould the Pt. Mclntyre No. 3 well be drilled to a bottomhole location within ADL 28297 [Tract 8], the Division will accept this well as satisfying the first drilling requirement of the Amended Decision." (Attachment I) Leaseholders have complied with the conditions imposed by the Director. Condition (A) was met when the Pt. Mclntyre No. 3 was drilled to a bottomhole location within ADL 28297 (Tract 8). Attachments E and G. This well was completed in April of 1988. Id. The Division of Oil and Gas acknowledged that Condition (A) had been met by internal memo dated August 17, 1988. Attachment R. In addition, the Pt. Mclntyre No. 8 was completed on Tract 8 in March of 18 1990, and the Pt. Mclntyre No. 5 and No. 10 wells were both completed on Tract 7 in June of 1989 and July of 1991, respectively. Attachments E and G. Condition (B) was met when the Pt. Mclntyre Owners committed, on February 28, 1992, to drill the Pt. Mclntyre No. F-2 to a bottomhole location in Tract 6 in the second quarter of 1992. Attachment Q. Although both conditions were met and deferral thereby granted, the Department imposed additional conditions by refusing to grant deferral until the results of the F-2 and Gull Island No. 3 were presented to the Department. Attachment H. Due to unforeseen difficulties, drilling of the original F-2 well (Well P2-50), which was spudded in May of 1992, and Well P2-50A, its sidetrack, were suspended. The replacement well, Well P2-48, was spudded on Tract 6 in November of 1992 and was completed in December of 1992. The P2-50, P2-50A, and P2-48 were all drilled within the Prudhoe Bay Unit boundary. The Pt. Mclntyre Owners fulfilled the Department's additional conditions by submitting data from the P2-48 and the Gull Island No. 3 wells to the Department on January 12, 1993. Attachment S. In addition, the Pt. Mclntyre Participating Area application was filed with the Department on March 18, 1993. Attachment A. The portions of Tracts 6, 7 and 8 which overlie the Pt. Mclntyre reservoir are included in the proposed Pt. Mclntyre Participating Area. All of the requirements for a complete expansion application have been met and notice of the application has been published for public comment. Attachment K. The Wes~ Beach Participating Ama application was filed with the Department on November 20, 1992 and was approved by the Department on April 2, 1993 as to all tracts except for Tract 5.17 Attachments J and L. As stated previously, in reliance upon the 1987 Decision, the Leaseholders have expended hundreds of millions of dollars, and spent the last several years negotiating facility sharing agreements and seeking agency approvals. Because of this reliance, it is unfair to contract the Subject Tracts and, at the last minute, require Leaseholders to pursue a different and lengthy procedural path. Moreover, it is not in the State's best interest to defer start-up of production. 17See footnote 7. 19 J. The Prudho¢ Bay Unit cannot be contracted absent reasonable notice and an opportu_nity to be hearcl. 11 AAC 83.301, 11 AAC 83.356(e) provides: Before any contraction of the unit area under this subsection, the commissioner will give the unit operator, the working interest owners, and the royalty owners of the leases or portions of the leases being excluded r¢ilsona.lple notice and an opportunity to be he~d. (emphasis added) On April 15, 1993, ARCO received the Decision which notified ARCO that the Tracts would be contracted from the Prudhoe Bay Unit. The Decision noted that the contraction was retroactively effective as of April 1, 1993. Thus, Leaseholders were not given prior notice of the exclusion of the Subject Leases and Leaseholders had no opportunity to be heard. For this reason, the Decision to contract the Subject Leases was error. IV. REOUEST FOR HEARING Leaseholders believe that the Commissioner may decide in Leaseholders' favor based upon the strength of this brief and its attachments. If the Commissioner believes otherwise, Leaseholders request a hearing at the Commissioner's earliest convenience, as start-up of the Pt. Mclntyre field will be physically possible on July 1, 1993. If a hearing will be held, the issues that need to be decided are 1) whether the contraction of Tracts 6, 7, and 8 should continue to be deferred until the Pt. Mclntyre Owners' application to expand {he' Prudhoe Bay Unit and form the Pt. Mclntyre Participating Area within the Prudhoe Bay Unit is finally determined by the state; and 2) whether the contraction of Tract 5 should continue to be deferred until April 1, 1994. These are mixed questions of law and fact. Moreover, each of the Legal Arguments above involves issues of law and fact. in accordance with 11 AAC 02.050(b), Leaseholders request that the hearing process include such normal due process procedures as the right to present oral testimony, cross-examine witnesses, and file post-hearing briefs. 