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Home My WebLink AboutO 148OTHER ORDER 148 Greater Mooses Tooth #2 1. July 12, 2018 CPAI's request for GMT2 Measure approval 2. October 8, 2018 Data room access and non -disclosure agreement 3. August 15, 2018 Notice of Hearing, affidavit of publication, email disstribution, mailings 4 - ----------------- Letters of Support 5. October 23, 2018 Transcripts, sign -in sheet and presentation STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ) Docket No. OTH 18-045 ConocoPhillips Alaska, Inc. for a waiver of ) Other Order No. 148 the requirements of 20 AAC 25.228(a) to ) Greater Moose's Tooth Unit provide custody transfer measurement of ) Greater Moose's Tooth 2Pad hydrocarbons prior to severance from the ) North Slope Borough, Alaska lease or unit. ) December 19, 2018 IT APPEARING THAT: By letter dated July 12, 2018, ConocoPhillips Alaska, Inc. (CPAI) requests a waiver to the requirements of 20 AAC 25.228(a) to Utilize a coriolis-based metering system at Greater Moose's Tooth (GMT) Pad 2 (GMT2) to allocate GMT Unit production to GMT2; production would be commingled with GMT Pad 1 (GMT I) production and Colville River Unit (CRU) production and shipped to the Alpine Central Facilities (ACF) for processing to pipeline quality requirements and final sales measurement. 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) tentatively scheduled a public hearing for October 23, 2018. On August 14, 2018, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website, on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies to all persons on the AOGCC's mailing distribution list. On August 15, 2018, the notice was published in the Anchorage Daily News. On October 17, 2018, CPAI provided access to a data room for an AOGCC Senior Reservoir Engineer to review project economic information on the GMT2 project. 4. Written comments supporting CPAI's request were received from the Division of Oil & Gas of the Alaska Department of Natural Resources (DNR) on October 12, 2018, the Tax Division of the Alaska Department of Revenue on October 22, 2018, the Arctic Slope Regional Corporation (ASRC) on October 23, 2018, and the United States Bureau of Land Management (BLM) on October 29, 2018. 5. The hearing was held as scheduled on October 23, 2018. Evidence was received from CPAI. FINDINGS: 1. CPAI is the operator and sole working interest owner of the GMTU and CPAI is the operator of the CRU. The WIOs for the CRU are CPAI and Petro -Hunt, LLC. Both units are located within the North Slope Borough, Alaska. 2. The GMTU landowners are the BLM and ASRC. The CRU landowners are DNR, BLM, and ASRC. All potentially affected landowners provided letters of support/nonobjection to CPAI's proposed methodology for allocating production the GMT2. Other Order 148 December 19, 2018 Page 2 of 3 3. CPAI proposes to install a single stage three-phase separator to support measurement of production leaving the GMT2 development. The oil leg coming off the three-phase separator will be metered with coriolis meters and water cut analyzer; the gas leg will be metered by orifice meters sized to measure the full range of expected flow. After metering the oil and gas flow streams will be recombined before being shipped to GMTI where they will be combined with GMTI production before being shipped on to Colville Delta Pad 5 (CD5) and commingled with the CRU production gathering system. 4. The commingled GMTU and CRU production will be processed to pipeline sales quality specifications at the ACF and then metered at the CRU lease automatic custody transfer (LACT) sales meter before shipping to market. 5. CPAI proposes that the production allocation factor for GMT2 be fixed at 1.0 as it is for GMTI. Thus, the oil production allocated to the CRU would be the volume measured by the CRU LACT meter minus the volume measured through the Coriolis meters coming off the three-phase separators at GMTI and GMT2. 6. The orifice meters coming off the three-phase separator at GMT2 will serve as the gas sales meter for gas shipped from GMT2 to the CRU. 7. CPAI maintains that stand-alone production facilities at GMT2 would be necessary to process the production to pipeline sales quality before custody transfer quality metering could occur as required 20 AAC 25.228(a). 8. CPAI testified that a stand-alone processing facility at GMTI would cost in the neighborhood of $700 to $900 million and that this would make the project non - economically competitive, prevent the project from being developed, resulting in stranded oil and gas. 9. CPAI provided the AOGCC access to a data room to review confidential project specific economics. The information made available to the AOGCC included a cost estimate prepared for CPAI by Turner & Townsend Larkspur (TTL), a company with extensive experience preparing conceptual project cost estimates for CPAI and other operators on the North Slope. TTL bases its estimates on other costs estimates it prepared and recently completed projects as bench marks when they prepare new cost estimates. CONCLUSIONS: I. An exception to 20 AAC 25.228 is necessary to allow for final custody transfer quality metering of oil production from GMT2 to occur after the production has been severed from the unit and commingled with production from GMT 1 and the CRU before being processed at ACF and metered for sale at the CRU LACT meter. 2. CPAI's cost estimate was very thorough, including items such as timing of expenditures and contingencies for various components of the project. The estimate is sufficiently detailed to provide a valid basis upon which to assess CPAI's assertions. 3. The evidence presented demonstrates that a stand-alone production facility at GMT 1 in the current economic environment would not be pursued by CPAI. Absent the exception, the reserves at GMTI would not be produced for the foreseeable future. 4. A waiver of the requirements of 20 AAC 25.228 that requires custody quality metering to occur before oil or gas is severed from a lease or unit is necessary in order to allow the maximization of recovery from GMT2. Other Order 148 December 19, 2018 Page 3 of 3 5. Assigning an allocation factor of 1.0 to the three-phase separators and metering systems at GMTI and GMT2 makes the assumption that the GMTU metering systems are 100% accurate. Any error in those systems would be applied to CRU production. This would result in one unit over -reporting production while the other unit under -reports. Since the landownership of the two units is different this would result in landowners being over or under paid for royalties for production from their lands. AOGCC approves the 1.0 allocation factor based on the fact all potentially affected landowners have submitted letters of support/nonobjection for CPAI's application, including, specifically, approval of a meter factor of 1.0 for the GMT2 system. 6. Additional information on the specifics of the meter system design is necessary before those components can be approved. NOW THEREFORE IT IS ORDERED: 1. CPAI's request for a waiver of the requirements of 20 AAC 25.228 to allow for fiscal allocation of production from GMT2 to be based on a metering system that does not meet custody transfer quality standards is hereby APPROVED. 2. The specific design of the GMT2 fiscal allocation metering system must be approved by the AOGCC before being installed and operated. Refer to AOGCC Industry Guidance Bulletin 13-002 for details regarding the measurement application(s). DONE at Anchorage, Alaska and dated December 19, 2018. Hollis S. French Daniel T. Seamount, Jr. Cathy Chair, Commissioner Commissioner Commis: As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it maybe appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to ran is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7o Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ) Docket No. OTH 18-045 ConocoPhillips Alaska, Inc. for a waiver of ) Other Order No. 148 the requirements of 20 AAC 25.228(a) to ) Greater Moose's Tooth Unit provide custody transfer measurement of ) Greater Moose's Tooth 2Pad hydrocarbons prior to severance from the ) North Slope Borough, Alaska lease or unit. ) December 19, 2018 IT APPEARING THAT: By letter dated July 12, 2018, ConocoPhillips Alaska, Inc. (CPAI) requests a waiver to the requirements of 20 AAC 25.228(a) to Utilize a coriolis-based metering system at Greater Moose's Tooth (GMT) Pad 2 (GMT2) to allocate GMT Unit production to GMT2; production would be commingled with GMT Pad 1 (GMT I) production and Colville River Unit (CRU) production and shipped to the Alpine Central Facilities (ACF) for processing to pipeline quality requirements and final sales measurement. 2. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) tentatively scheduled a public hearing for October 23, 2018. On August 14, 2018, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website, on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies to all persons on the AOGCC's mailing distribution list. On August 15, 2018, the notice was published in the Anchorage Daily News. 3. On October 17, 2018, CPAI provided access to a data room for an AOGCC Senior Reservoir Engineer to review project economic information on the GMT2 project. 4. Written comments supporting CPAI's request were received from the Division of Oil & Gas of the Alaska Department of Natural Resources (DNR) on October 12, 2018, the Tax Division of the Alaska Department of Revenue on October 22, 2018, the Arctic Slope Regional Corporation (ASRC) on October 23, 2018, and the United States Bureau of Land Management (BLM) on October 29, 2018. 5. The hearing was held as scheduled on October 23, 2018. Evidence was received from CPAI. FINDINGS: 1. CPAI is the operator and sole working interest owner of the GMTU and CPAI is the operator of the CRU. The WIOs for the CRU are CPAI and Petro -Hunt, LLC. Both units are located within the North Slope Borough, Alaska. 2. The GMTU landowners are the BLM and ASRC. The CRU landowners are DNR, BLM, and ASRC. All potentially affected landowners provided letters of support/nonobjection to CPAI's proposed methodology for allocating production the GMT2. Other Order 148 December 19, 2018 Page 2 of 3 3. CPAI proposes to install a single stage three-phase separator to support measurement of production leaving the GMT2 development. The oil leg coming off the three-phase separator will be metered with coriolis meters and water cut analyzer; the gas leg will be metered by orifice meters sized to measure the full range of expected flow. After metering the oil and gas flow streams will be recombined before being shipped to GMTI where they will be combined with GMTI production before being shipped on to Colville Delta Pad 5 (CD5) and commingled with the CRU production gathering system. 4. The commingled GMTU and CRU production will be processed to pipeline sales quality specifications at the ACF and then metered at the CRU lease automatic custody transfer (LACT) sales meter before shipping to market. 5. CPAI proposes that the production allocation factor for GMT2 be fixed at 1.0 as it is for GMTI. Thus, the oil production allocated to the CRU would be the volume measured by the CRU LACT meter minus the volume measured through the Coriolis meters coming off the three-phase separators at GMTI and GMT2. 6. The orifice meters coming off the three-phase separator at GMT2 will serve as the gas sales meter for gas shipped from GMT2 to the CRU. 7. CPAI maintains that stand-alone production facilities at GMT2 would be necessary to process the production to pipeline sales quality before custody transfer quality metering could occur as required 20 AAC 25.228(a). 8. CPAI testified that a stand-alone processing facility at GMT] would cost in the neighborhood of $700 to $900 million and that this would make the project non - economically competitive, prevent the project from being developed, resulting in stranded oil and gas. 9. CPAI provided the AOGCC access to a data room to review confidential project specific economics. The information made available to the AOGCC included a cost estimate prepared for CPAI by Turner & Townsend Larkspur (TTL), a company with extensive experience preparing conceptual project cost estimates for CPAI and other operators on the North Slope. TTL bases its estimates on other costs estimates it prepared and recently completed projects as bench marks when they prepare new cost estimates. CONCLUSIONS: 1. An exception to 20 AAC 25.228 is necessary to allow for final custody transfer quality metering of oil production from GMT2 to occur after the production has been severed from the unit and commingled with production from GMT 1 and the CRU before being processed at ACF and metered for sale at the CRU LACT meter. 2. CPAI's cost estimate was very thorough, including items such as timing of expenditures and contingencies for various components of the project. The estimate is sufficiently detailed to provide a valid basis upon which to assess CPAI's assertions. 3. The evidence presented demonstrates that a stand-alone production facility at GMTI in the current economic environment would not be pursued by CPAI. Absent the exception, the reserves at GMTI would not be produced for the foreseeable future. 4. A waiver of the requirements of 20 AAC 25.228 that requires custody quality metering to occur before oil or gas is severed from a lease or unit is necessary in order to allow the maximization of recovery from GMT2. Other Order 148 December 19, 2018 Page 3 of 3 5. Assigning an allocation factor of 1.0 to the three-phase separators and metering systems at GMTI and GMT2 makes the assumption that the GMTU metering systems are 100% accurate. Any error in those systems would be applied to CRU production. This would result in one unit over -reporting production while the other unit under -reports. Since the landownership of the two units is different this would result in landowners being over or under paid for royalties for production from their lands. AOGCC approves the 1.0 allocation factor based on the fact all potentially affected landowners have submitted letters of support/nonobjection for CPAI's application, including, specifically, approval of a meter factor of 1.0 for the GMT2 system. 6. Additional information on the specifics of the meter system design is necessary before those components can be approved. NOW THEREFORE IT IS ORDERED: 1. CPAI's request for a waiver of the requirements of 20 AAC 25.228 to allow for fiscal allocation of production from GMT2 to be based on a metering system that does not meet custody transfer quality standards is hereby APPROVED. 2. The specific design of the GMT2 fiscal allocation metering system must be approved by the AOGCC before being installed and operated. Refer to AOGCC Industry Guidance Bulletin 13-002 for details regarding the measurement application(s). DONE at Anchorage, Alaska and dated December 19, 2018. //signature on file// //signature on file// //signature on file// n Hollis S. French Daniel T. Seamount, Jr. Cathy P. Foerster ,,, Chair, Commissioner Commissioner Commissioner °A,�n„„,,�,� As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order. or decision is believed to be erroneous. The AOGCC shall grantor refuse the application for reconsideration in whole min part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day Bernie Karl Gordon Severson Penny Vadla K&K Recycling Inc. 3201 Westmar Cir. 399 W. Riverview Ave. P.O. Box 58055 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 Fairbanks, AK 99711 George Vaught, Jr. Darwin Waldsmith Richard Wagner P.O. Box 13557 P.O. Box 39309 P.O. Box 60868 Denver, CO 80201-3557 Ninilchik, AK 99639 Fairbanks, AK 99706 AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 ALASKA OIL AND GAS CONSERVATION COMMISSION In the Matter of the Request by ConocoPhillips Alaska, Inc., for Waiver ) of the Requirements of 20 AAC 25.228(a) to ) Provide Custody Transfer Measurement of ) Hydrocarbons Prior to Severance from the ) Lease or Unit. 1 Docket No.: OTH 18-045 ALASKA OIL and GAS CONSERVATION COMMISSION Anchorage, Alaska October 23, 2018 10:00 o'clock a.m. PUBLIC HEARING BEFORE: Hollis French, Chair Daniel T. Seamount Cathy Foerster Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 2 1 TABLE OF CONTENTS 2 Opening remarks by Chair French 03 3 Testimony by Brandon Viator 06 4 Testimony by Jodie Hosack 08 5 Testimony by John Cookson 09 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 3 1 P R O C E E D I N G S 2 (On record) 3 CHAIRMAN FRENCH: I'll call the hearing to 4 order. It's 10:00 o'clock in the morning of October 5 23, 2018. We're here at 333 West Seventh Avenue, 6 Anchorage, Alaska, the headquarters of the Alaska Oil 7 and Gas Conservation Commission. To my right is 8 Commissioner Cathy Foerster, to my left is Commissioner 9 Dan Seamount, I'm Hollis French, the Chair of the 10 Commission. 11 We're here today on docket number OTH 18-045, 12 it's the application of ConocoPhillips Alaska, CPAI, 13 for a waiver of the requirements of 20 AAC 25.228(a), 14 to provide custody meter -- custody transfer 15 measurement of hydrocarbons prior to severance from the 16 lease or unit. 17 ConocoPhillips by letter dated July 12th, 2018 18 has requested the AOGCC to issue a waiver from the 19 requirements of 20 AAC 25.228(a) to allow for final 20 custody transfer metering of hydrocarbons sold from the 21 Greater Mooses Tooth Unit development, for those -- for 22 that final custody transfer metering to occur off unit 23 and to approve the conceptual design of the metering 24 system that will provide fiscal allocation to the GMT2 25 development. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH I8-045 Page 4 1 Computer Matrix will be recording the 2 proceedings, you can get a copy of the transcript from 3 Computer Matrix Reporting. 4 We've got a couple of folks signed up from 5 ConocoPhillips to testify. Are there any other parties 6 planning to testify? 7 (No comments) 8 CHAIRMAN FRENCH: The Commissioners will ask 9 questions during the testimony, we may also take a 10 recess to consult with staff to determine whether 11 additional information or clarifying questions are 12 necessary. If a member of the audience has a question 13 he or she feels should be asked please submit that 14 question in writing to Jody Colombie. She will provide 15 the question to us and if we feel that asking that 16 question will assist us in making our determinations we 17 will ask it. 18 For those testifying please keep in mind that 19 you must speak into the microphone so that those in the 20 audience and the court reporter can hear your 21 testimony. The most common problem people have is just 22 forgetting to turn on their mics, there's a little 23 button there at the bottom of your mic you want to turn 24 on before you start testifying. 25 Also please remember to reference your slides Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 5 1 so that someone reading the public record can follow 2 along. For example refer to slides by the numbers if 3 numbered or by the titles if not numbered. 4 Of course the testimony today has to be 5 relevant to purposes of the hearing and if it drifts 6 off we may ask you to get back on the topic. 7 Finally testimony that's disrespectful or 8 inappropriate will not be allowed. 9 Commissioner Foerster or Seamount, do you have 10 anything to add? 11 COMMISSIONER FOERSTER: I'm not expecting to 12 see disrespect from these folks, but you never know. 13 CHAIRMAN FRENCH: Commissioner Seamount. 14 COMMISSIONER SEAMOUNT: I have nothing. 15 CHAIRMAN FRENCH: Let's go ahead and swear in 16 the witnesses now. If you -- those of you intending to 17 testify raise your right hands. 18 (Oath administered) 19 MR. VIATOR: I do. 20 MS. HOSACK: I do. 21 MR. COOKSON: I do. 22 CHAIRMAN FRENCH: Thank you. And if you'd like 23 to be recognized as an expert, when you introduce 24 yourself, you know, my name is so and so, I work for 25 this company and I'd like to be recognized as an expert Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 6 1, in and then give us the field and then we'll do a quick 2 colloquy on those credentials. 3 But whoever wants to -- oh, I'll just also add 4 that before we get too far along the Arctic Slope 5 Regional Corporation submitted a letter in support of 6 the idea this morning. It's in the record and it's 7 been distributed to the Commissioners. 8 So let's go ahead and get started. Who's going 9 to lead off? 10 MR. VIATOR: I will. 11 CHAIRMAN FRENCH: Good morning. 12 BRANDON VIATOR 13 previously sworn, called as a witness on behalf of 14 CPAI, testified as follows on: 15 DIRECT EXAMINATION 16 MR. VIATOR: Good morning. So my name is 17 Brandon Viator and I'd like to say thank you to the 18 Commissioners for the opportunity to present a summary 19 of our GMT2 measurement application this morning. 20 Slide two is a summary of the biographies of 21 myself, Ms. Hosack and Mr. Cookson. we thought we 22 would just go through this upfront and go ahead and get 23 recognized as expert witnesses so I'll start with 24 myself. 25 Brian Viator. I'm with ConocoPhillips, Alaska. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 7 1 I am the project integration manager for the Greater 2 Mooses Tooth Unit. I have a bachelor's degree in 3 chemical engineering from Texas A&M University, I'm a 4 licensed professional engineer for the state of Texas 5 as well as a project management professional. I have 6 over 17 years of industry experience both in domestic 7 and international developments covering onshore and 8 offshore and the last three years in Alaska working on 9 the western North Slope. And I'd like to be recognized 10 as an expert witness in project development. 11 CHAIRMAN FRENCH: In project development. 12 MR. VIATOR: Yep. 13 CHAIRMAN FRENCH: Very good. Maybe just tell 14 us a few of the projects you have developed? 15 MR. VIATOR: So I've been involved in our 16 Bohigh 17 Phase II development offshore China, the Australia 18 Pacific LNG project in Australia and then the Greater 19 Mooses Tooth 1 and 2 developments here in Alaska. 20 CHAIRMAN FRENCH: And the first two projects 21 you listed have -- were those completed, are they 22 online, are they up and running or what happened to 23 them? 24 MR. VIATOR: Yes, they are both completed. So 25 Bohigh Phase II was sanctioned in 2004, I spent six Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 8 1 years on that project as a process engineer and project 2 engineer, it was five offshore platforms each producing 3 about up to 80,000 barrels a day. Total production 4 from the field of almost 200,000 barrels a day. 5 Started up in 2008 and is still online today. 6 For APING that project was sanctioned I believe 7 in 2001, construction took place from 2011 to 2014. It 8 is online. I was a project engineer as well as the 9 deputy site manager on that project. I spent four and 10 a half years on APLNG. 11 CHAIRMAN FRENCH: I don't have any other 12 questions for you, Mr. Viator, maybe the other members 13 of the panel do. 14 CHAIRMAN FRENCH: You missed the only glaring 15 problem. Just kidding. 16 CHAIRMAN FRENCH: I think that -- I don't think 17 there are any objections to your being an expert in 18 project development. 19 Who wants to go next? Go ahead. 20 JODIE HOSACK 21 previously sworn, called as a witness on behalf of 22 CPAI, testified as follows on: 23 DIRECT EXAMINATION 24 MS. HOSACK: My name is Jodie Hosack, I'm the 25 instrumentation and flow measurement technical Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 9 1 authority for ConocoPhillips Alaska. I have a bachelor 2 of science in engineering science with a control 3 systems option from Montana Tech of the University of 4 Montana. I've been -- I'm a licensed electrical 5 professional engineer in the state of Alaska. I have 6 21 industry -- years of industry experience all of 7 which have been up in Alaska. So the last 10 years 8 have been with ConocoPhillips. And I'd like to be 9 considered an expert witness in instrumentation and 10 flow measurement. 11 CHAIRMAN FRENCH: Questions for Mr. Hosack? 12 COMMISSIONER SEAMOUNT: No questions, no 13 objections. 14 CHAIRMAN FRENCH: Very good. You're an expert 15 in instrumentation and flow measurement. 16 Mr. Cookson, go ahead. 17 JOHN COOKSON 18 previously sworn, called as a witness on behalf of 19 CPAI, testified as follows on: 20 DIRECT EXAMINATION 21 MR. COOKSON: Yes, my name's John Cookson. I 22 am the GMT production engineer. I have bachelor's and 23 master's degrees in petroleum..... 24 (Off record comments - microphone) 25 MR. COOKSON: I have bachelor's and master's Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 7 about his..... 8 COMMISSIONER FOERSTER: No questions. 9 CHAIRMAN FRENCH: Mr. Cookson, it looks like 10 you've also been deemed an expert in our eyes in the 11 area of production engineering. 12 Thank you. 13 MR. COOKSON: Thank you. 14 CHAIRMAN FRENCH: So go ahead, Mr. Viator, you 15 going to lead us off? 16 MR. VIATOR: Yes, sir. So first I'll just 17 start with the presentation today will be done by 18 myself and Ms. Hosack and we have John available to 19 answer questions, but he doesn't have any prepared 20 testimony today. 21 We're on slide three, a brief introduction. 22 Before we begin I guess I'd call your attention to 23 slide 19 in the back is a summary of abbreviations and 24 acronyms and I will try to define those as we go 25 through the presentation, but they're there for Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 10 1 degrees in petroleum engineering. I have a -- I'm a 2 licensed professional engineer, 32 years of industry 3 experience, 16 years in Alaska. And I'd like to be 4 accepted as an expert witness in production 5 engineering. 6 CHAIRMAN FRENCH: Questions for Mr. Cookson 7 about his..... 8 COMMISSIONER FOERSTER: No questions. 9 CHAIRMAN FRENCH: Mr. Cookson, it looks like 10 you've also been deemed an expert in our eyes in the 11 area of production engineering. 12 Thank you. 13 MR. COOKSON: Thank you. 14 CHAIRMAN FRENCH: So go ahead, Mr. Viator, you 15 going to lead us off? 16 MR. VIATOR: Yes, sir. So first I'll just 17 start with the presentation today will be done by 18 myself and Ms. Hosack and we have John available to 19 answer questions, but he doesn't have any prepared 20 testimony today. 21 We're on slide three, a brief introduction. 22 Before we begin I guess I'd call your attention to 23 slide 19 in the back is a summary of abbreviations and 24 acronyms and I will try to define those as we go 25 through the presentation, but they're there for Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 11 1 reference. 2 CHAIRMAN FRENCH: Actually very helpful. Thank 3 you. 4 MR. VIATOR: So we're here today to seek 5 approval from the AOGCC for the proposed GMT2 6 measurement system. This is the same measurement 7 system concept that was approved by the AOGCC for GMT1, 8 custody transfer measurement regulation 20 AAC 25.228, 9 and we are seeking an order under Alaska statute 10 31.05.030(c) and 20 AAC 25.505. We do have a 11 concurrent application with the BLM for the exact same 12 measurement design. 13 One of the other points I'd like to make today 14 is that the design of the GMT2 measurement system is 15 really an issue that affects the royalty interest 16 owners, having to do with the allocation factor of one 17 and how that -- the royalty will be split between CRU 18 and GMTU. 19 As you mentioned the ASRC provided a letter of 20 support today. We understand that the Department of 21 Natural Resources also provided a letter of 22 nonobjection. We've spoken to the Department of 23 Revenue as well as the BLM, expect them to provide 24 letters of support, but they were not able to get those 25 signed and submitted before the hearing. But we have Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 12 1 had those discussions and they are supportive of -- at 2 least verbally of our measurement design. 3 CHAIRMAN FRENCH: We'll hold the record open 4 awaiting those letters. 5 MR. VIATOR: Slide four, a brief agenda. So 6 we'll go through a little bit of the GMT1 measurement 7 system that was approved. I'll go through a background 8 and brief overview of GMT2. We'll touch on the 9 metering application highlights, again touch on the 10 regulations that we're dealing with today. We'll go 11 through a summary of the economic analysis and 12 discussions that we've had with the AOGCC staff and 13 then wrap things up with a status and summary. 14 Slide five, GMT1 history. So GMT1 was not an 15 economic stand-alone, an economic project with a stand - 16 alone processing facility. Our processing was planned 17 to take place at ACF which resulted in a smaller 18 footprint and made the project economic and something 19 that was able to be approved. The challenge with 20 measurement was measuring live fluids for custody 21 transfer versus measuring a dead oil. 22 With GMT1 we had a three phase production 23 separator to measure the oil and gas and water. That's 24 all measured at the GMT1 drillsite. The oil 25 measurement is done by Coriolis meters Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 13 1 with the application of a shrinkage factor and the gas 2 measurement is done by Orifice meters and there are no 3 special approvals that were required for the gas 4 measurement. 5 The allocation factor of one for GMT1 oil and 6 custody transfer meters was one of the topics that came 7 up during GMT1. We will be requesting the same thing 8 for GMT2. And then we also have gas that returns from 9 Alpine Central Facility to GMT1 where the gas is 10 measured at CD5 before severing the unit. 11 CHAIRMAN FRENCH: Mr. Viator, before we move on 12 maybe we should just talk for a minute about the 13 experience at GMT1 since this is something of a 14 parallel or a similar proposal. What are the flow 15 rates from GMT1, what have they been and what are they 16 now? 17 MR. VIATOR: So we -- GMT1 started up on 18 October the 5th and we're still going through our ramp 19 up phase. Current production is around seven to 8,000 20 barrels a day. We estimate that we will hit peak 21 somewhere between 20 and 25,000 barrels per day 22 sometime early next year. 23 CHAIRMAN FRENCH: And so far the metering 24 system seems to be working okay for all of -- almost 25 two weeks, three weeks? Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 14 1 MS. HOSACK: I can address that. We did have 2 some commissioning issues that popped up early on, one 3 of which is our water cut analyzer did not properly 4 communicate to our flow computer. We brought a 5 manufacturer representative onsite and have worked 6 through those issues and it is now functioning. We 7 didn't -- we weren't seeing any water actually in the 8 production though so while this analyzer wasn't working 9 it wasn't really making any problems or causing any 10 issues with the measurement. 11 We also did -- we did our first proving on the 12 oil line meters on the 15th. We had one of our line 13 meters, our Coriolis line meters that -- it proved out, 14 but it proved out at a higher flow rate than we 15 anticipated. We were hoping to get down to a low flow 16 rate of like about 5,000 barrels a day, but it wouldn't 17 prove any lower than about 11,000 barrels a day. So 18 but we're working through the -- working through that 19 with the manufacturer and seeing what might be going on 20 with the meter that we can't get the lower flow rates. 21 CHAIRMAN FRENCH: And I imagine your start up, 22 you begin with a fairly low water cut and you expect 23 that to climb over time? 24 MS. HOSACK: Correct. 25 CHAIRMAN FRENCH: And so your 20 to 25,000 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 15 1 figure, is that clean oil flow rates? 2 MR. VIATOR: Yes, sir, that is correct. 3 CHAIRMAN FRENCH: And as the water cut goes up 4 your flow rate will go up with that, but -- and how 5 high do you think it'll get, sort of maximum fluid out 6 of that field? 7 MR. VIATOR: So actual -- when we hit the peak 8 that will be the peak and it will decline from there. 9 So this sand is a -- it's a very good sand, but we will 10 see a decline almost immediately after we hit peak so 11 our total fluids won't go above the 20 to 25,000. 12 CHAIRMAN FRENCH: As the oil rate goes down the 13 water goes up and it all sort of holds steady at around 14 20, 25, roughly speaking? 15 MR. VIATOR: Roughly. 16 CHAIRMAN FRENCH: Yeah. I'm not going to -- 17 and we're not -- yeah, right. We're just -- we're just 18 kind of ball parking. 19 Okay. Thank you. Please proceed. 20 MR. VIATOR: Slide six. So this is a high 21 level overview of GMT2. We'll clear the map on the 22 top. Colored in blue and yellow and red are the units 23 on the North Slope that ConocoPhillips has working 24 interest in. What we're here to talk about today is 25 really the Greater Mooses Tooth Unit and the Colville Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH I8-045 Page 16 1 River Unit on the -- on the left in red. You'll see 2 the dots for GMT1 and GMT2 developments. So for GMT2, 3 this is the second development within the Greater 4 Mooses Tooth Unit. It's also the last of the original 5 Alpine satellite development plan which was originally 6 CD7. So this is the last of that plan from 2004 to 7 produce back to Alpine. 8 We are utilizing the existing Alpine 9 infrastructure as well as CD5 and GMT1 road and 10 pipeline system. We have an eight mile gravel road and 11 pipeline that connects back from GMT2 to GMT1, a 14 12 acre gravel pad that's capable of supporting up to 48 13 wells in a MWAG development that's a miscible water 14 alternating gas, it's the same system we've employed 15 throughout Alpine. We estimate to have peak North 16 Slope employment of about 700 personnel in two of our 17 three winter construction seasons. 18 You may have seen earlier this week that we -- 19 or last week that we did receive the record of decision 20 from the Corps of Engineers and the Bureau of Land 21 Management. We do expect to sanction the project in 22 the fourth quarter of this year. For GMT2, the 23 construction is actually planned to take place over 24 three construction seasons, with the first of those 25 come in early 2019 to lay gravel and do the initial Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 10 system 11 CHAIRMAN FRENCH: Just a quick question, Mr. 12 Viator. Above the ConocoPhillips box in the lower 13 right-hand corner there are two sort of brown hashmarks 14 areas, one that I suspect is Alpine and one that's 15 something else, which is which? 16 MR. VIATOR: Yeah. So just above the 17 ConocoPhillips box there's -- excuse me, there's a 18 brown line that comes down from close to CD5 all the 19 way to the..... 20 CHAIRMAN FRENCH: Right. 21 MR. VIATOR: .....kind of northeast. That's 22 the road down to Nuigsut..... 23 CHAIRMAN FRENCH: Okay. 24 MR. VIATOR: .....and the kind of boxes down 25 there is the road system in Nuiqsut. Alpine is Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 17 1 procurement. And then we'll have two more construction 2 seasons in the 2020 and 2021 seasons which start up at 3 the end of 2021 and drilling taking place in second 4 quarter of 2021. 5 Slide seven. This is another map of the 6 Colville River Unit and Greater Mooses Tooth Units and 7 this just shows the road and pipeline system throughout 8 these two units that connect back to Alpine. The green 9 is the pipeline system and the brown lines are the road 10 system 11 CHAIRMAN FRENCH: Just a quick question, Mr. 12 Viator. Above the ConocoPhillips box in the lower 13 right-hand corner there are two sort of brown hashmarks 14 areas, one that I suspect is Alpine and one that's 15 something else, which is which? 16 MR. VIATOR: Yeah. So just above the 17 ConocoPhillips box there's -- excuse me, there's a 18 brown line that comes down from close to CD5 all the 19 way to the..... 20 CHAIRMAN FRENCH: Right. 21 MR. VIATOR: .....kind of northeast. That's 22 the road down to Nuigsut..... 23 CHAIRMAN FRENCH: Okay. 24 MR. VIATOR: .....and the kind of boxes down 25 there is the road system in Nuiqsut. Alpine is Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 18 1 actually located at CD1 kind of on the upper right. 2 CHAIRMAN FRENCH: Oh, very good. Okay. So I 3 was confused. So above the sea of ConocoPhillips is 4 Nuiqsut? 5 MR. VIATOR: Yes, sir. 6 CHAIRMAN FRENCH: Okay. And Alpine is at CD1? 7 MR. VIATOR: Correct. 8 CHAIRMAN FRENCH: Thanks. 9 MR. VIATOR: Slide eight is more background on 10 GMT2. As I mentioned earlier the proposed measurement 11 design is the same as what was approved for GMT1. We 12 have a three phase production separator and the 13 associated metering to achieve a level of hydrocarbon 14 measurement accuracy for a cost that allows the GMT2 15 project to stay viable and something that the company 16 could sanction and move forward. The design allows for 17 efficient use of existing infrastructure to reduce 18 costs and limit gravel footprint as well as to reduce 19 air emissions and other environmental impacts. 20 I mentioned about previous development being 21 back through the Alpine Central Facility and this 22 design is consistent with the 2012 NPRA Integrated 23 Activity Plan, EIS, which evaluated GMT2 as a satellite 24 development relying on the Alpine Central Facility for 25 processing. And it complies with IAP stipulation E5 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch, AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH I8-045 Page 19 1 requiring sharing of facilities with existing 2 development in order to minimize footprint. 3 Slide nine. This is a similar chart to what we 4 show that GMT1, but now adding in GMT2 and is intended 5 to represent where we have measurement taking place and 6 the fluids going back and forth from GMT2 to the 7 Colville River Unit. So I'll start with the box on the 8 left which is a high level representation of the GMT2 9 development. 10 On the right side of that box you'll see meters 11 for oil, gas and water from the three phase separator. 12 Those will be recombined on pad and then sent down in a 13 single pipeline, multiphase pipeline, where it will 14 commingle with the GMT1 fluids and then go on to the 15 Colville River Unit and into Alpine. 16 Coming back from Alpine we have water and two 17 different gas lines. So the water could be seawater or 18 produced water that comes from Alpine, tees off for 19 GMT1 and then on to GMT2 which is used for our water 20 injection. We have a miscible injection gas line as 21 well as a lean gas line for fuel gas and lift gas. 22 Each of those are measured at CD5 before severing the 23 unit and then that gas goes on and splits off and some 24 of it will go to GMT1 and some of it will go on to 25 GMT2. We do have measurement of the water and fuel gas Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 20 1 and lift gas as well as the miscible injection gas at 2 the drillsite. And then on the right with the Colville 3 River Unit box you'll see the blue box inserted is 4 intended to be the Alpine Central Facility, but we have 5 our LACI measurement in the oil bubble there that goes 6 to the Transalaska Pipeline system. 7 CHAIRMAN FRENCH: And in general what's the 8 maximum capacity of Alpine, the central facility there? 9 MR. VIATOR: Well, it's really a combination of 10 your gas handling limits, your water handling limits. 11 Right now we're producing around 70,000 barrels of oil 12 per day. Total fluids -- I don't recall off the top of 13 my head. 14 CHAIRMAN FRENCH: But there's room for 20,000 15 from GMT1 and 20,000 more from GMT2? 16 MR. VIATOR: There is room to accommodate both 17 developments, yes, but it does cause some back out, 18 GMT2 does cause some back out of the CRU volumes which 19 it comes online. 20 COMMISSIONER SEAMOUNT: Does a oil water 21 contact identify Mooses -- Greater Mooses Tooth? 22 MR. VIATOR: I don't believe so. 23 COMMISSIONER SEAMOUNT: So you don't know if 24 you're going to make water, right? 25 MR. VIATOR: We'll make water when -- during Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 21 1 the waterflood. And that -- it's the same thing at 2 CRU. So most of these Alpine reservoirs do not have a 3 water leg. The water that we experience is due to the 4 waterflood. 5 COMMISSIONER SEAMOUNT: Okay. That's what I 6 sort of remember. 