2O V. REMEDY REOUESTED Leaseholders request that the Department defer the contraction of the Prudhoe Bay Unit as to Tracts 6, 7, and 8 until the application to expand the Prudhoe Bay Unit and form the Pt. Mclnt.vre Participating Area. within the Prudhoe Bay Unit is finally determined by the state. I_.easeholders request that the Department defer the contraction of the Prudhoe Bay Unit as to Tract 5 be deferred until April 1, 1994, as Leaseholders continue to evaluate this area with seismic and core data studies. VI. CONCLUSION It is hard for Leaseholders to conceive of what State interest is being advanced by contracting the Subject Tracts from the Prudhoe Bay Unit while there is a pending application to include the same Tracts in the Pt. McIntyre Participating Area within the Prudhoe Bay Unit. Contraction can only result in confusion and delay. For the reasons set forth above, Leaseholders request that contraction of the Subject Tracts be deferred until the Department reaches a final ., decision on the pending application to expand the Pmdhoe Bay Unit and form the Pt. McIntyre Participating Area. osanne M. Jacobsen ARCO Alaska, Inc. Rosanne M. Jacobsen P. O. Box 100360 ATO-2088 Anchorage, Alaska 99510-0360 Exxon Company, U.S.A., a Division of Exxon Corporation Gary E. Baker Law Department 800 Bell Street P. O. Box 2180 Houston, Texas 77252-2180 21 .\pPE;NDIX .\ 1. The Pt, Mclntw¢ Reservoir underlies Tracts 6.7. and 8. The Pt. Mclntvre reservoir I Kuparuk Formation.~ underlies Tracts 6. 7 'and 8 as shown on the ~_eologic maps submitted with the Pt. Mclntwe Participating Area application. (See Attachments 8, 9 and 10 of the Pt. Mclntyre Participating Area application, which is Attachment A to this brief). These maps are a product of the twelve member Pt. Mclntyre equity team1 and are based on well control from nineteen wells and a 1990 3-D seismic program which covers the entire Pt. Mclnt.vre Participating Area. Pt. Mclntyre Well P2-48 (F-2A)2 was drilled on Tract 6 at a location within the PBU boundary. This well encountered 98' of high quality oil bearing sandstone in the Kuparuk Formation. Attachment T. In addition, Pt. Mclntyre Well No.'s 3, 5, 10 and PI-G1 were drilled within 1200 ft, 1650 ft, 750 f-t, and 1750 ft from the PBU boundary., respectively, and confirm the presence of the Pt. Mclntyre reservoir underlying Tracts 6, 7, and 8. _.,." The West Beach Reservoir un0¢rlics Traqt~ ~. 6. and 7 The West Beach reservoir underlies Tracts 5, 6, and 7 as shown on the geologic maps submitted with the West Beach Participating Area application. Attachment J. These maps are based on well control from the West Beach No. 3, No. 3B, and No. 4 wells, the Gull Island No. 1 and No. 3 wells, and on a 1990 3-D seismic program. The details of the technical and legal bases for concluding that the West Beach reservoir underlies Tract 5 are covered by separate proceedings. 3. Thc Ngrth Prudhoe Bay R~$¢rvoir underlies Tracts 7 and 8 The North Pmdhoe Bay State No. 3 well was spudded in January of 1993 and was completed in the Sadlerochit formation. The surface location of the well is within the Prudhoe Bay Unit and the bottomhole 1 In order to rigorously determine oil-in-place by tract to assist in equity determination and location of development wells, the ?t. Mclntvre Owners formed a twelve member equity team consisting of one geologist, geophysicist, petrophysicist and mapper t'rom each Owner. (This team cont'iguration, designed to result in maps which are as accurate as technically possible, is intended to guard against any bias in interpretation of seismic and well data.'). The team has been working full-time since May ,.~t' 1992 to interpret and integrate the results of the drilling program with a 3-D seismic survey of the area. The team has ?reduced a structure map, gross sand is(xziaore and hydrocarbon pore-foot map et' the Pt. Mclntvre reservoir, among other things. '\\"ell F-2 (P2-50), spudded in Mav ~>~' 1!)~¢2, required a sidetrack IP2-50a'). 'Fh¢ sidetrack was unsuccessful. The well was r'~'cirilled as the F-2A (P2-483 in Decernt',er (>t' 1992. '~cation is on Tract 8. The reservoir underlies Tracts 7 and 8. as well as Prudhoe Bay Unit Tract 27. These · :'~aps are based on seismic and the North Prudhoe Bay No.'s 1. 2. and 3. and the .Abel State No. 1 well. )n .Xlav 1-7. 