7 MS. HOSACK: So slide 10 is a representation of 8 the GMT2 production separator. We'll start off at the 9 top, I'll kind of walk through the equipment. Well, 10 you have the full flow, three phase production 11 separator. Off the top of the separator on the orange 12 line, that represents our gas outlet leg so we will 13 have two ADA compliant Orifice meter runs on gas and 14 each one will have a gas sampling station that's 15 capable of taking composite gas samples as well as spot 16 gas samples. The conceptual sizing for these is a six 17 inch and a 12 inch on the gas so that provides an 18 overlap on the expected gas rates that we anticipate. 19 On the green line, that's our oil outlet of our 20 separator. We have a master meter Coriolis -- Coriolis 21 master meter in series with two Coriolis line meters. 22 This are 100 percent redundant so we'd only be flowing 23 through one of the Coriolis line meters at a time. And 24 it's -- there's valving such that the master meter can 25 be lined up to the line meters for proving. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 22 1 On the downstream side of the line meters you 2 have a fast loop which has an oil composite sampling 3 station as part of the fast loop which we're using for 4 quality bank purposes so collecting samples every month 5 for quality bank. On that fast loop is also our water 6 cut analyzer. So this is a low range water cut 7 analyzer that we're using to detect how much water is 8 in our oil outlet. 9 The blue line is our water outlet of our 10 separator. The triangle represents an oil and water 11 analyzer that we're adding on the water outlet. We 12 also have -- oh, I forgot to mention, sorry, I'm going 13 to go back on the oil. The oil meters are going to be 14 a size bigger than what we used at GMT1 so they're 15 actually 10 inch oil meters rather than the eight inch 16 that we had at GMT1. 17 So back on the water leg. So the water leg -- 18 like I said we have the oil and water analyzer and it 19 also is a Coriolis meter for the water outlet for 20 measuring the water off of the separator. 21 CHAIRMAN FRENCH: Is there just one separator 22 at GMT2? 23 MS. HOSACK: For production separator, yes. 24 We'll also have a test separator in the design as well, 25 but, yes. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOOCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 15 MS. HOSACK: We anticipate it never exceeding 16 10 percent. 17 CHAIRMAN FRENCH: Ten. 18 MS. HOSACK: The analyzer's good up to 20 19 percent of water and oil. 20 CHAIRMAN FRENCH: Thank you. 21 MS. HOSACK: So as Brandon mentioned the 22 typical LACT requires stable fluids and when you end up 23 calculating standard volumes from a typical LACT unit 24 you end up applying a volume correction factor to 25 correct for the pressures and temperatures. What we're Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net Page 23 1 CHAIRMAN FRENCH: But it's not like you have a 2 primary and a secondary..... 3 MS. HOSACK: No. 4 CHAIRMAN FRENCH: .....and a Coriolis..... 5 MS. HOSACK: No. 6 CHAIRMAN FRENCH: .....like some of the 7 facilities, it's..... 8 MS. HOSACK: Just a single, correct. 9 CHAIRMAN FRENCH: .....it's a single, three 10 phase separator? 11 MS. HOSACK: Yes. 12 CHAIRMAN FRENCH: And I think you said, but 13 just remind me what you expect the water cut to be in 14 the oil meter? 15 MS. HOSACK: We anticipate it never exceeding 16 10 percent. 17 CHAIRMAN FRENCH: Ten. 18 MS. HOSACK: The analyzer's good up to 20 19 percent of water and oil. 20 CHAIRMAN FRENCH: Thank you. 21 MS. HOSACK: So as Brandon mentioned the 22 typical LACT requires stable fluids and when you end up 23 calculating standard volumes from a typical LACT unit 24 you end up applying a volume correction factor to 25 correct for the pressures and temperatures. What we're Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 24 1 proposing is an alternative to that, again it's based 2 on live fluids and we would be applying a shrinkage 3 factor based over the operating pressure and 4 temperature range of the production separator to 5 correct the observed vol -- or convert the observed 6 volumes to standard volumes in order for the -- the 7 measurement. This allows for -- it doesn't require any 8 processing in order to do this and the shrinkage 9 factor, the uncertainty that we're anticipating around 10 the shrinkage factor is approximately about 2 percent 11 which you wouldn't have in a typical LACT application. 12 So slide 12. This ends up stepping you through 13 the calculation for the volume, to get to net standard 14 volume. The Coriolis meters are actually mass meters 15 so it measures mass and the Coriolis meters measure 16 density. So the Coriolis meters will output an 17 observed volume to the flow computer. 18 The water cut analyzer is also tied into the 19 flow computer so the flow computer will subtract out 20 the water content in order to get to a net observed 21 volume. And this is where we apply our shrinkage 22 factor in order to get from a net observed volume to a 23 net standard volume, just kind of step through the 24 calculation sequence. 25 As far as for GMT2 we are planning a similar Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 25 1 operation and maintenance strategy regarding the 2 different meters. So for the Coriolis meters we are 3 planning to do monthly line meter proving against the 4 master meter. We are also going to be running smart 5 meter verification which is a diagnostics tool that the 6 vendor provides to ensure that the meter is running 7 properly. we'll be doing that monthly. And then the 8 master meter itself would be shipped out and 9 recertified at a third party flow laboratory every year 10 in order to ensure that our master meter is working. 11 On the gas measurement side we've deployed or 12 we will be deploying a continuous DP diagnostics 13 application on the Orifice plates. This will hopefully 14 give us because we haven't seen it yet, but hopefully 15 give us indication of things like bent plates, plugged 16 tubing, that type of thing, so give us some advance 17 warning that we might have the -- might have issues 18 with our gas measurement. we'll also be pulling the 19 Orifice plates monthly for inspection and we'll be 20 doing an annual meter tube inspection with a borescope 21 in order to make sure the meter tube is in good shape. 22 For the pressure, temperature and water cut 23 transmitters we are going to be doing monthly oil or 24 quarterly gas transmitter verifications unless we look 25 to deploy redundancy verification. what redundancy Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 26 1 verification is is we essentially have two redundant 2 transmitters, two pressure transmitters, two 3 temperature transmitters, and we continually compare 4 them to make sure that you're not drifting. And that 5 would help us to extend our maintenance frequency on 6 those transmitters. 7 We will also be doing monthly water cut 8 calibrations where we take samples every month and 9 compare the lab analysis of those samples to the 10 readings of the water cut analyzer to make sure that 11 the water cut is operating properly. 12 Slide number 14. On the sampling you have -- 13 as I mentioned before on the oil sampling the fast loop 14 with a flow proportional composite sampling system. 15 This is connected to be lined up with either meter run 16 again with only one meter run functioning online at a 17 time. These monthly samples are used by our quality 18 bank and they get sent off to a laboratory in Houston 19 as part of the quality bank process. 20 The gas sampling as I mentioned again we have 21 gas sampling stations at each of the Orifice meter 22 runs, they're set up for either composite sampling or 23 spot sampling. We'd be taking monthly collection of 24 samples for composition and BTU analysis. 25 MR. VIATOR: Slide number 15. Just a Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email• sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 27 1 restatement of the regulations that we're discussing 2 today so 20 AAC 25.228. We are seeking an order under 3 Alaska statute 31 05.030(c) and 20 AAC 25.505 that is 4 approving the proposed GMT2 custody transfer 5 measurement methodology. The -- what we are not able 6 to meet under 25.228 is really the references to the 7 API regs around LACT measurement and the application of 8 the calculations that are having to do with the volume 9 correction factor and we're needing to use the 10 shrinkage factor. 11 We are not requesting specific equipment 12 approvals at this time so the requirements of guidance 13 bulletin 13002 will be submitted at a later date since 14 that requires a bunch of detailed manufacturing 15 information. And we expect to do so similar like we 16 did to GMT1, most likely the year before start up we 17 would submit our application to allow adequate time to 18 get that approval. 19 slide 16. This is one of the attachments that 20 we included in our application that shows the summary 21 of the economic analysis for a production facility. 22 What's shown here is representation of net present 23 value on a percentage basis with the far left being our 24 current value and the far right being what that value 25 would be should we be required to put in a processing Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile(c�gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 28 1 facility. The first step in that is we would have to 2 take a step back and there would be approximately a 3 four year delay to redo the engineering as well as redo 4 all of our permitting. And then you'd have the 5 facility cost. We estimate that to be somewhere 6 between seven and $900 million, approximately 800 7 million in capital as well as another $40 million in 8 operating cost per year as well as the delay in 9 production of that -- of the four year delay that would 10 get you somewhere in the range of possible outcomes of 11 being roughly 10 percent of current value to somewhat 12 less than -- below zero of an outcome. 13 The other thing I would mention that, you know, 14 that -- you know, what is economic. It's more than 15 just MPV, it's also rate of return as well as cost of 16 supply which is a more recent kind of measure that's 17 been used in the last several years. Typical rate of 18 returns for industry are somewhere between 10 and 20 19 percent. For cost supply ConocoPhillips has been on 20 record in recent months stating that for projects to 21 qualify funding within our company it needs to meet a 22 $40 or better cost of supply. So for reference..... 23 CHAIRMAN FRENCH: Meaning price of a barrel of 24 oil? 25 MR. VIATOR: Yes. Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.nel AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 291 1 CHAIRMAN FRENCH: Is that net back at -- 2 exclusive of transportation costs or is that at the 3 wellhead? 4 MR. VIATOR: That's basically, you know, kind 5 of net to us so it's after taxes and transportation and 6 all that. 7 CHAIRMAN FRENCH: Net. Thanks. 8 COMMISSIONER FOERSTER: So is it safe to say 9 that if you were required to put in full facilities 10 this project might not make ConocoPhillips' list of 11 projects that they would do? 12 MR. VIATOR: That is safe. It would not meet 13 the hurdle. The -- the far right for reference is kind 14 of a range between about a $60 and $50 cost of supply. 15 So having to put in a facility would move this into the 16 bottom 10 percent of projects in our current portfolio 17 and would not compete for capital. 18 COMMISSIONER FOERSTER: Okay. So in other 19 words in asking us to accept a lower level of accuracy 20 in metering we're getting say 95 percent of something 21 rather than 99.9 percent of nothing? 22 MR. VIATOR: Yes, ma'am. 23 COMMISSIONER FOERSTER: Okay. 24 COMMISSIONER SEAMOUNT: What are these 25 estimates, are these estimates based on what you've Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 1 seen at CD1 partly? 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 301 2 MR. VIATOR: Partly. We actually had a third 3 party produce a cost estimate so -- Turner and 4 Townsend, and that's something that we did review with 5 AOGCC staff and went through that detailed estimate on 6 how we came up with the cost. But it -- they do a lot 7 of our cost estimating on the North Slope so it does 8 have some built in. CD5/GMT1 was calibrated to current 9 GMT1 actuals that they were seeing at the time so it is 10 a -- was a relatively current based capital estimate. 11 COMMISSIONER SEAMOUNT: Okay. Thank you. 12 CHAIRMAN FRENCH: And all the information was 13 information that was presented inside sort of the -- 14 we'll just call it the confidential room to our senior 15 reservoir engineer? 16 MR. VIATOR: Yes. 17 CHAIRMAN FRENCH: And were you present during 18 that review, I mean, did you attend that meeting? 19 MR. VIATOR: Yes, I did. 20 CHAIRMAN FRENCH: Thank you. And just while 21 we're on this slide, I mean, I -- Commissioner 22 Foerster, I think, you know, summed it up real nicely, 23 but just to walk through each piece. The 100 percent 24 bar represents the project without a stand-alone, you 25 know, three phase, you know, or a typical LACT sort of Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 1 process? 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 31 2 MR. VIATOR: Yes, sir, that's..... 3 CHAIRMAN FRENCH: And you remove 35 percent of 4 that net present value through the four year delay, you 5 remove another 40 percent of the value through the 6 facility cost and then you lose another 15 percent of 7 the value through the operating cost? 8 MR. VIATOR: Yes, sir. 9 CHAIRMAN FRENCH: That's how you back down to 10 -- you wind up with 10 percent of the net present 11 value. So just to plug in some completely random 12 numbers because I didn't attend the meeting, if the 13 project is worth a billion dollars on the left-hand 14 side when you get all done backing out all the other 15 costs you're left with $100 million? 16 MR. VIATOR: Yes, sir, that's what that would 17 mean. 18 CHAIRMAN FRENCH: That's how it -- okay. 19 Thanks. 20 MR. VIATOR: Slide 17 is the last slide that we 21 have to present and it's just the status and summary. 22 So ConocoPhillips has applied for -- to AOGCC and the 23 BLM for the GMT2 measurement system. We are requesting 24 approval of our measurement system design to measure 25 live fluids with the application of a shrinkage factor Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH I8-045 Page 32 1 as well as the allocation factor of one for the GMT2 2 custody transfer meters. We are currently completing 3 detailed engineering. I mentioned that we did receive 4 our record of decision from the Corps and BLM last week 5 and are hopeful to receive funding this quarter from 6 the company to move forward with construction this 7 coming winter season. 8 That is all we have prepared to provide today. 9 CHAIRMAN FRENCH: Questions or comments? 10 COMMISSIONER FOERSTER: I want to thank you for 11 anticipating all the relevant questions and providing 12 the information. 13 CHAIRMAN FRENCH: Commissioner Seamount. 14 COMMISSIONER SEAMOUNT: I have no questions. 15 Thank you 16 CHAIRMAN FRENCH: I have a couple concerns I'll 17 put on the record, but they're -- and just so 18 everyone's clear I'm just speaking purely for myself. 19 This is the second project we're being asked to 20 approve, you know, with the same kind of idea and I 21 think it speaks highly of the goodwill and good 22 reputation your corporation has that we're taking this 23 step, you know, we -- at some level we trust you. On 24 the other hand the decision requires us to sort of take 25 two big factors into account. One, sort of the Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: sahile@gci.net AOGCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 33 1 technical side of the metering which we're expert at 2 and you're expert at, the other side is the economic 3 analysis which I don't think anyone would say that 4 we're expert at. We're -- you know, we're smart enough 5 and we can sort of figure out things, but at some level 6 we're in the dark about that and the public's in the 7 dark. We've assigned that analysis to one of our 8 senior reservoir engineers and we trust that person and 9 we're going to make a decision based on that. 10 And I'll just say, you know, this is now number 11 2, maybe there's going to be 20 more of these little 12 pearls strung across NPRA and I hope there are, you 13 know, all making 20 to 30,000 barrels a day, but at 14 some point we're going to be confronted with a very 15 difficult question about how accurately we're measuring 16 all this consistent with the standards that we have 17 imposed on others in other places. Clearly any oil 18 development is more economic if you don't have three 19 big hunking separators sitting there and sitting there 20 to get down to, you know, a .05 water cut. So we are 21 setting a precedent. And it may be that other 22 companies have different hurdle rates and different 23 economic analyses that -- you know, I'm not sure if we 24 -- you know, if a privately held company comes to us 25 and asks for this same dispensation they may have a Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Arch. AK99501 Fax: 907-243-1473 Email: sahile@gci.net AOOCC 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 34 1 hurdle rate that's so far different from yours that 2 we're now at apples and oranges. And so at some point 3 we may have to come back and -- I'm not sure who we 4 would go to for guidance about, you know, what's a 5 reasonable rate of return for an investment on the 6 North Slope. I'm not sure this confronts us with that 7 because I think the difference is so stark in your 8 analysis that -- and we're not at that -- we're not at 9 that point, but I just wanted to put those concerns on 10 the record. 11 Thank you. 12 Anybody else, anybody provoked -- did I provoke 13 any responses or comments or feedback? 14 (No comments) 15 CHAIRMAN FRENCH: Hearing and seeing none we're 16 going to go ahead and adjourn at 10:40. Thanks so 17 much. 18 (Hearing adjourned) 19 (END OF PROCEEDINGS) 20 21 22 23 24 25 Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email• sahile@gci.net AOGCC 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 10/23/2018 ITMO: REQUEST BY CONOCO PHILLIPS AK, INC., Docket No. OTH 18-045 Page 351 TRANSCRIBER'S CERTIFICATE I, Salena A. Hile, hereby certify that the foregoing pages numbered 02 through 35 are a true, accurate, and complete transcript of proceedings in Docket No.: OTH 18-045, transcribed under my direction from a copy of an electronic sound recording to the best of our knowledge and ability. DATE SALENA A. HILE, (Transcriber) Computer Matrix, LLC Phone: 907-243-0668 135 Christensen Dr., Ste. 2., Anch. AK 99501 Fax: 907-243-1473 Email: mhile@gci.net STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Docket Number: OTH-18-045 October 23, 2018 at 10:00 am NAME AFFILIATION Testify (yes or no) �e t1oS&C�, cop�k j%t=s r -,h r I S I-ya' L l e GiC G A/ o �vh v 00A49A0C#- ZL M ;00 ConocoPhillips GMT2 Measurement Application AOGCC Hearing October 23, 2018 Mr. Brandon Viator • ConocoPhillips, Alaska, Inc • Project Integration Manager - GMTU • BS Chemical Engineering, Texas A&M University • Licensed Professional Engineer, Texas • 17 years industry experience, domestic and international developments covering both onshore and offshore, 3 years in Alaska working Western North Slope • Expert Witness: Project Development Mr. John Cookson • ConocoPhillips, Alaska, Inc • Production Engineer • BS and MS Petroleum Engineering, Colorado School of Mines • Licensed Professional Engineer, Texas • 32 years industry experience, 16 years in Alaska working Kuparuk, Prudhoe, Point Thomson and Alpine fields • Expert Witness: Production Engineering Mrs. Jodie Hosack • ConocoPhillips, Alaska, Inc • Instrumental and Flow Measurement Technical Authority • BS Engineering Science — Montana Tech • Licensed Professional Engineer, Alaska • 21 years industry experience, 10 years with ConocoPhillips in Alaska • Expert Witness: Instrumentation and Flow Measurement ConocoPhillips e ConocoPhillips seeks AOGCC approval For the proposed GMT2 measurement system Same measurement system approved for GMT1 Custody transfer measurement regulation: 20 AAC 25.228 We are seeking an order under AS 31.05.030(c); 20 AAC 25.505 Concurrent application pending before BLM Presenters Brandon Viator, Project Integration Manager Jodie Hosack, Staff Instrumentation Engineer John Cookson, Staff Petroleum Engineer conocophillips A Review Measurement System approved for GMT1 Background / Overview Metering Application Highlights Regulations Economic Analysis Status & Summary ConocoPhillips • GMT1 was not economic with a stand-alone processing facility • Processing at ACF resulted in a smaller footprint and made project economic • Challenge was measurement of live fluids for custody transfer • Oil and gas measurement occurs after three phase separation, but prior to oil stabilization • Oil measurement by Coriolis meter system with shrinkage factor • Gas measurement by Orifice meter; no special approvals required • Allocation factor of 1 for GMT1 oil and gas custody transfer meters • Gas returning to GMT1 is measured at CD5 ConocoPhillips Beaufort Sea Kuparuk NPR -A ED MeRiver Prudhoe '" River Bay Bear oth Greater ft Mo,7ses ,, L Tooth _ i • Second development in Greater Mooses Tooth Unit • Utilizes Alpine infrastructure & CD5/GMT1 designs • 8 -mile gravel road and pipelines • 14 -acre gravel pad • Up to 48 horizontal well MWAG development Estimated peak NS employment: —700 positions • Key Permits Received: October 2018 • CPAI Project Sanction: 4Q2018 11t Construction Season: 4Q2018 - 2Q2019 211 Construction Season: 4Q2019 - 2Q2020 3'6 Construction Season: 4Q2020 - 4Q2021 Start Drilling: 2Q 2021 First Oil: December 2021 ConocoPhillips Pipeline O uu OAK Unit N A T I O N A L P E T R O L E U M R E S E R V E . A L A S K A • f GMT2 I L CD3 a i Colville ' CD2 River Unit ! CD1 CD5 ,• • CD4 . T .I. Nr Greater Mooses Tooth Unit ConocoPhillips Alaska Greater Mooses Tooth Unit N and Colville River Unit o Roads, Pads, & Pipelines i i mmmmm[ZZ= Mlles A 3/2012018 ConocoPhillips • The proposed measurement design is the same that was approved for GMT1 The 3-phase production separator and associated metering achieve a high level of hydrocarbon measurement accuracy (2.03% uncertainty in oil stream) for a cost that allows the GMT2 project to remain viable The GMT2 design allows for efficient use of the existing infrastructure to reduce costs and limit gravel footprint, air emissions and other environmental impacts The proposed design is consistent with the 2012 NPR -A Integrated Activity Plan (IAP) EIS, which evaluated GMT2 as a satellite development that relies on Alpine Central Facility (ACF) for processing, and it complies with the IAP stipulation E-5, which requires sharing facilities with existing developments in order to minimize project footprint ConocoPhillips Greater Mooses Tooth #2 (GMT2) Colville River Unit (CRU) • Oil, Gas and Water are measured at the GMT2 3 -Phase Separator, recombined and sent to Alpine Central Facility (ACF) at CRU for processing along with GMT1 production Gas (Lift Gas + Fuel Gas and Miscible Injection Gas) and Injection Water sent to GMT2 from CRU • Gas streams measured at CD5 • Water measured at the wellhead at GMT2 LEGEND Ane line OMeasurement MI — Miscible Injection gas LG — Lift Gas FG — Fuel Gas ConocoPhillips EI E]Phase Dynamics Water Cut meter Line List: E2 10 ® Coriolis Meter Orange: Gas O Green: Oil+water Orifice Plate Meter Blue: Separated water OGas sample station Black: Oil+water+gas QOil in Water Analyzer Production to GMTl/ACF Conocol"hillips LACT quality metering design requirements LACT metering is achieved by measuring stable fluids and converting from an observed volume to a standard volume through the application of a Volume Correction Factor (VCF) A processing facility is required to produce streams with stable fluids • Proposed alternative to LACT The proposed alternative to LACT metering is to measure live fluids and convert observed volumes to standard volumes through the application of a Shrinkage Factor (SF) developed across a range of operating pressures and temperatures No processing facility is required The use of a SF applied to live fluids measurement has an uncertainty of -2% ConocoPhillips Mass Output J7 Observed Volume 'L - \f Net Observed Volume Net Standard Volume Observed Density Measured by the Flow Meter Water Content Determined by the Phase Dynamics Unit Volumetric Correction — Either VCF or SF b ConocoPhillips • The proposed measurement system, along with robust operation and maintenance plans provide for a reliable system that all royalty owners have accepted Oil Measurement - Coriolis Meters Monthly line meter proving against the master meter A Monthly meter verification checks using Smart Meter Verification Annual calibration of the master meter at off-site testing facility • Gas Measurement - Differential Pressure Orifice Gas Meters Continuous DP Diagnostics system Monthly orifice plate and annual meter tube boroscope inspection • Watercut Analyzer and Secondary Instruments Monthly oil and quarterly gas secondary instrument verifications, unless redundancy verification applied Monthly watercut verification against spot sample lab results ConocoPhillips ^ Oil Sampling Fast -loop flow proportional composite sampling system configured to be connected to both meter runs, with only the in service meter run open to the sampling system Monthly sample for quality bank analysis Gas Sampling Flow proportional composite sampling stations at each regulatory gas meter Monthly collection for compositional and BTU analyses ConocoPhillips • 20 AAC 25.228 • Seeking an order under AS 31.05.030(c); 20 AAC 25.505 approving the proposed GMT2 custody transfer measurement system methodology Same methodology approved for GMT1 Not requesting specific equipment approvals at this time Custody Transfer Meter Application per AOGCC Industry Guidance Bulleting 13- 002 will be submitted at a later date after the engineering and procurement phases of the project are completed ConocoPhillips 120% 100% 80% 60% 40% a Z 20% 0% • , Range of Possible -20% Outcomes -40% Current Value Four Year Delay Facility Cost Operating Cost Revised Value (No PF) (PF) • Production Facility impacts (besides potential for negative NPV) would move GMT2 project to the bottom 10% of projects in COP's global portfolio and thus not compete for capital • Production Facility adds -$800 MM in capital, -$40 MM /year in annual expense, and will delay production at least four years to achieve LACT quality measurement = ConocoPhillips CPAI has applied for AOGCC and BLM approval of the GMT2 measurement system • CPAI requests AOGCC approval of the GMT2 Measurement System Measurement of live fluids Custody transfer oil measurement by Coriolis meters with shrinkage factor applied Allocation factor of 1 for the GMT2 custody transfer meters • The GMT2 project is completing detailed engineering Need approval of measurement system to initiate the procurement process for measurement equipment ConocoPhillips Back -Up ConocoPhillips • 2Q Second Quarter MI Miscible Injection • 4Q Fourth Quarter MM Million • AAC Alaska Administrative Code MPMS Manual of Petroleum Measurement Std. • ACF Alpine Central Facility MWAG Miscible Water Alternating Gas • AGA American Gas Association NPRA National Petroleum Reserve -Alaska • AOGCC Alaska Oil & Gas Conservation Commission NS North Slope • API American Petroleum Institute • PA Participating Area • ASK Artic Slope Regional Corporation • PF Production Facility • BLM Bureau of Land Management PFD Process Flow Diagram • BTU British Thermal Unit PVT Pressure, Volume & Temperature • CD1 Colville River Delta - 1 • SF Shrinkage Factor • CPAI ConocoPhillips Alaska, Inc. • VCF Volume Correction Factor • CRU Colville River Unit • EIS Environmental Impact Statement • FG Fuel Gas • GMTU Greater Mooses Tooth Unit Participating Area • GMT1 Greater Mooses Tooth #1 CD 1 Alpine Reference • H2O Water CD 2 Alpine, Qannik information for • IAP Integrated Activity Plan CD 3 Fiord-Kuparuk meet (FK), Fiord-Nechelik (FN) AlG: ACCFF SiSmple • LACT Lease Automatic Custody Transfer CD4 Nanuq, Nanuq-Kuparuk (NK), Alpine Process Flow • LG Lift Gas CD Nanuq-Kuparuk (NK), Alpine Diagram GMT 1 Lookout ConocoPhillips E PSdgNT OF 19 � 9 � O 44 CN 31 In Reply Refer To: 2361(AK930) United States Department of the Interior BUREAU OF LAND MANAGEMENT Alaska State Office 222 West Seventh Avenue, #13 Anchorage, Alaska 99513-7504 www.blm.jzov/a1aska Mr. Hollis French Chair, Commissioner Alaska Oil and Gas IConservation Commission 333 West Seventh Avenue Anchorage, AK 99501-3572 Dear Commissioner French: OCT 25 2018 29 The Alaska Oil and Gas Conservation Commission conducted a hearing on October 23, 2018, to discuss Greater Mouses Tooth 2 (GMT 2) measurement. The hearing included discussion about using an allocation factor of 1.0 for the future development of GMT 2. The BLM supports the use of the 1.0 allocation factor, as it meets the federal requirements in 43 CFR 3162.7-2, and the requirements under BLM 43 CFR 3170 regulations. If further discussion is warranted, please contact Wayne Svejnoha, Supervisory Minerals and Energy Specialist, at wsvejnoh@blm.gov or 907-271-4407. Sincerely, Ted A. Murphy Acting State Director cc: Brandon Viator, ConocoPhillips Alaska October 22, 2018 THE STATE 01ALASKA GOVERNOR BILL WALKER ConocoPhillips Alaska, Inc. 700 G Street Anchorage, AK 99501 Attn: Marie P. Evans Department of Revenue "I AX DIVISION State Office Building 333 Willoughby Avenue, I la Floor PO Box 110420 .Juneau. Alaska 99811-0420 Main: 907.465.2320 Fax: 907.465.2375 Re: AOGCC Docket Number OTH-18-045 Waiver of Requirements for 20 AAC 25.228(a) at GMT2 Dear Ms. Evans, ConocoPhillips Alaska, Inc. (CPAI) has asked that the Department of Revenue (department) agree, or supply a letter of non -opposition, to CPAI's request before the Alaska Oil and Gas Conservation Commission (AOGCC) as described in AOGCC's public notice referencing Docket Number OTH-18-045, "Waiver of the Requirements of 20 AAC 25.228(a) to Provide Custody Transfer Measurement of Hydrocarbons Prior to severance from the Lease or Unit" ("Waiver"), The Waiver would allow for final custody transfer metering and fiscal allocation of production from the Greater Moose's Tooth Unit, GMT2 development, to occur off unit and to be based on a metering system that does not meet custody transfer quality standards. The Waiver, by its terms, would also include approval of a meter allocation factor for the GMT2 development metering system of 1.0, the same as for GMT1. The department hereby agrees to the conceptual design of the metering system as described in the Waiver subject to the following conditions: (1) that any installed metering system and allocation methodology is consistent with AOGCC's letter dated August 30, 2018, "Revised Approval Custody Transfer Measurement Greater Moose's Tooth Unit GMT1," Docket Number OTH-17-033, and (2) since it appears that the final design and equipment to be used by CPAI at the GMT2 development may not be known until 2020 when ConocoPhillips submits their official GMT2 measurement application (in accordance with AOGCC Guidance Bulletin 13-002), the department should also have a chance to review the final application if there are any differences between the equipment or procedures as contemplated in AOGCC's August 30, 2018 letter for GMT1, Docket Number OTH-17-033. The point of production for the GMT2 development will be the lease automatic custody transfer (LACT) meter at the entrance to the Alpine Pipeline, the same as for GMT1. Notwithstanding the department's agreement to the terms of the Waiver the department desires to preserve for the record that the allocation factor of 1.0 for oil and gas produced at GMT2 could result in less taxable revenues to the state: As oil produced from state leases and processed at the Alpine Production Center will be deemed to have been produced from federal leases within the GMT2 development in order to make up for any processing use and line loss that would otherwise be attributable to GMT2 . Additionally, any such reduction would shift production from state leases at Alpine paying the full oil and gas production tax, to federal and private leases at GMT2 paying, for the first three to seven years, taxes reduced due to the Gross Value Reduction under AS 43.55.160(f)(1). In contrast to the above, we further understand that, should there be metering error that understates the volumes leaving GMT2 the state could potentially see additional revenues as those volumes would effectively be applied to Alpine production. If there are any questions, please let me know. Thank you. Anchorage Office • 3900 C Street, Suite 801 • Anchorage, Alaska 99503-5963 • 907.339.6000 • FAX 907.339.6028 • 1.800.770.2772 q® ?ai�,5 al corporation October 23, ?QW Commissioners Foerster, Seamount and French Alaska Oil and Gas Conservation Commission j 7 3 2r;8 333 W. 7th Avenue Anchorage, Alaska 99501b"` 4 r - RE: Docket OTH-18-045 ASRC Comments to AOGCC Regarding the Allocation Factor at Greater Moose's Tooth #2 Dear Commissioners: Arctic Slope Regional Corporation (ASRC) urges AOGCC to approve ConocoPhillips Alaska, Inc. (COP) proposed hydrocarbon and production measurement and allocation system for Greater Mooses Tooth #2 (GMT2) from the second drillsite within the Greater Mooses Tooth Unit (GMTU), located in the National Petroleum Reserve - Alaska (NPRA). ASRC is a mineral owner in the Greater Mooses Tooth 2 (GMT2) development, and has considerable economic interest in the GMT2 development. ASRC is also a co -manager, with the Bureau of Land Management and therefore has standing with respect to decisions regarding production measurements and allocations methodologies utilized at GMT2. ASRC's reasons to justify approval for the allocation factor are as follows: In the past, ASRC has been actively involved in technical discussions to meet the BLM metering requirements for GMT1. ASRC has continued to participate in such technical discussions pertaining to GMT2 and feels that COP has adequately presented its justification and methodology to BLM. To optimize economic recovery, Greater Mooses Tooth Unit (GMTU) is designed as a satellite drillsite that will be produced through the Colville River Unit (CRU) Alpine Central Facility (ACF). Similar to GMT 1 fluids produced at GMT2 will be measured through a 3-phase production separator that will allow for continuous measurement using a Coriolis meter and water cut analyzer. After separation, fluids will be recombined and delivered to the ACF through a three phase pipeline system from GMT2 to the CD5 drill site in the CRU. ASRC understands that the proposed production allocation system proposed by COP is different from what we are accustomed to in the CRU. As a mineral owner and Unit manager in the adjacent CRU, ASRC is intimately familiar with the CRU allocation methodology and has been party to multiple redeterminations of production and allocation in the CRU since its start-up in 2000. We are also comfortable with the high-pressure separator and continuous metering approach proposed for GMT2. With recombination of GMT2 fluids prior to reaching the ACF, the GMT2 fluids will have an effective allocation factor of 1.0 at the CRU LACT meter. As such: Corporate Headquarters • PO Box 129 • Barrow, Alaska 99723-0129 • 907.852.8533 or 907.852.8633 • FAX 907.852.5733 • Production measurements for CRU wells are much less accurate as they are based on monthly well tests to allocate the Alpine Central Facility LACT meter volumes back to individual wells. • The designed oil measurement system meets both AOGCC standards for the CRU, a State and ASRC jointly managed unit, and BLM standards for the GMTU, a federal and ASRC jointly managed unit, without economic waste. • ASRC feels that any effect on State royalty through the CRU allocation methodology will be minimal and will be offset by the benefit of having more gas delivery to the CRU from GMT2 for enhanced oil recovery efficiency. • ASRC is a mineral owner in both CRU and GMTU. As such ASRC currently receives royalty from production in the CRU and will receive royalty from GMT2. The State of Alaska currently receives royalty from production from the CRU and is entitled to receive 50% of the federal royalty from GMT2. ASRC feels that COP has a metering design that protects all royalty interests in both units. Thank you for your time and attention. Ve�ryy Truly Yours, � Teresa Imm Executive Vice President, Regional & Resource Development CC: Brandon Viator, ConocoPhillips Alaska Inc. Kevin Pike, Alaska Division of Oil and Gas Wayne Svejnoha, Bureau of Land Management 2 ME STATE °'ALASKA GOVERNOR BILL WALKER October 12, 2018 Commissioner Hollis French, Chair Alaska Oil and Gas Conservation Commission 333 W. 7' Avenue Anchorage, AK 99501 Re: Greater Mooses Tooth #2 Measurement Application Dear Commissioner French: Department of Natural Resources DIVISION OF OIL & GAS 550 W 7^' Avenue, Suite 1100 Anchorage, AK 99501-3560 Main: 907.269.8800 Fax: 907.269.8939 CERTIFIED MAIL RETURN SERVICE REQUESTED ConocoPhillips Alaska, Inc. (CPAI) has provided the State of Alaska, Department of Natural Resources, Division of Oil and Gas (Division) a copy of the application to the Alaska Oil and Gas Conservation Commission (AOGCC) for GMT2 Measurement Approval dated July 12. 2018. The Division considers the metering tools and procedures proposed by CPAI to the AOGCC to be sufficient to accurately differentiate between production originating from GMT2 and production originating from the Colville River Unit for royalty accounting and reservoir surveillance purposes. Accordingly, the Division does not object CPAI's proposed metering system. Sincerely, P Chantal Walsh Director Division of Oil and Gas Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: OTH-18-045 The application of ConocoPhillips Alaska Inc. (CPAI) for a Waiver of the Requirements of 20 AAC 25.228(a) to Provide Custody Transfer Measurement of Hydrocarbons Prior to severance from the Lease or Unit. CPAI, by letter dated July 12, 2018, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue a waiver from the requirements of 20 AAC 25.228(a) to allow for final custody transfer metering of hydrocarbons sold from the Greater Moose's Tooth Unit (GMTU), GMT2 development to occur off unit and to approve the conceptual design of the metering system that will provide fiscal allocation to the GMT2 development. The AOGCC has tentatively scheduled a public hearing on this application for October 23, 2018 at 10:00 a.m. at 333 West 7a Avenue, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on September 4, 2018. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 279-1433 after September 7, 2018. In addition, written comments regarding this application may be submitted to the AOGCC at 333 West 7' Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on September 20, 2018, except that, if a hearing is held, comments must be received no later than the conclusion of the October 23, 2018, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC at (907) 279-1433, no later than October 16, 2018. ri_'i' Hollis French Chair, Commissioner Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: OTH-18-045 The application of ConocoPhillips Alaska Inc. (CPAI) for a Waiver of the Requirements of 20 AAC 25.228(a) to Provide Custody Transfer Measurement of Hydrocarbons Prior to severance from the Lease or Unit. CPAI, by letter dated July 12, 2018, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue a waiver from the requirements of 20 AAC 25.228(a) to allow for final custody transfer metering of hydrocarbons sold from the Greater Moose's Tooth Unit (GMTU), GMT2 development to occur off unit and to approve the conceptual design of the metering system that will provide fiscal allocation to the GMT2 development. The AOGCC has tentatively scheduled a public hearing on this application for October 23, 2018 at 10:00 a.m. at 333 West 7' Avenue, Anchorage, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 p.m. on September 4, 2018. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call (907) 279-1433 after September 7, 2018. In addition, written comments regarding this application may be submitted to the AOGCC at 333 West 7`^ Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on September 20, 2018, except that, if a hearing is held, comments must be received no later than the conclusion of the October 23, 2018, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC at (907) 279-1433, no later than October 16, 2018. //signature on file// Hollis French Chair, Commissioner STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OFPUBLICATWN WON ATTACHED COPY OFADVERTISMENT. ADVERTISING ORDERNUIvIDER L AO -19-006 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O.AGENCY 8/14/2018 PHONE: (907) 279-1433 333 West 7th Avenue Anchorage, Alaska 99501 DATES ADVERTISEMENT REQUIRED: COMPANY CONTACT NAME: PHONE NUMBER: ASAP FAX NUMBER: (907)276-7542 TO PUBLISHER: Anchorage Daily News, LLC SPECIAL INSTRUCTIONS: PO Box 140147 Anchorage, Alaska 99514-0174 TYPE OF ADVERTISEMENT; LEGAL DISPLAY a CLASSIFIED OTHER (Specify below) DESCRIPTION PRICE OTH-18-045 Initials of who prepared AO: Alaska Non -Taxable 92-600185 9UBMITINV.OYt4: SHOWINGADVERTISIN6' .. ORDER.NO.; CERTIFIED AYnDAYFrOF : : ....LICA. _ _ .............COPY .. ruscme[�DNmTx:ATrncxm cors oF. 