1993. Leaseholders petitioned the Department to certifv the North Pmdhoe Bay No. $ as _ ::pable of producing in paying quantities and to allow Leaseholders to operate the well as a Tract Operation '.vithin the Pmdhoe Bay Unit. Attachment P. 4. The Gull Island Reservoir underlies Tract 5, The Gull Island No. 1 was spudded in March of 1975 and tested the Shublik Formation. The well's bottom hole location is on Tract 5, and the reservoir underlies Tract 5. This well was certified capable of producing in paying quantities in February of 1977. Attachment U. .-\ PPENDIX B E,:ploration and Devet0pment Drilling The Subject Tracts were ieased bv .ARCO and Exxon in October of 1965 (Tract 8') and April of 1967 ~ Tracts 5, 6, and 7) and were committed to the Prudhoe Bay Unit on April 1, 1977. The first plan of development and operation for lands outside the Prudhoe Bay Unit Initial Participating Area, which included the Subject Tracts, was attached as Exhibit E-1 to the Prudhoe Bay Unit Agreement ("PBUA") (Attachment F) and was approved by the Department. (PBUA Art. 4.2). Early exploration activities on the Subject Tracts included the acquisition of seismic data in 1982, 1983, 1990 and 1991 and the drilling of the North Prudhoe Bay No. 1 in February of 1970, the Gull Island No. 1 in March of 1975, and the West Beach No. 3 in April of 1976. Both the Gull Island No. 1 and West Beach No. 3 wells were certified capable of t~roducing in paying quantities in February of 1977. Attachments E and G. The Pt. McIntyre No. 3 was spudded on Tract 8 in March of 1988. This well discovered pay in the ,. Kuparuk and Stump Island reservoirs and was completed in April of 1988. The Department approved Leaseholder's application for discovery royalty. Since discovery, ARCO, Exxon and BP (the "Pt. McIntyre Owners") have worked aggressively to delineate and develop the field, investing approximately S 110,000,000 to date in the drilling, completion and testing of Pt. McIntyre wells alone. Twenty-eight ,,,,'elis have been drilled in the West Beach/Pt. McIntyre area since discovery,, with at least two wells being drilled each calendar year. Attachments E and G. Twelve of the twenty-eight wells were drilled on Tracts 6, 7 or 8. Sixty' to seventy, additional development wells are planned to be drilled over the next three years. Drilling at Pt. Mclntyre has been essentially continuous since March of 1992. In fact, when the ~otification of the contraction of Tracts 5, 6, 7, and 8 from the Prudhoe Bay Unit was received on April 14, i ~)9,~, the Pt..'vlcIntvre No. PI-17 was bein,,~ drilled on Tract 8. Well No. P1-13 is currentlv being drilled ,,n Tract $. In addition to aaaressiveiv developin(, the Pt. ,¥IcIntvre reservoir underlvin(, Tracts 6 7 and 8, i_~aseholders have also been ~ctive in ex'aluatin~_ deeper formations underlvin~ these tracts. The North '):'udi~o¢ Bat,,.' ,qtate No. 3 was ¢iriiled within the Prudhoe Bay L.'~it boundary to evaiuate deeper horizons on 'Tract ~ in January of 1993. This well was heinz tested when the Prudhoe Bav Unit contraction notice was :'zzeived from the Department..-X request for tract operations and to certify the well as capable of producing 'n paying quantities was filed on May 17, 1993 and is pending. ,Attachment P. To date, Pt. McIntvre No.'s 3, 4, 5, and 7. the West Beach No.'s 3 and 4. and the Gull Island No. · !,,ave each been cemfied as capable of prociuction in paying quannties by the Department. LIST OF ATTACHMENTS me Bo Application to Expand the Prudhoe Bay Unit and Form the Pt. Mclntvre Participating Area within the Prudhoe Bay Unit. March 18, 1993. Request for Deferral of Contraction of Prudhoe Bay Unit; Affected Tracts 5, 6, 7, and 8. March 31, 1993. C. April 14, 1993 Denial of Contraction Deferral Request. D. April 30, 1993 Appeal Documents. E. Pt. Mclntyre Wells (June 1, 1993). F. Unit Agreement, Prudhoe Bay Unit, State of Alaska. G. Pt. Mclntyre Area Wells, June 3, 1993. J. Contraction Deferral Correspondence. February 25, 1987 Decision of the Commissioner Delayin.g Unit Contraction as to Tracts 5, 6, 7, and 8. Application to Form the Berch Participating Area within the Prudhoe Bay Unit. November 20, 1992. Ko Ce Public Notice of Application to Expand Prudhoe Bay Unit Area and Form Pt. Mclntyre Participating Area. Decision and Findings of the Commissioner re Application for the Formation of the West Bend Participating Area, April 2, 1993. Me Conservation Order No. 311, February 25, 1993. February 14, 1991 Letter from Department of Revenue Commissioner Lee E. Fisher to J. D. Dayton and F. S. Mahoney. Oo Po Q. 1980 Settlement Agreement. May 17, 1993 Letter from A. D. Simon to Director Eason and Chairman Johnston re North Prudhoe Bay State No. 3. February 28, 1992 Request for Deferral of Contraction of Prudhoe Bay Unit Affected Tracts 5, 6, 7, and 8. R. August 17, 1988 memo from Mike Kotowski to file. S. January 12, 1993 ARCO/DNR Meeting. r. U. F-2 Well Log (P2-48). February 1, 1977 Determination of Wells Capable of Producing in Paying Quantities.