'ADVERFI8M6NF:T0� AOGCC 333 West 7th Avenue Anchorage, Alaska 99501 Pae I of I Total of All Pages S - REF Type Number Amount Date Camueut 1 PvN VCO21795 2 AO AO -19-006 3 4 FUN AMOUNT SY Act Template I PGM LGR Object FY DIST LIQ l 19 A14100 3046 19 2 5 Pur Na Title: Purchasing Authority's Signature Telephone Number APO receoang agent ust appear on all invoices and documents relating to this purchase . The state is registered for tax free transactions under Chapter 32, IRS code. Registration number 92-73-0006 K. Items are for the exclusive use ofthe state and not for sale. —. DIS f...... ION, llmslonfiscal/Ori'glnal,Ab Copies' Ptitihsha(fsxedj,U.vis.Ion:I'S.ii ReceAft Form: 02-901 Revised: 8/14/2018 Bernie Karl K&K Recycling Inc. P.O. Box 58055 Fairbanks, AK 99711 George Vaught, Jr. P.O. Box 13557 Denver, CO 80201-3557 Gordon Severson 3201 Westmar Cir. Anchorage, AK 99508-4336 Darwin Waldsmith P.O. Box 39309 Ninilchik, AK 99639 Penny Vadla 399 W. Riverview Ave. Soldotna, AK 99669-7714 Richard Wagner P.O. Box 60868 Fairbanks, AK 99706 RECEIVED ANCHORAGE DAILY NEWS AUG 2 3 2018 AFFIDAVIT OF PUBLICATION AOGCC Account C: 270227 ST OF AK/AK OILAND GAS Order' 0001426290 Cost $279.12 CONSERVATION COMMISSION 333 WEST 7TH AVE STE 100 nnirunannc nvoounuvo STATE OF ALASKA THIRD JUDICIAL DISTRICT Joleesa Stepetin being first duly swom on oath deposes and says that he/she is a 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 15, 2018 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. . ri =d a5111CF 411MNlIIFAMLTM Subscribed and swom to before me this 15th day of August, 2018 `'Notary Pu lic n and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSIQIVtEXPIF�S w)I��71��LJ ;D,,; k ORII NEY L. iFs'Ka N State of Flataska My Commission cxphes Feb 23, 2019 Product ADN -Anchorage Daily News Placement 0300 Position 0301 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket Number: OTH-18-045 The application of ConocoPhillips Alaska Inc. (CPAO for a Waiver of the Requirements of 20 AAC 25.228(a) to Provide Custody Transfer Measurement of Hydrocarbons Prior t0 Severance from the Lease or Unit. - CPAL.by letter dated July 12, 2018, requests the Alaska Oil and Gas Conservation Commission (AOGCC) issue a waiver from the requirements of 20 AAC 25.228(a) to allow for final custody transfer metering of hydrocarbons sold from the Greater Moose's Tooth Unit (GMTV), GMT2 development to occur Off unit and to approve the conceptual design of the metering system that will provide fiscal allocation to the GMT2 development. The AOGCC has tentatively Scheduled a public hearing on this application for October 23, 2018 at 10:00 a.m, at 333 West 7th Avenue, Anchors a, Alaska 99501. To request that the tentatively scheduled hearing be held, a written request must be filed with the AOGCC no later than 4:30 P.M. on September 4, 2018. If a request for a hearing is not timely filed, the AOGCC may consider the issuance of an,order Without a hearing. To learn if the AOGCC will hold the 'heal'ing, call (907) 279-1433 after September 7, 2018. In addition, written comments regarding this application may be Submitted t0 the AOGCC at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on September 20, 2018, except that, if a hearing is held, comments must be received no later than the conclusion of the October 23, 2018, hearing. If, because of a disability, special accommodations may be needed to comment or attend the hearing, contact the AOGCC at (907) 279-1433, no later than October 16, 2018. //S nature on file// ' Hollis French Chair, Commissioner Published: August 15, 2018 2 Data Room Access and Non -Disclosure Agreement AOGCC Docket Number OTH-18-045 ConocoPhillips Alaska, Inc. (ConocoPhillips) has offered to admit Alaska Oil and Gas Conservation Commission (AOGCC) staff into a data room to review economic information related to ConocoPhillips' application for approval of the proposed oil and gas measurement system for the Greater Mooses Tooth 2 (GMT2) development. The GMT2 measurement application is the subject of an AOGCC hearing on October 23, 2018. Prior to the hearing, the AOGCC has requested access to more economic information related to GMT2, subject to confidential treatment and protection by the AOGCC. The data room will contain anticipated future oil production rates, estimated project spending profiles, cost estimates for hypothetical processing facilities, and project net present value estimates based on public oil price forecasts. This information is confidential and proprietary to ConocoPhillips; access to this information is limited in order to preserve a competitive business position. The undersigned AOGCC staff member hereby acknowledges that access to information the data room is subject to the following conditions: • No paper or electronic media may be removed from the data room. • Any mental impressions of information in the data room, or notes made of information in the data room, shall be treated as confidential. Any notes shall be labelled as confidential, segregated from non -confidential information, and may not be released in response to a public records request. • The information in the data room is made available for review without any warranty. Much of the information is forward-looking, predictive, based on estimates, or otherwise may prove to be an inaccurate representation of actual conditions. ConocoPhillips has no obligation to update, revise, correct, or otherwise modify the information after it is viewed in the data room. • The information made available in the data room may be used only as follows: o the information may be discussed among AOGCC staff and Commissioners for purposes of considering the GMT2 metering application in AOGCC docket number 0TH -18-045 , and notes of the information and discussions may be included in AOGCC records, so long as anything that would reveal information shown in the data room is labelled and treated as confidential and is not released outside of the AOGCC; o the information maybe released to the extent necessary to comply with a court order or in litigation to which the information is relevant, and to the extent the information may have otherwise been made public except through a breach of AOGCC confidentiality protections. The undersigned AOGCC staff member acknowledges these conditions for access to the data room and agrees to comply with the conditions to protect the confidentiality of information in the data room. Name: A �Y 5 90P Date: 10/51 Signature: i ConocoPhillips Alaska September 17, 2018 Brandon Viator Project Integration Manager, GMTU ConocoPhillips Alaska 700 G Street Anchorage, AK 99501-3439 Phone 907.263.4653 Dave Roby Alaska Oil and Gas Conservation Commission SEP 17 20118 Anchorage, W. 71h orage, venue AOGCC Anchorage, AK 99501 RE: Docket Number: OTH-18-045 Application for waiver of requirements of 20 AAC 25.228(a) to the Greater Mooses Tooth 2 (GMT2) metering system Dear Mr. Roby: In response to the Alaska Oil and Gas Conservation Commission's letter of August 22, 2018 to Stephen Thatcher, ConocoPhillips Alaska, Inc. (CPAI) has set-up a confidential data room for you to view confidential economic data related to CPAI's application in the above referenced docket. Attached is a proposed non -disclosure agreement (NDA) to facilitate your review. If the NDA is acceptable, please complete it and then contact me to arrange a time to view the data. Sincerely, �I Brandon Viator Project Integration Manager, GMTU ConocoPhillips Alaska Attachments: Attachment 1: Data Room Access and Non -Disclosure Agreement ORIGINAL ATTACHMENT 1 Data Room Access and Non -Disclosure Agreement Data Room Access and Non -Disclosure Agreement AOGCC Docket Number OTH-18-045 ConocoPhillips Alaska, Inc. (ConocoPhillips) has offered to admit Alaska Oil and Gas Conservation Commission (AOGCC) staff into a data room to review economic information related to ConocoPhillips' application for approval of the proposed oil and gas measurement system for the Greater Mooses Tooth 2 (GMT2) development. The GMT2 measurement application is the subject of an AOGCC hearing on October 23, 2018. Prior to the hearing, the AOGCC has requested access to more economic information related to GMT2, subject to confidential treatment and protection by the AOGCC. The data room will contain anticipated future oil production rates, estimated project spending profiles, cost estimates for hypothetical processing facilities, and project net present value estimates based on public oil price forecasts. This information is confidential and proprietary to ConocoPhillips; access to this information is limited in order to preserve a competitive business position. The undersigned AOGCC staff member hereby acknowledges that access to information the data room is subject to the following conditions: • No paper or electronic media may be removed from the data room. • Any mental impressions of information in the data room, or notes made of information in the data room, shall be treated as confidential. Any notes shall be labelled as confidential, segregated from non -confidential information, and may not be released in response to a public records request. • The information in the data room is made available for review without any warranty. Much of the information is forward-looking, predictive, based on estimates, or otherwise may prove to be an inaccurate representation of actual conditions. ConocoPhillips has no obligation to update, revise, correct, or otherwise modify the information after it is viewed in the data room. • The information made available in the data room may be used only as follows: o the information may be discussed among AOGCC staff and Commissioners for purposes of considering the GMT2 metering application in AOGCC docket number OTH-18-045 , and notes of the information and discussions may be included in AOGCC records, so long as anything that would reveal information shown in the data room is labelled and treated as confidential and is not released outside of the AOGCC; o the information may be released to the extent necessary to comply with a court order or in litigation to which the information is relevant, and to the extent the information may have otherwise been made public except through a breach of AOGCC confidentiality protections. The undersigned AOGCC staff member acknowledges these conditions for access to the data room and agrees to comply with the conditions to protect the confidentiality of information in the data room. Name: Date: Signature: THE STATE 01ALASKA GOVERNOR BILI. WALKER August 22, 2018 Mr. Stephen Thatcher WNS Development Manager ConocoPhillips Alaska, Inc. PO Box 100360 Anchorage, AK 99510 Re: Docket Number: OTH- 18-045 Application for waiver of requirements of 20 AAC 25.228(a) to the Greater Moose's Tooth 2 (GMT2) metering system. Dear Mr. Thatcher: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.olaska.gov By letter dated July 12, 2018, ConocoPhillips Alaska, Inc. (CPAI) applied for a waiver of the requirement that custody transfer metering at GMT2 be performed in accordance with the API Manual of Petroleum Measurement Standards (API MPMS) in effect on November 30, 1998, i.e., waiver of the requirement that production be processed to sales quality before being metered. The Alaska Oil and Gas Conservation Commission (AOGCC) has previously granted a waiver of the processing requirement when compliance with the regulation would have made the project economically unviable. CPAI's waiver request states that "installing a process facility to meet custody transfer measurement requirements has significant environmental and cost impacts, which could lead to project delays and could potentially lead to other consequences including reconsideration of the economic viability of GMT2." To the extent CPAI is claiming that regulatory compliance will render the GMT2 project economically unviable, it has not provided sufficient information in support of its request. Specifically, CPAI has not provided economic data and assumptions that show that a standalone processing facility is not economically viable for the GMT2 project. To the extent CPAI asserts its economic data and assumptions are confidential, AOGCC notes that CPAI and AOGCC resolved a similar waiver issue as to GMTl by way of a non -disclosure agreement. AOGCC further notes its willingness to enter the same non -disclosure agreement with regard to confidential economic data and assumptions with regard to this waiver request. Senior Reservoir Engineer David S. Roby would be the staff member assigned to any such review. If you have any questions, please contact Dave Roby (dave.roby a)alaska.eov or 907-793-1232). Sincerely, Hollis S. French Chair, Commissioner 1 ConocoPhillips Alaska July 12, 2018 Commissioner Hollis French, Chair Alaska Oil and Gas Conservation Commission 333 W. 7`h Avenue Anchorage, AK 99501 RE: Greater Mooses Tooth #2 (GMT2) GMT2 Measurement Approval Dear Mr. Commissioner French: Stephen Thatcher WNS Development Manager ConocoPhillips Alaska 700 G Street Anchorage, AK 99501-3439 Phone 907.263.4464 JUL 12 2018 AOGCC ConocoPhillips Alaska, Inc. (ConocoPhillips), as the sole working interest owner and Unit Operator of the Greater Mooses Tooth Unit (GMTU), requests approval for a proposed hydrocarbon production measurement and allocation system for the second GMTU development, GMT2. As described in detail in Attachment 1 to this letter, GMT2 is designed as a satellite drill site in the National Petroleum Reserve — Alaska (NPR -A), west of the existing CD5 drillsite in the Colville River Unit (CRU) and west of Greater Mooses Tooth #1 (GMT1). AOGCC Industry Guidance Bulletin 13-002 specifies that AOGCC approval of custody transfer measurement is required before installation of a meter system, which as a practical matter means approval is required at the engineering and procurement stage of development. ConocoPhillips is requesting approval of the same measurement methodology that was approved for GMT1. See Attachment 2 (Other Orders 112 and 112A dated 10/12/2016 and 12/22/2016, respectively). At this point, not all of the information listed in Guidance Bulletin 13-002 can be provided, in part because actual equipment must be installed before some of the information can be obtained. Yet, it is important to secure AOGCC approval of the system before project sanction. ConocoPhillips thus seeks approval now, with the understanding that the AOGCC might later require specific information that is not presently available. The proposed GMT2 measurement system includes a 3-phase production separator providing continuous measurement of GMT2 production using Coriolis meters and water cut analyzer. It also includes American Gas Association (AGA) compliant orifice meter runs for the produced gas. After separation and measurement at the GMT2 drill site, the produced fluids are recombined and flow to GMT1, where production from GMT2 is commingled with GMT1 production prior to flowing to the Alpine Central Facility where it is commingled with production from the remaining Colville River Unit drill sites. At the Alpine Central Facility, commingled production from GMT2, GMT1 and all of the CRU drill sites will be separated, processed, and delivered to the Alpine Pipeline, through a Lease Automatic Custody Transfer (LACT) meter, for transport to market. Like GMT1, GMT2 production will be measured continuously prior to being combined with any other production, and like GMT1 production will receive an allocation factor of 1.0 at the CRU LACT meter. As with GMT1, the GMT2 measurement system may not strictly conform to the API standard adopted in 20 AAC 25.228(b), but we believe it lies well within ConocoPhillips Alaska GMT2 Development & Measurement Approval Request Overview the Commission's authority to adopt reasonable orders to provide for the measuring of oil and gas under AS 31.05.030(c)(6), 20 AAC 25.505(a) and 20 AAC 25.540(a). Attachment 1 to this letter is a detailed explanation of the project, and an explanation of why this production measurement system should be approved. ConocoPhillips is seeking concurrent regulatory approval from both the AOGCC and the BLM for the proposed measurement system. As reference, ConocoPhillips has also included with this submittal a copy of our GMT2 measurement application package that will be submitted concurrently to the BLM. See Attachment 3. If you have questions or need additional information, please contact Brandon Viator, Project Integration Manager - GMTU, at 907-263-4653. Sincerely, Stephen Thatcher WNS Development Manager ConocoPhillips Alaska Attachments: Attachment 1: GMT2 Measurement Application Request Attachment 2: Other Orders 112 and 112A Attachment 3: GMT2 Measurement Application Package for BLM 3 ATTACHMENT 1 GMT2 Measurement Application Request ConocoPhillips GMT2 Development & Measurement Alaska Approval Request Overview GMT2 Measurement System Content: A. Requested Approvals.......................................................................................................................3 B. GMT2 Project Description................................................................................................................3 C. Proposed GMT2 Flow Measurement & Metering Description..........................................................4 1. Custody Transfer/Point of Royalty Metering and Oil Measurement..................................................4 2. Gas Measurement...........................................................................................................................5 3. Operation and Maintenance of Measurement Equipment...............................................................6 D. Rationale for Live Fluid LACT Measurement.....................................................................................6 1. Provides Accurate Measurement.....................................................................................................6 2. Minimizes Environmental Footprint and Makes the Project Economic.............................................8 E. Conclusion.......................................................................................................................................9 Figures: • Attachment 1A— GMT2 and CRU Map (Gathering System) • Attachment 1B— GMT2 leases, preliminary PA, and proposed wells • Attachment 1C—GMT2 lease ownership, royalty rate, and allocation factor • Attachment 1D —GMT2 drillsite site plan • Attachment 1E — GMT2 drillsite process flow diagram • Attachment 1F—GMT2 production separator measurement system • Attachment 1G —ACF simple process flow diagram • Attachment 1H —GMTU Measurement Point Overview • Attachment 11— Uncertainty Calculation • Attachment L — Processing Facility Economic Impacts 2 ConocoPhillips Alaska A. Requested Approvals GMT2 Development & Measurement Approval Request Overview ConocoPhillips requests the Alaska Oil and Gas Conservation Commission (AOGCC) approve the Greater Mooses Tooth #2 (GMT2) oil measurement system, described below. The system may not strictly conform to the API standard adopted in 20 AAC 25.228(b), but we believe it lies well within the Commission's authority to adopt reasonable orders to provide for the measuring of oil and gas under AS 31.05.030(c)(6), 20 AAC 25.505(a) and 20 AAC 25.540(a). The GMT2 measurement system is based on the Greater Mooses Tooth #1 (GMT1) measurement system design that was previously approved by the AOGCC in Other Orders 112 and 112A. GMT2 production will be measured continuously prior to being commingled with GMT1 and Colville River Unit (CRU) production, and like GMTI, will be given an allocation factor of 1.0 at the CRU LACT meter. B. GMT2 Project Description The GMT2 project will develop the second drill site in the Greater Mooses Tooth Unit (GMTU) which is in the northeast corner of the National Petroleum Reserve — Alaska (NPR -A). The GMT2 project consists of the construction of a planned drillsite, access road, pipelines, power lines, bridges, and ancillary facilities for recovery of petroleum resources within the GMTU. The GMT2 drillsite will be located 25 miles southwest of the CRU CDl drillsite and the Alpine Central Facility (ACF). The GMT2 project will develop Arctic Slope Regional Corporation (ASRC) leases and BLM federal leases from an oil accumulation formed by a stratigraphic trap of Upper Jurassic sandstones (Alpine C sandstone equivalent) similarto what has been developed at CD1. The GMT2 satellite was discovered in 2000 by the Rendezvous A well. Rendezvous 2 (2001) and Rendezvous 3 (2014) wells were drilled and used for reservoir delineation. The GMT2 project will provide sufficient infrastructure to support development of up to 48 wells. The proposed GMT2 infrastructure will tie back to the CRU and will be the sixth satellite developed through the ACF following development of the Clannik CD2, Fiord CD3, Nanuq CD4, Alpine West CD5, and Lookout GMT1 satellites (see Attachment 1A). The project will produce 3-phase fluids (oil, gas, and water) which, after measurement at the GMT2 drillsite, will be carried by pipeline to the CRU ACF at CD1 for processing. Water and gas will be returned to GMTU by pipeline to support enhanced oil recovery of GMTU resources. Sales -quality crude oil produced at the ACF will be transported via the existing Alpine Sales Oil Pipeline and Kuparuk Pipeline to the Trans -Alaska Pipeline System (TAPS) for shipment to market. Development and production of hydrocarbons from GMT2 will help offset declines in production from the Alaskan North Slope and maintain throughput of TAPS. Development will also provide benefits to local, state, and national economies through local hire for jobs created during construction and operations, tax revenues, revenue sharing, royalties, and new resources to help meet US domestic energy demand. The GMT2 development is expected to employ up to 700 people during the peak of construction and result in new full-time positions upon startup. 3 ConocoPhillips Alaska GMT2 Development & Measurement Approval Request Overview The map and figures included as Attachments 1A, 1B, and 1C, show the GMTU leases, proposed development wells, conceptual unit participating area (PA), and lease ownership percentages. The map and figures illustrate how GMT2 pipelines tie back to GMT1 and the CRU. The GMT2 development drillsite consists of nine process modules and a well row. The process modules consist of a pig launcher/receiver module, production heater, test separator/ sand handling module, remote electrical & instrumentation module (REIM), emergency shutdown module (ESD), chemical injection module, fuel gas conditioning skid (fuel gas is supplied to the drillsites from the ACF), metering module, and a production separator system which will be used as the GMT2 point of royalty. Attachment 1D, the proposed GMT2 site plan, displays the layout of the drillsite infrastructure. Attachment 1E provides a GMT2 drillsite process flow diagram and Attachment 1F provides additional detail on the GMT2 production separator measurement system. The ACF simplified process flow diagram is shown in Attachment 1G. The ACF separates and processes well bore fluids from the associated drillsite facilities and delivers sales -quality crude oil into the common carrier oil pipeline system that leads to the TAPS. ACF processed produced water is returned to the CRU drillsites for re-injection into the producing formations to maintain reservoir pressure and provide secondary flood support. Seawater or produced water will be delivered to GMT1 and GMT2 for pressure maintenance. ACF processed gas is: (i) used to fuel plant and drillsite facility equipment, (ii) provided to the Village of Nuiqsut, (iii) re -injected into CRU and GMTU reservoirs to maintain reservoir pressure for increased recovery, and (iv) used for gas lift. C. Proposed GMT2 Flow Measurement & Metering Description 1. Custody Transfer/Point of Royalty Metering and Oil Measurement The GMT2 produced oil and gas custody transfer system is designed similar to the GMT1 system. The GMT2 system will consist of a horizontal vessel which will operate as a three-phase separator (vapor/water/oil). Vessel internals will consist of an inlet cyclonic separator, liquid coalescer, weir (three-phase operation), mist extractor on the gas outlet, vortex breaker and sand -jet system. The GMT2 returned gas custody transfer will utilize the return gas meters installed with GMT1 and located at CD5, shown on Attachment 1H. Shrinkage Factors (SF) will be utilized to convert live oil drillsite flowrates to standard conditions and will be developed across a range of operating pressures and temperatures so that process variances are captured to prevent a systematic bias impacting the measurement of oil. The same methodology used at GMT1 will be used for GMT2. An on-line water cut analyzer in the sampling fast loop will be utilized to measure water in the oil outlet PRM, identical to GMT1. It is anticipated that the water content flowing through the oil leg of the production separator will not exceed 10% by volume at any point in field life. 4 ConocoPhillips Alaska GMT2 Development & Measurement Approval Request Overview The oil metering system for GMT2 is based on the GMT1 system. The GMT2 metering system will consist of a Micro Motion Elite Coriolis master meter in series with two Micro Motion Elite Coriolis line meters installed in a parallel configuration. (The proposal for GMT2 is to have 2 x 100% meters. The GMT2 meters are the next size larger model than installed for GMTI.) The project is also considering a 3 x 50% meters configuration for GMT2, which would utilize identical Coriolis meters as GMT1. Regardless of the selected meter configuration, the Coriolis in-service line meters are sized to handle the full range of expected normal operating flow rates from GMT2 and includes jet mixing and sampling extractor for the composite sampling system, pressure and temperature instrumentation and control valves. One line meter is expected to be in operation at any point, with the other as an in- line spare. An automatic flow proportional sample system will be installed to permit collection of representative oil samples for laboratory analysis. A common composite sampling system with a water cut analyzer in the fast loop will be manifolded to the two parallel line meters. All flow measurement information will be used to calculate net oil volume and evolved gas at standard conditions through application of a shrinkage factor. An oil -in -water analyzer will be installed on the water outlet. Simplified process flow diagrams of the GMT2 production separator and oil metering system are shown in Attachment 1F. 2. Gas Measurement Gas will be measured in accordance with applicable regulations, and no special approval is being requested for gas measurement beyond the allocation factor of 1 to be applied to the GMT2 gas meters. As shown in Attachments IE, IF, & 1H total gas will be measured at GMT2 before being sent to the ACF for processing. The conditioned GMT2 gas will then be sent back to GMT2 for use as fuel, injection and artificial lift. Excess gas not used for fuel at ACF and not returned to GMT2 will remain in CRU and injected into CRU participating areas for enhanced oil recovery. Prior to severing the CRU, a metering module installed at the CD5 drill site will measure gas being sent back to GMTU for reinjection, lift and fuel at the GMT1 and GMT2 drill sites. (i) Production Separator Gas Metering The production separator gas outlet metering system will be based on GMT1. The GMT2 gas metering system will include two meter runs, which will cover the range of normal operating gas flowrates from the drill site. Conceptually this will be accomplished by two similar AGA compliant orifice meter runs of different size. GMT1 includes a 6 inch and 10 inch orifice meter run, while GMT2 is proposing a 6 inch and 12 inch run due to higher forecasted gas rates. Additionally, the two meter runs provide a level of redundancy to help ensure improved drill site uptime. Fully redundant meter runs are not necessary due to the highly reliable orifice metering technology and the relatively minimal maintenance down time to repair orifice meters. Each meter run will consist of upstream and downstream metertubes, flow conditioner, senior orifice fitting and plate, pressure and temperature transmitters and control valve. A flow computer, DP Diagnostics, and a differential pressure diagnostic system will be installed on the gas meter runs to GZ ConocoPhillips Alaska GMT2 Development & Measurement Approval Request Overview monitor the gas metering systems. Automatic flow proportional gas composite sampling systems will also be installed to collect representative produced gas samples for laboratory analysis. (ii) Drill Site Gas Metering Attachment 1H shows the GMTU Measurement Points currently anticipated to support custody transfer and reporting requirements. 3. Operation and Maintenance of Measurement Equipment The operation and maintenance program for measurement equipment will be based on the GMT1 operation and maintenance program. (i) Sampling Sampling philosophy will be consistent with the GMT1 design and will follow all applicable ELM and AOGCC regulations. (ii) Well Allocation Methodology Each well will be tested in the Test Separator once per month and that data used in conjunction with the 3-phase separator to determine well allocation at GMT2. Net standard volumes will utilize this metering allocation information for royalty payment data. D. Rationale for Live Fluid LACT Measurement 1. Provides Accurate Measurement GMT2 is designed as a satellite drill site that will deliver three-phase production to the Alpine Central Facility (ACF) for separation and processing. Accordingly, the measurement of hydrocarbon liquids will occur at elevated temperature and pressure which are not stable under the requirements of the American Petroleum Institute (API) Manual of Petroleum Measurement Standards (MPMS) Chapter 6.1 Metering Assemblies - Lease Automatic Custody Transfer (LACI) Systems (1996), which is made applicable by 20 AAC 25.228. Standard volume is not a wholly measured parameter; it is a parameter derived from a measurement of volume at operational conditions which is then converted by means of empirical or laboratory analysis data to a volume at standard conditions. The conversion of stable fluids from observed volume to standard volume is achieved using Volume Correction Factors (VCF) derived from tables and calculations created by the API and which have an uncertainty budget in the region of+/- 0.1°%. ConocoPhillips Alaska GMT2 Development & Measurement Approval Request Overview The conversion of live fluids from observed volume to standard volume is achieved through the application of a Shrinkage Factor (SF) which is derived from laboratory pressure, volume and temperature (PVT) testing or equation of state (E05) modeling based upon detailed compositional analysis. The conversion of volume at operational conditions to volume at standard conditions will incur a penalty of+/ -0.1% when applied to stabilized fluids and a penalty of +/-2% when applied to live fluids. Table 2 below provides an illustration of the comparable measurement uncertainties for stable and live fluids. Table 2 — Comparable Measurement Uncertainties r Stable Fluids Uncert Flow Meter Base Flow Meter Base Accuracy plus Pressure Accuracy plus Mass 0.15 and Temperature Mass 0.16 Pressure and Corrections Temperature Corrections Observed Mass Uncertainty plus Observed Mass Uncertainty plus Volume 0.25 Observed Density Volume 0.27 Observed Density Uncertainty Uncertainty Mass Uncertainty, Mass Uncertainty, Observed Density Observed Density Standard Uncertainty Plus Standard Uncertainty Plus Volume 035 . Conversion to volume 2.05 Conversion to Standard Volume Standard Volume Uncertainty (VCF) Uncertainty (SF) It is important to note that the differences in performance in determining Standard Volume between the AOGCC rule requirements and ConocoPhillips' proposed metering system design are not related to the base accuracy of the flow meters or hardware components of the metering system. The ConocoPhillips proposed measurement system design, utilizing Coriolis flow meters, will meet typical industry custody transfer standards forthe measurement of Mass and Gross Observed Volume but will not meet the performance standard required for Standard Volume. The measurement uncertainty estimate for GMT2 oil production is provided as Attachment 11 of this document where a maximum value of+/- 2.03% at 95% confidence level has been determined using the 2 x 100% meter configuration. The 3 x 50% meter configuration would result in an uncertainty of 7 ConocoPhillips Alaska GMT2 Development & Measurement Approval Request Overview approximately 2.05%. The calculations required to determine Net Standard Volume are also contained within the uncertainty calculation provided in Attachment 11. Flow meter verification is accomplished by monthly proving of the line meters against the master meter consistent with API MPMS standards. The Coriolis meters will also implement Smart Meter Verification (SMV) functionality, which permits automated and online verification of the flow meters. The results of the SMV verifications are trended over time and provide traceable evidence of meter performance within defined manufacturer limits. The Coriolis master meter will be sent off site for master meter proving initially after three months and annually after that per BLM Measurement of Oil regulations, which is consistent with the requirements of API MPMS Section 4.8.2.11, made applicable through 20 AAC 25.228(h). 2. Minimizes Environmental Footprint and Makes the Project Economic The Naval Petroleum Reserves Production Act of 1976 (NPRPA) authorizes and directs the Secretary of the Interior to "further explore, develop, and operate" the National Petroleum Reserve -Alaska (NPR -A) (10 USC Section § 7422[c]). The GMT2 Development Project promotes the exploration and development of oil and gas resources in the NPR -A. Specifically, the NPRPA, as amended, encourages oil and gas leasing in the NPR -A while requiring protection of important surface resources and uses. One of the key aspects of this approach is the utilization of the existing installed processing capacity at the ACF. The current GMT2 Development Project seeks to minimize environmental impacts by leveraging existing infrastructure where available to avoid redundancy and waste. Facility sharing for GMT1 and GMT2 at Alpine was required and approved by BLM. Specifically, the Interior Secretary's Record of Decision provided that NPR -A developments to share facilities with existing developments to minimize project footprint. See 2/21/2013 ROD at Stipulation E-5. The use of ACF to process GMT2 production greatly reduces the environmental footprint of GMT2 by eliminating the need for a standalone GMT2 processing facility capable of producing sales -quality crude oil. Without approval of an alternative oil measurement method, a processing facility would have to be built as part of the proposed project to accommodate custody transfer metering prior to sales -quality crude leaving the lease or unit PA. Significantly, the measurement system submitted for approval for GMT2 is based on the system that was approved by the AOGCC and BLM for the GMT1 Satellite. The estimated incremental environmental and cost impacts associated with building a new processing facility are significant in nature and unjustified. Environmental impacts include "'8-10 additional acres of gravel to house a processing facility, and increased air emissions due to additional electric power generation, gas compression, and flare requirements. The incremental unescalated costs for building ConocoPhillips Alaska GMT2 Development & Measurement Approval Request Overview a processing facility for a single PA at the GMT2 site are estimated to be within a range of $700- $900 million. If multiple PAs are produced at GMT2, some utilities and equipment may be shared, but the separation and compression systems will be needed for each PA. This will result in additional unescalated capital on the order of $400 - $500 million per additional PA. A related consideration that should be taken into account when evaluating this proposal is the viability of permitting a development which does not allow the measurement system proposed by ConocoPhillips in this application. Permitting agencies and stakeholders are keen on reducing any impacts tothe environment and subsistence lifestyle of local native residents. The wetlands fill permit forthe GMT2 project was designed for a satellite drill site that relies on existing ACF infrastructure for processing. That permit is expected to be approved by the United States Army Corps of Engineers as the Least Environmentally Damaging Practicable Alternative (LEDPA). Changing course to install a new processing facility at GMT2 would likely result in a 4 -year delay to first oil resulting in deferred economic benefit to the BLM, the State of Alaska, and ASRC. Attachment L shows that the cost to add a processing facility to the GMT2 scope would result in an uncompetitive project and would not be sanctioned by ConocoPhillips, stranding valuable resource that is otherwise ready to be developed. In summary, installing a process facility to meet custody transfer measurement requirements has significant environmental and cost impacts, which would lead to project delays and could potentially lead to other consequences including reconsideration of the economic viability of GMT2. CPAI strongly believes that overriding considerations merit approval of the measurement system described in this application for GMT2 consistent with the approval previously granted for GMT1. E. Conclusion CPAI requests that AOGCC approve the oil measurement system described in this application for the GMT2 project. The measurement methodology proposed in this application will result in accurate measurement which will protect all interested parties while accommodating the unique circumstances of the GMT2 development. 0 Attachment IA: GMT2 and CRU Map (Gathering System) • Exploration Well SHL ....�• ■ Road or Pad , -..� "�•• �•`�• +"• _ —Pipeline • •....,,,.•, OAK Unit '�,� CD3 a_NPR-A �•,f l ..� NATIONAL P ETR OLEU M. R E S E R V E - ALASKAeo • �� Colville River Unit CD2 CD9 CDS •• CD4 • • GMT9 • Greater Moose s Tooth Unit GMT2 ✓ ConocoPhillips • Alaska Greater Mooses Tooth Unit N and Colville River Unit Roads, Pads, & Pipelines • o i z � mile, 3/20/2018 Attachment 113: GMT2 Conceptual PA, Wells, and Leases Ma78a M087tW f---��_-- Mateo M0BQ3° f,vl rMtT M081821 AAM+eM Ma1111. A31 River Maus Mautb 1Unit u06 M081819 L� M6t1617 ASIN ArPR2 Bear Tooth At Unit atmtlt6i aosnoo GMT1 1 �acwtd __ 4 Malta AAM342 .I M004167 Malta i M092911 M0MVI A6%1111 118RGNPRS Greater Maim _ Mooses Matx75 Tooth Unit r M092341 M01107 M081804 rI M081803 M081T% Ma176t M081793 bRC.NPR6 GMT2 M094168 _ \� M011800! i I Ma3132 Ma1tu Mtnrw \ \ 1 Mat7a1 \�\�\\ Ma tt\ Moen% M I \\\\\\ o91779 — proposed Well Targets Motlne —Pipeline Road or Ped AA081735+AACSIMRendezvous Reservoir ^^a17u Mos+7n "' Q Potential PA Boundary Ma1110 ! Ma0709 M081702 M081738 Unit Boundaries jj CPAI Leases r r ConocoPPhillips Alaska Ma0707 I r92672 Ma29n I Rendezvous Participating Area, Leases and Proposed Wells 0 1 2 3 4 Miles 3/1812018 Attachment 1C: GMT2 List of Leases for Potential Rendezvous Participating Area Greater Mooses Tooth Unit Tract Description No. of Lands 13 T10N-R1E, UM lection 16: S1/2NE1/4,SE1/4 Total Number Serial Number Expiration of Acres Tobin Number Date AA -081806 8/31/09 240.00 932541 240.00 Basic Basic Ownership Overriding Overriding Royalty Working Ownership Royalty Royalty Owner Percentage Royalty Owner Percentage Interest Owner(s) Percentage 16.6667% U.S. 100% None None ConocoPhillips 100.00 14 T10N-R1E, UM AA -081805 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 13: SW1/4NW1/4, 932540 W112SE1/4, SE1/4SE1/4, SW1/4 320.00 Section 14: W1/2, NW1/4NE1/4, S1/2NE1/4, SE1/4 600.00 Section 15: NEI/4NW1/4, S1/2NW1/4, E1/2, SW1/4 600.00 Total 1520.00 20 T10N-R1E, UM AA -081804 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 21: E1/2W1/2, E1/2 480.00 932539 Section 28: E1/2W1/2, E1/2 480.00 Section 33: E1/2W1/2, E1/2 460.00 Total 1440.00 21 T10N-R1E, UM AA -081803 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 22: All 640.00 932538 Section 23: All 640.00 Section 24: All 640.00 Section 25: All 639.00 Section 26: All 640.00 Section 27: All 639.00 Section 34: All 640.00 Section 35: All 639.00 Section 36: All 639.00 Total 5756.00 1 Attachment 1C: GMT2 List of Leases for Potential Rendezvous Participating Area Greater Mooses Tooth Unit Tract Description No. of Lands 22A T10N-R2E, UM Section 19: W1/2, SWI/4NE1/4, W1/2SE1/4, SE1/4SE1/4 Section 28: W1/2SE1/4, SW1/4 Section 30: All Section 31: All Section 32: All Section 33: All Total Number Serial Number Expiration of Acres Tobin Number Date AA -081800 8/31/09 932535 480.00 240.00 619.00 621.00 640.00 640.00 3240.00 Basic Basic Ownership Overriding Overriding Royalty Working Ownership Royalty Royalty Owner Percentage Royalty Owner Percentage Interest Owner(s) Percentage 16.6667% U.S. 100% None None ConocoPhillips 100.00 22B T10N-R2E, UM AA -092341 8/31/09 14.16667%` ASRC 100% Kuukpik Corp. 2.5%' ConocoPhillips 100.00 Section 29: W1/2NW114, 340762 SEI/4NW1/4, S112NE1/4, S1/2 520.00 Total 520.00 23 T10N-R2E, UM AA -081799 8/31/09 16.6667% U.S. 10D% None None ConocoPhillips 100.00 Section 25: SW1/4SE1/4, S1/2SW 120.00 932534 Section 26: SE1/4SE1/4 40.00 Section 34: W1/2NW1/4, 520.00 SE1/4NW1/4, S1/2NE1/4, S1/2 Section 35: S1/2NW1/4, E1/2, SWIM 560.00 Section 36: All 640.00 Total 1880.00 25 T9N-RIE, UM AA -081785 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 4: N1/2NE1/4 80.00 932520 Total 80.00 26 T9N-R1E, UM AA -081784 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 1: All 640.00 932519 Section 2: All 640.00 Section 3: N1/2, SE1/4, N1/2SW1/4 560.00 Section 10: N1/2NE1/4 80.00 Section 11: All 640.00 Section 12: All 639.00 Section 13: All 639.00 Section 14: All 639.00 Total 4477.00 2 Attachment 1C: GMT2 List of Leases for Potential Rendezvous Participating Area Greater Mooses Tooth Unit Tract Description No, of Lands 27 T9N-R2E, UM Section 4: All Section 5: All Section 6: All Section 7: All Section 8: All Section 9: All Section 16: All Section 17: All Section 18: All Total Number Serial Number Eviration of Acres Tobin Number Date Section 15: W1/2W1/2 AA -081781 8/31/09 640.00 932516 639.00 640.00 639.00 Section 36: All 624.00 Total 5676.00 626.00 640.00 640.00 640.00 640.00 630.00 5720.00 Basic Basic Ownership Overriding Overriding Royalty Working Ownership Royalty Royalty Owner Percentage Royalty Owner Percentage Interest Owner(s) Percentage 16.6667% U.S. 100% None None ConocoPhillips 100.00 28 T9N-R2E, UM AA -081780 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 1: N1/2, NW1/4SE1/4, 932515 E/2SE1/4, N1/2SW1/4 520.00 Section 2: N1/2, N1/2SE1/4, SW1/4 560.00 Section 3: All 640.00 Section 10: W1/2NW1/4, 639.00 NW1/4NW1/4, W1/2SW1/4 200.00 Section 15: W1/2W1/2 160.00 Total 2080.00 29 T9N-R3E, UM AA -081779 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 6: All 624.00 932514 Total 624.00 31 T9N-RIE, UM AA -081782 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 22: E11/2NW1/4, E1/2, SW114 560.00 932517 Section 23: All 640.00 Section 24: All 639.00 Section 25: All 640.00 Section 26: All 639.00 Section 27: All 640.00 Section 34: All 639.00 Section 35: All 639.00 Section 36: All 640.00 Total 5676.00 3 Attachment M GMT2 List of Leases for Potential Rendezvous Participating Area Greater Mooses Tooth Unit Tract Description No. of Lands 32 T9N-R2E, UM Section 19: All Section 20: All Section 21: All Section 29: All Section 30: All Section 31: All Section 32: All Total 33 T9N-R2E, UM Section 22: N W 114NW 1 /4 Total Number Serial Number Expiration of Acres Tobin Number Date AA -081736 8/31/09 631.00 300840 640.00 640.00 640.00 635.00 638.00 640.00 4464.00 Basic Basic Ownership Overriding Overriding Royalty Working Ownership Royalty Royalty Owner Percentage Royally Owner Percentage Interest Owner(s) Percentage 16.6667% U.S. 100% None None ConocoPhillips 100.00 AA -081735 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 4000 300839 40.00 45 T9N-RIE, UM AA -090709 11/30/18 16.6667% U.S. 100°/ None None ConocoPhillips 100.00 Section 21: SE1/4 160.00 310090 Section 28: E1/2NW1/4, E1/2, SWIM 560.00 Section 32: NE1/4NE1/4, S1/2NE1/4, SE1/4, E1/2SW1/4 360.00 Section 33: All 640.00 Total 1720.00 48 T8N-R1 E, UM AA -092672 10/31/20 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 4: All 640.00 341731 Section 5: NE1/4, N1/2SE1/4, 280.00 SE1/4SE1/4 Section 9: N1/2NE1/4 80.00 Total 1000.00 Totals 40,477.00 'Kuukpik Corp. Overriding Royalty deducted from ASRC Royalty as agreed between Kuukpik Corp. and ASRC for surface access. Key: ASRC - Arctic Slope Regional Corporation Kuukpik Corp. - Kuukpik Corporation ConocoPhillips - ConocoPhillips Alaska, Inc. - Operator U.S. - United States of America 4 5.7 In 4 ® h�� M1qa1qp �1q�1q ppm ®Yd ow Yd Yd ia�® a----_----' ' [0 .fT-nm.gb W Mh M/we �E=MIWp WL o_��• - n art •yam .�. :: ' ConowpNlli -� NaAa. Inc, vac emuran we m .� PRELIMINARY $a Uh ,, a.sw wea.w %OT FOR 0016TRNCTION e e ivu rtn agar hre > e icwm na ate. `ss-ufll-r] Cn. 9 N Attachment IE: GMT2 Drillsite Process Flow Diagram Additional Utilities Required: Nitrogen Plant Air Fuel Gas Corrosion Inhibitor Scale Inhibitor Emulsion Breaker 1:1Water Cut Meter and Liquid Sampling ® Coriolis Meter OOrifice Plate Meter and Gas Sampling Anti -foam Q Oil in Water Analyzer Pig Launcher To GMT3/ ACF GMT2 Fuel Gas Conditioning Line List: _________________I Purple: Chemical Orange: Gas Lift Gas Green: Oil+water I GI Blue: Separated water Fuel Gas Black: Oil+water+gas I TO Injector i rl Wells t– �— �i I I MI I m Test Separator' .__________I _I x I I � I I I I ESD Valves I I Test Sep. i � Prod. Separator ---I i Metering I I 00 I I 1 I I i I Full Flow 3Phase I Production Separator – -- ___--- I Production Heater I � I I I I I xxo rlwnxmr Scale Inhibitor Emulsion Breaker 1:1Water Cut Meter and Liquid Sampling ® Coriolis Meter OOrifice Plate Meter and Gas Sampling Anti -foam Q Oil in Water Analyzer Pig Launcher To GMT3/ ACF Attachment 1F: GMT2 Production Separator Measurement System ❑Phase Dynamics Water Line List: cut meter ® ❑u ® cnrrolis Meter Orange: Gas Green: Oil+water O Orifice Plate Meter Blue: Separated water OGassan,lestatbn Black: Oil+water+gas QOil in Water Analyzer Production to GMT1/ACF Attachment 1G: ACF simple process flow diagram Sea Water Alpine Central Facility Natural Lift G85 -- P Gas C� OYnOA FUN & Fare Gas Sates Processing ALP - Alpine Gas FN - Fiord- Nechelik Condensate Gas FK - Fiord-Kuparuk Dry Gas NN - Nan uq-Nanuq Crude la at Enrichment Injection GAN - Oannik Separator LO -Lookout Enriched REN - Rendezvous" Oil Stabilizer Gas Processing Injection • ♦Condensate : ..................................................................... ........................................................................ Oil Sales ►Drillsite Fuel Gas Water Injection ALP NKA LO =s ALP __ rl I ANK LO ` FN '` FK NN ` ;.REN.;:- 74 `? FN rn NN = ,REN.:`- - - •Prwmad PA Attachment 1H: GMT2 Measurement Point Overview GMT2 Reinjection and MI Gas j Lift Gas t I j Fuel Gas I I TO Injector Wells GMT2 Production Metering ______________________ I GMT2 Full Flow Production Separator GMTI Reinjection and MI Gas I___________________ Lift Gas I I I I I I Fuel l Gas I I I I TO Injector ^_ I I Wells �I --------------------------- G1 N� GIPnd Mi Plpelmeslmm GMrz In t- -. Ml GMT2 GMTI Production Metering Mzonwmettr I ---------------- CBS Gas Metering I Poll `–� CDS Production 1 I I CDS Production to I ACF ma New PO I I I Pipeline jinstalled as 1ar[ofGMT2 Pro'1ec[ 00 1 j I xzonwmeM. — ______ I ____________ _I 1 .—Pop"oto(mm !OsloK ld rPO FoMbre from &Klieg PO Pipeline f— WTI to GMT2 f- --- .r WTI 1. ACr une List: Orange: Gas Green: Oil+water Blue: Separated water Black: Oil+water+gas Red: New Meters ❑Water Cut Meter and Liquid Sampling ® Coriolis Meter OOrifice Plate Meter and Gas Sampling Q Oil in Water Analyzer Alpine Central Facility Attachment 11 - GMT2 Oil Uncertainty Calculation Project: GMT2 Separator Analysis Project number: WCP.WAS.P0008.DF95PM04 Revision: 0 Prepared: Jodie L. Hosack, PE Signed: Date. July 3, 2018 Subject: Measurement Uncertainty Estimate Case: Net Volume Uncertainty for Oil in a Three Phase Measurement Application Utilizing a Coriolis Flow Meters (one line meter and one MM) and CEESI Ball Prover MM Calibration 1.0 General 1.1 Introduction 1.2 Process Parameters GMT2 Separator 1.3 Measurement Uncertainty of Net Oil Mass Flow 2.0 Measurement Uncertainty Contributors and Assumptions 2.1 Uncertainty in Primary Device (Micro Motion Coriolis) 2.2 Uncertainty in BSW Value (Phase Dynamics Analyzer) 2.3 Uncertainty in Density at Operating Conditions 2.4 Meter Factor Uncertainty Contributors 2.5 Sensitivity Analysis for Meter Factor 2.6 Uncertainty of Meter Factor 3.0 Sensitivity Analysis for Net Oil Volume Flow 3.1 Uncertainty Estimate for Net Oil Measurement 3.2 Expanded Uncertainty of Net Volume of Oil (95% Confidence Level) Page 1 of 14 1.0 General 1.1 Introduction The GMT2 production separator measurement system operates in a three phase mode. The oil measurement system comprises of dual redundant Micro Motion Coriolis flow meters installed in a parallel configuration. The combined metering stream is fitted with a fast loop and Phase Dynamics water cut analyzer which provides a means of calculating Net Oil at operating conditions. The Coriolis meter is complete with an electronic flow transmitter (which is paired with the Coriolis flow meter from calibration) and outputs a pulse signal which is applied within a flow computer against a Meter Factor (MF) using units of pulses/bbl to output a Gross Volumetric flow in bbl/day. A density measurement performed by the Coriolis meter is used in the calculation of volume flow at operating conditions. Verfication of the in-service flow meters will be conducted using a Coriolis Master Meter proving arrangement. The separator liquid flow computer further employs a net oil calculation and water calculation through the use of the Phase Dynamics water cut analyzer. Additional measurement uncertainty will be incurred for the measurement of Oil and Water due to the use of the water cut analyzer. This document constitutes a high level measurement uncertainty estimate for the Oil Coriolis measurement system in use. This measurement uncertainty report has been completed in accordance with ISO5168 and all uncertainty terms shown are expressed at the 95% confidence level This model uses the estimated flow rates for Oil taken from the Basis of Design Forecasts for GMT2. The Expanded Uncertainty is a numerical representation of the expected distribution for the majority (95%) of measured values. Page 2 of 14 1.2 Process Parameters GMT1 Separator Unit conversion for Gallons to Barrels bbl := gal • 42 W• - • • �- • �• 1 • • y• •1 • •. Netoil :=11000 bbl day Netwater:=110 bblda y BSW:=( Netwater lNetwater + Netoil TotalmixFlow := Netoil + Netwater Poll := 52 lb ft PMix:= Poll • (1— BSW) + Pwater • BSW Flow Calibration Factor (FCF) FCF:=1543234 lb 2 s At := PMix. TotalmixFlow FCF Meter Factor Determined from Onsite Proving MF := 0.998 Mass Flow Mass:=TotalmixFlow' PMix Netoil = gal �4.62.105� day Netwater = 4.62.103 ` gal day BSW=0.9901% TotaI,,d.Floa,=(4.666.10s) gal day Pwater := 61.55 lb ft pMix = 52.095 lb ft At=0.00002 s Mass= 1.354.10') Lb hr Page 3 of 14 1.3 Measurement Uncertainty of Net Oil Mass Flow The measurement uncertainty contributors considered for this high level estimate are: 1. Design Performance Estimate of Coriolis Meter 2. Density measured by the Coriolis meter at operating conditions 3. Water content measured by the Phase Dynamics analyzer Design Performance Estimate The practical implementation of the Coriolis Mass flow calculation, as taken from AGA11, is: Mass Flow in Ib/hr qm = FCF TT •FP • (At—Ato) Where: FCF = Flow Calibration Factor derived from offsite calibration FT = Temperature Compensation FP = Pressure Compensation At = Phase induced by the flowing fluid at Operating Conditions Ato = Residual phase at Zero Flow Conditions Expanding Sub -Equations: Temperature Compensation FT=1—KT -T Where: KT = Temperature Coefficient of Flow Meter T = Operating Temperature of Flow Meter Pressure Compensation FP=1+KP -P Where: KP = Pressure Coefficient of Flow Meter P = Operating Pressure of Flow Meter Page 4 of 14 2.0 Measurement Uncertainty Contributors and Assumptions In order to determine Net Standard Volume Flow the following calculations apply Where: poomi. = Density of oil at operating conditions BSW = The percentage volume of water content contained within the oil flow MF = The Meter Factor determined from onsite proving SF = The shrinkage factor associated with converting observed volume to standard volume 1011251114 �.a.-... . - i.. FTM FCF.(1—KT•T)•(1+KP•P)•(At —Ato) PMix Fully Expanded Net Oil Standard Volume calculation Netoir = FCF•(1—KT•7)•(1+Kp-P)•(At —Ato)•(1—BSL40 Poimix Shrinkage Factor used to convert observed volume to Standard Volume SF := 0.87 ESF := 2% .L . Netou := Mass . MF • (1— BSW) • SF Pmix Netoii = 9.551.103) bbl day Page 5 of 14 The Contributors to Measurement Uncertainty for the purpose of this study are taken as• 1. FCF Flow Calibration Factor determined from flow calibration facility 2. At Frequency determination as per manufacturers base accuracy data 3. BSW Water content from Phase Dynamics 4. pOilMix Mixture Density Measured at the Meter 5. MF Meter Factor determined from onsite proving The Assumptions applied within this measurement uncertainty review are as follow 1. The measurement uncertainty associated with the At term is included within the manufacturers base accuracy statement. 2. The measurement uncertainty associated with the At term is included within the flow meter zero stability and base accuracy term as supplied by the manufacturer. 3. Temperature and Pressure effects are considered negligible. 4. There are no installation effects to be considered. 5. Mixture density uncertainty is taken from the manufacturers technical specification. Page 6 of 14 2.1 Uncertainty in Primary Device EBase This is determined from the following components: EBaseAccuracy = Uncertainty in base accuracy of flow meter. EZeroStability = Uncertainty in zero stability of flow meter CalFacility = Uncertainty in calibration facility Flowrange = Flow range of specified flow meter Uncertainty in Mass flow rate as provided within the manufacturers specification Using the manufacturers technical specification as our primary source of measurement uncertainty for the flow meter in respect to Linearity, Hysterisis, and Repeatability. Base Accuracy Statement from Manufacturers Literature as a percentage of flow rate BaseA,, := 0.1 % Zero Stability of Flow Meter Expressed in Ib/min Meterstabiuty'=1.08 lb min Meterstabiiity Zstat,'= PMix Zstab=5.317bbl day Zero:= Zstab Zero=0.04786% TotalmixFlow Uncertainty in At as per Manufacturers Specification EAt:=VBaseA.,2 +Zero2 EAt=0.11086% i. �► .CEO. EFCF := 0.024% 2 2 EMass:= Eot +EFCF Page 7 of 14 Emw, = 0.11343% 2.2 Uncertainty in BSW value measured by the Phase Dynamics Analyzer The measurement uncertainty for water content shall be determined from the following uncertainty contributors: Oil Phase = The given oil continueous phase uncertainty and repeatability data for the instrument from the manufacturer Water Phase = The given water continueous phase uncertainty and repeatability data for the instrument from the manufacturer Uncertainty in the BSW Calculation The water content of the flowing fluids is obtained directly from the Phase Dynamics water cut analyser. Specifications below are those given for the Phase Dynamics low range (0-20%) water cut analyzer: BSW uncertainty is 0.2% for water cut 0-20%. BSW repeatability is 0.1% for water cut 0-20%. BSW=O.gg01% B'SWUncertainty °_ 0.275 BSWRepeatability :_ 0.1% 2 2 EBSW:= BSWUncertainty +BSWRepeatability EBSW = 0.22361% Page 8 of 14 2.3 Uncertainty in Mixture Density The measurement uncertainty for Density variables shall be determined from the following uncertainty contributors: puomi. = The density of the oil and water mixture as measured by the Coriolis Meter. Uncertainty in the oil / water density value The mixture density of the flowing fluids is obtained directly from the Coriolis Flow Meter. specifications below are those given for the Micro Motion Elite series flow meters: DensitYA..uraoy:=0.5 -k9-- 3 rn. U :=vDensit 2+Densit 2 Mix'— YAccuracy yRepeatability Umj�=0.03362 16 ft F'pMix :_ UMix IRMlx Page 9 of 14 Densit k YRepeatability :=�•2 9 M EpMix = 0.06453% Emmsmm := EM"g • Mass Epmm := EpMix , PMix EMassmut'= EM"s • Mass E' pmut :=EpMix' PMix MassMM := Mass • MF MassMUT := Mass PMM'= PMix PMUT:= PMix Massmm PMM MFc�c:= MF��,=0.998 MassMUT PMUT Page 10 of 14 2.5 2.6 Sensitivity Analysis for Meter Factor MassMM OMassMM:= d PMM OMassMM=0.02659 s dMassAm Ma'SSMUT lb PMUT MassMM OMaSSMUT:= d PMM OMassMUT=-0.02654 a dMasSMUT MassMUT lb PMUT Massmm d PMM a O PMM°- OPMM=-0.01916 ft dpMM Ma'SSMUT lb PMUT MassMM OPMUT:= I d M OPMUT=0.01916 Massfta dPMUT MUT lb PMUT Uncertainty of Meter Factor EMF:— V (EMassmm' OMaSSMM) 2 + (E,mm' OPMM) 2 + (EMassmut' OMaSSMUT) 2 + (Epmut' OPMUT) 2 EMF = 0.18433% Page 11 of 14 3.0 Sensitivity Analysis for Net Oil Volume Flow d (Mass •(1—BSW) 3 OMass :_ II MF • SF OMass = 0.0165t f dMass l PMix � lb OBSW d (Mass•(1—BSW) o;;:= -MF-SF) OBSW0i1=-281.352 gpm, dBSW � Pmiix J O _ d I(Mass•(1—BSW) fts d Poii' M�x • MF • SF I Opo;i =-0.01191 PMix 1 Plb • s J OMF:= d I(IMass•(1—BSW) •MF•SF) OMF=279.125 gpra dMF \ PMix OSF:= d (Mass•(1—BSW) •MF•SFl I J OSF=320.192 gpm dSF \ PMx 3.1 Uncertainty Estimate for Net Oil Measurement Input Uncertainty Distribution Coverage Factor (K) EMa. = 0.11343% Normal KMaaa := 2 EBBW = 0.22361% Normal KBsw:= 2 EFMix = 0.06453% Normal Kpoi1:= 2 EMF = 0.18433% Normal Kmp:= := 2 EsF = 2% Normal KSF := 2 Page 12 of 14 StdMasa :_ Um"S KMass StdMF:=EMF — KMF StdBsw:= EBsw KBsw Stdpoil ;= Fpm._K poil StdsF:=EsF — KsF Sensitivi 3 OMass=0.017 ft Ib OMF = 279.125 gpm OBSWOil=-281.352 gpm OPoil=-0.012 - Lt s lb -s OSF=320.192 gpm Relative Standard Uncertainty Stdm83 =0.05672% StdMF = 0.09216% StdBSW = 0.1118% Stdpoil = 0.03227% StdSF =1% Absolute Standard Uncertainty_ Variance 2 Varmms = (Um. • OMass) z VarMF := (UMF - OMF) UMass := Mass • StdMass UMF:= MF • StdMF UBsw := Netwat�r • StdBsw Upoil := pMix"Stdpoil USF:=SF • StdsF VarMass=0.02496 gpm2 VarMF=0.06592 gpm2 VarBSW1=(StdBsw-OBSWoii)2 VarBSW=0.09895 gpm2 2 Varpoil := (Upoll • OPoll) 2 VarsF:= (USF • OSF) Page 13 of 14 Varpoil=0.00808 gpm2 VarSF = 7.75994 gpm2 Sum of Variances Sumvariance := Varmws + VaXMF•+ Varssw+ VarPoil + VarsF Snmvariance-7.95785 gpmz Combinedstandard_Uncertainty'= `5umvariance Combinedstandard_Uncertainty=2.821 gp'in Relative Standard Uncertainty �'.,ombinedstandard_Umertainty Escd:= NetOi1=278.567 Spm Netoil 3.2 Expanded Uncertainty of Net Standard Volume of Oil (95% Confidence Level) Expanded Uncertainty (95% Convidence Level) Expandeduncertaincy:=Estd' 2 Expandeduncertainty = 2.02534% UnCharrels:= ExpandedUncertainty-Netoil'1 dna✓ Barrels:= Uncbarrels 42 gal Page 14 of 14 UnCb�rels=8.124.103) gal Barrels =193.438 120% 100% 80% 60% 40% a Z 20% 0% -20% -40% Current Value Four Year Delay Facility Cost Operating Cost (No PF) Revised Value (PF) Range of Possible Outcomes • Production Facility impacts (besides potential for negative NPV) would move GMT2 project to the bottom 10% of projects in COP's global portfolio and thus not compete for capital • Production Facility adds -$800 MM in capital, -$40 MM /year in annual expense, and will delay production at least four years to achieve LACT quality measurement ConocoPhillips ConocoPhillips Alaska GMT2 Development & Measurement Approval Request Overview ATTACHMENT 2 Other Order 112A(12/22/2016) 10 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7" Avenue Anchorage, Alaska 99501 Re: THE APPLICATION OF ) Docket No. OTH 16-005 ConocoPhillips Alaska, Inc. for a waiver of ) Other Order No. 112 the requirements of 20 AAC 25.228(a) to ) Greater Moose's Tooth Unit provide custody transfer measurement of ) Greater Moose's Tooth 1 Pad hydrocarbons prior to severance from the ) North Slope Borough, Alaska lease or unit. ) October 12, 2016 IT APPEARING THAT: By a letter received February 26, 2016, ConocoPhillips Alaska, Inc. (CPAI) requests the following waivers to the requirements of 20 AAC 25.228(a) to provide custody transfer measurement of hydrocarbons associated with the planned development of the Greater Moose's Tooth (GMT) Unit; a. Utilize a coriolis-based metering system at GMT Pad 1 (GMTI) to allocate GMT Unit production to GMTI; production would be commingled with Colville River Unit (CRU) production and shipped to the Alpine Central Facilities (ACF) for processing to pipeline quality requirements and final sales measurement; b. Utilize a gas measurement system installed at GMTI instead of within CRU for gas transferred from the Colville River Unit (CRU) to GMTI. Pursuant to 20 AAC 25.540, the Alaska Oil and Gas Conservation Commission (AOGCC) tentatively scheduled a public hearing for May 3, 2016. On March 31, 2016, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, and electronically transmitted the notice to all persons on the AOGCC's email distribution list. On April 6, 2016, the AOGCC mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. 3. The hearing was held as scheduled on May 3, 2016. Testimony was received from CPAI. At the conclusion of the hearing the record was held open until June 3, 2016 so that CPAI could respond to questions and data requests made during the hearing. On June 1, 2016 the hearing deadline for CPAI to submit the additional information was extended to June 10, 2016. 4. On June 3, 2016, CPAI submitted written responses to the questions raised during the May 3, 2016 hearing. 5. On June 3, 2016, the Arctic Slope Regional Corporation (ASRC) submitted comments in support of CPAI's application. 6. On June 9, 2016, CPAI provided the AOGCC with access to a data room so that project economic data could be reviewed. Other Order 112 October 12, 2016 Page 2 of 4 FINDINGS: 1. CPAI is the operator of the GMTU and CRU located within the North Slope Borough, Alaska. Working interest owners (WIOs) of the GMTU are CPAI and Anadarko Petroleum Corp. (Anadarko). WIOs of the CRU are CPAI, Anadarko and Petro -Hunt, LLC. 2. The GMTU landowners are the United States Bureau of Land Management (BLM) and ASRC. The CRU landowners are Department of Natural Resources, BLM, and ASRC. 3. CPAI proposes to install a single stage three phase separator to support measurement of production leaving the GMTI development. The oil leg coming off the three phase separator will be metered with a coriolis meter and water cut analyzer; the gas leg will be metered by a pair of orifice meters sized to measure the full range of expected flow. After metering the oil and gas flow streams will be recombined before being shipped to Colville Delta Pad 5 (CD5) and commingled with the CRU production gathering system. 4. The commingled GMTU and CRU production will be processed to pipeline sales quality specifications at the ACF and then metered at the CRU lease automatic custody transfer (LACT) sales meter before shipping to market. 5. CPAI proposes that the production allocation factor for GMTI be fixed at 1.0. Thus the oil production allocated to the CRU would be the volume measured by the CRU LACT meter minus the volume measured through the Coriolis meter coming off the three phase separator at GMT I. 6. The dual orifice meters coming off the three phase separator at GMTI will serve as the gas sales meter for gas shipped from GMT 1 to the CRU. 7. CPAI testifies that gas will need to be shipped to GMTI from CRU for fuel and rich miscible gas injection. CPAI proposes to install orifice gas meters at GMT] instead of within the CRU, stating operational and space constraints at CD5 are the basis of their request for the waiver of requirements to measure before severance of production from the property or unit where produced. 8. CPAI maintains that stand alone production facilities at GMTI would be necessary to process the production to pipeline sales quality before custody transfer quality metering could occur as required 20 AAC 25.228(a). 9. CPAI testified that a standalone processing facility at GMTI would cost in the neighborhood of $500 million. Using a 10 percent rate of return and the Alaska Department of Revenue's price forecasts, CPAI states this would make the project uneconomic. 10. CPAI provided the AOGCC access to a data room to review confidential project specific economics. The information made available to the AOGCC included a cost estimate prepared for CPAI by Turner & Townsend Larkspur (TTL), a company with extensive experience preparing conceptual project cost estimates for CPAI and other operators on the North Slope. TTL bases its estimates other costs estimates they've prepared and recently completed projects as bench marks when they prepare new cost estimates. 11. CPAI stated the recently commissioned CD5 drillsite was not designed to house a sales gas metering system for gas sales to GMTI and would require modifications to incorporate one. 12. On April 21, 2016, CPAI announced it would fund additional wells and install additional on- pad infrastructure at CD5 to allow for expanded production from the pad'. ' hqp•//alaska conocophillius com/newsroom/Documents/NR-AK-CD5%20EUansion-Apr°/202016 FINAL odf Other Order 112 October 12, 2016 Page 3 of 4 CONCLUSIONS: An exception to 20 AAC 25.228 is necessary to allow for final custody transfer quality metering of oil production from GMTI to occur after the production has been severed from the unit and commingled with production from the CRU before being processed at ACF and metered for sale at the CRU LACT meter. 2. An exception to 20 AAC 25.228(a) is necessary to allow the custody transfer measurement point for gas transferred from CRU to GMTI to be at a location after the gas has been severed from the CRU. 3. CPAI's cost estimate was very thorough, including items such as timing of expenditures and contingencies for various components of the project. The estimate is sufficiently detailed to provide a valid basis upon which to assess the basis for CPAI's request. 4. The evidence presented demonstrates that a stand-alone production facility at GMT] in the current economic environment would not be pursued by CPAI. The reserves at GMTI would not be produced for the foreseeable future. 5. Failure to develop GMTI would likely lead to a failure to develop the four GMTU other participating areas for the foreseeable future. 6. A waiver of the requirements of 20 AAC 25.228 that requires custody quality metering to occur before oil or gas is severed from a lease or unit is necessary in order to allow the maximization of recovery from GMT]. 7. Referring to the location of the CRU-to-GMTI gas custody transfer meters, CPAI testified that a variance to the requirement to measure before severance from the property or unit where produced (i.e., CRU) would be simpler and cheaper. CPAI has not provided factual evidence in support of its assertions. 8. Assigning an allocation factor of 1.0 to the three phase separator and metering system at GMTI makes the assumption that the GMTI metering system is 100% accurate. Any error in that system would be applied to CRU production. This would result in one -unit over - reporting production while the other unit under -reports. Since the landownership of the two units is different this would result in landowners being over or under paid for royalties for production from their lands. Of the landowners only the ASRC has commented on the record in support of or opposing the proposed meter allocation factor for GMTI . 9. There is insufficient information available at this time to demonstrate that the mineral rights owners of the two units fully understand the implications of assigning a fixed allocation factor to one unit while the other unit has a floating allocation factor and thus the AOGCC needs to gather more information before a decision on the GMTI allocation factor can be made. 10. Additional information on the specifics of the meter system design is necessary before those components can be approved. NOW THEREFORE IT IS ORDERED: CPAI's request for a waiver of the requirements of 20 AAC 25.228 to allow for fiscal allocation of production from the GMTI to be based on a metering system that does not meet custody transfer quality standards is hereby APPROVED. Other Order 112 October 12, 2016 Page 4 of 4 2. CPAI's request for a waiver of the requirements of 20 AAC 25.228(a) to allow for the custody transfer metering of gas sold from CRU to GMT] at a point after the gas is severed from the CRU is hereby DENIED without prejudice to CPAI renewing the request when it can provide additional evidence in support of the request. 3. The specific design of the fiscal allocation metering system must be approved by the AOGCC before being installed and operated. The specific design for the gas measurement system to measure gas sold from the CRU to GMT] must be approved by the AOGCC before being installed. Refer to AOGCC Industry Guidance Bulletin 13-002 for details regarding the measurement application(s). DONE at Anchorage, Alaska and dated October 12, 2016. //signature on file// //signature on file// Cathy P. Foerster Daniel T. Seamount, Jr. Chair, Commissioner Commissioner As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 3L05.080(b), "[tlhe questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7" Avenue Anchorage, Alaska 99501 Re: THE MOTION OF the Alaska Oil and ) Docket No. OTH 16-025 Gas Conservation Commission to provide ) Other Order No. II2A potentially affected landowners the ) Greater Moose's Tooth Unit opportunity to comment on ConocoPhillips ) Greater Moose's Tooth IPad Alaska, Inc. to set the meter allocation factor ) North Slope Borough, Alaska for the Greater Moose's Tooth 1 ) development at 1.0 ) December 22, 2016 IT APPEARING THAT: 1. On its own motion the Alaska Oil and Gas Conservation Commission (AOGCC) called a hearing for the purpose of accepting testimony from potentially affected landowners on the issue of whether or not the meter allocation factor for ConocoPhillips Alaska, Inc.'s (CPAI) Greater Moose's Tooth 1 (GMTI) development should be set at 1.0. 2. Pursuant to 20 AAC 25.540, the AOGCC tentatively scheduled a public hearing for November 17, 2016. On October 12, 2016, the AOGCC published notice of the opportunity for that hearing on the State of Alaska's Online Public Notice website and on the AOGCC's website, electronically transmitted the notice to all persons on the AOGCC's email distribution list, and mailed printed copies of the notice to all persons on the AOGCC's mailing distribution list. On October 14, 2016, the notice of the hearing was published in the Alaska Dispatch News. 3. On October 31, 2016, the Department of Revenue (DOR) requested that the hearing be held as scheduled. 4. The hearing was held as scheduled on November 17, 2016. Testimony was received from CPAI and DOR. At the conclusion of the hearing the record was held open until November 28, 2016, so that CPAI could respond to questions and data requests made during the hearing and so the potentially affected landowners could provide comments. On November 23, 2016, the hearing deadline was extended to December 19, 2016. 5. Comments were received from the Bureau of Land Management (BLM) on November 28, 2016, from Arctic Slope Regional Corporation (ASRC) on December 1, 2016, from CPAI on December 8, 2016, from the Department of Natural Resources (DNR) on December 16, 2016, and from DOR on December 19, 2016. FINDINGS: 1. CPAI is the operator of the GMTU and CRU located within the North Slope Borough, Alaska. Working interest owners (WIOs) of the GMTU are CPAI and Anadarko Petroleum Corp. (Anadarko). WIOs of the CRU are CPAI, Anadarko and Petro -Hunt, LLC. 2. The GMTU landowners are the BLM and ASRC. The CRU landowners are DNR, BLM, and ASRC. 3. The DOR is not a landowner, but is responsible for tax collection from the GMTU and CRU for the State of Alaska. Other Order 112A December 22, 2016 Page 2 of 3 4. The ASRC and BLM both provided comments in support of establishing the meter factor for the GMTI metering system at 1.0. 5. The DNR and DOR both provided comments saying they did not object to establishing the meter factor for the GMTI metering system at 1.0. CONCLUSION: All of the potentially affected parties have provided comments that support, or at the very least does not object to, establishing the GMTI metering system meter factor at 1.0. Since none of the potentially affected parties believe they'll be adversely impacted if the meter allocation factor is set at 1.0 there is no reason for the AOGCC to reject CPAI's request to set the GMT] meter allocation factor to 1.0. NOW THEREFORE IT IS ORDERED: The record Other Order No. 112 is incorporated by reference and Other Order No. 112 is amended to read as follows: CPAI's request for a waiver of the requirements of 20 AAC 25.228 to allow for fiscal allocation of production from the GMTI to be based on a metering system that does not meet custody transfer quality standards is hereby APPROVED. CPAI's request for a waiver of the requirements of 20 AAC 25.228(a) to allow for the custody transfer metering of gas sold from CRU to GMTI at a point after the gas is severed from the CRU is hereby DENIED without prejudice to CPAI renewing the request when it can provide additional evidence in support of the request. 3. The specific design of the fiscal allocation AOGCC before being installed and operated. system to measure gas sold from the CRU 1 before being installed. Refer to AOGCC regarding the measurement application(s). In metering system must be approved by the The specific design for the gas measurement o GMTI must be approved by the AOGCC dustry Guidance Bulletin 13-002 for details 4. The meter allocation factor for the GMTI metering system shall be set at 1.0. u,01Lq.�.O DONE at Anchorage, Alaska and dated December 22, 2016. & //signature on file// //signature on file// ON Daniel T. Seamount, Jr. Hollis French Commissioner Commissioner Other Order 112A December 22, 2016 Page 3 of 3 As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The AOGCC shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is adenial of reconsideration. If the AOGCC denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the AOGCC grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the AOGCC, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the AOGCC mails, OR 30 days if the AOGCC otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the AOGCC by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to mn is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. ConocoPhillips Alaska GMT2 Development & Measurement Approval Request Overview ATTACHMENT 3 GMT2 Measurement Application Package for BLM 11 ConocoPhillips Alaska July 12, 2018 Mr. Wayne Svejnoha Bureau of Land Management 222 W. 7th Avenue, #13 Anchorage, AK 99513 Brandon Viator Project Integration Manager-GMTU ConocoPhillips Alaska 700 G Street Anchorage, AK 99501-3439 Phone 907.263.4653 RE: Request for Approval - Oil Measurement by Other Methods and Redundancy Verification of Oil Measurement Secondary Pressure and Temperature Instruments Greater Mooses Tooth Unit (Rendezvous) BLM No. AA 087852; CPA] No. 204278 Dear Mr. Wayne Svejnoha: ConocoPhillips Alaska, Inc. (ConocoPhillips), as the sole working interest owner and Unit Operator of the Greater Mooses Tooth Unit (GMTU), requests, pursuant to 43 CFR 3174.13, approval of oil measurement by other methods for Greater Mooses Tooth #2 (GMT2) Rendezvous oil production. See Attachment 1, GMT2 Measurement Application Request. ConocoPhillips is requesting approval of the same measurement methodology that was approved for Greater Mooses Tooth #1 (GMT1) Lookout Participating Area. See Attachment 2 (Approved Sundry Notice for GMT1 Oil Measurement by Other Methods dated 10/14/2016). The proposed GMT2 measurement system includes a 3-phase production separator providing continuous measurement of GMT2 production using a Coriolis meters and water cut analyzer. In addition to the request for measurement approval under 43 CFR 3174.13 "Oil Measurement by Other Methods," this application also requests approval for the use of redundancy verification of oil measurement secondary pressure and temperature instruments at GMT2. BUM approved redundancy verification of oil measurement secondary pressure and temperature instruments for GMT1 by sundry. See Attachment 3 (approved Sundry Notice for Redundancy Verification dated 1/25/2018). Attachment 1 to this letter is a detailed explanation of the project, and an explanation of why oil measurement by other methods and redundancy verification of oil measurement secondary pressure and temperature instruments should be approved. As reference, ConocoPhillips has also included with this submittal a copy of our GMT2 measurement application package that will be submitted concurrently to the Alaska Oil and Gas Conservation Commission. See Attachment 4. If you have questions or need additional information, please contact me at 907-263-4653. Sincerely, Brandon Project Integration Manager - GMTU ConocoPhillips Alaska ConocoPhillips Alaska GMT2 Development & Measurement Approval Request Overview Attachments: Attachment 1: GMT2 Measurement Application Request Attachment 2: GMT1 Oil Measurement by Other Methods Approval (10/14/2016) Attachment 3: GMT1 Measurement and Redundancy Verification Approval (1/25/2018) Attachment 4: GMT2 Measurement Application Package for AOGCC ConocoPhillips Alaska GMT2 Development & Measurement Approval Request Overview ATTACHMENT 1 GMT2 Measurement Application Request V_' ConocoPhillips Alaska GMT2 Development & Measurement Approval Request Overview Oil Measurement by Other Methods and Redundancy Verification of Oil Measurement Secondary Pressure and Temperature Instruments Contents: A. Requested Approvals.......................................................................................................................3 1. Oil Measurement by Other Methods Approval.................................................................................3 2. Redundancy Verification of Oil Measurement Secondary Pressure and Temperature Instruments ... 3 B. GMT2 Project Description................................................................................................................3 C. Proposed GMT2 Flow Measurement & Metering Description..........................................................4 1. Custody Transfer/Point of Royalty Metering and Oil Measurement..................................................4 2. Gas Measurement...........................................................................................................................5 3. Operation and Maintenance of Measurement Equipment...............................................................6 D. Rationale for Oil Measurement by Other Methods...........................................................................6 1. Provides Accurate Measurement.....................................................................................................6 2. Minimizes Environmental Footprint and Makes the Project Economic.............................................8 E. Conclusion.......................................................................................................................................9 Figures: • Attachment 1A—GMT2 and CRU Map (Gathering System) • Attachment 1B—GMT2 leases, preliminary PA, and proposed wells • Attachment 1C—GMT2 lease ownership, royalty rate, and allocation factor • Attachment 1D — GMT2 drillsite site plan • Attachment 1E — GMT2 drillsite process flow diagram • Attachment 1F — GMT2 production separator measurement system • Attachment 1G —ACF simple process flow diagram • Attachment 1H —GMTU Measurement Point Overview • Attachment 11—Uncertainty Calculation • Attachment 11—Oil Secondary Instrument Redundancy Verification • Attachment 1K—Production Facility Economic Impacts 2 ConocoPhillips Alaska A. Requested Approvals 1. Oil Measurement by Other Methods Approval GMT2 Development & Measurement Approval Request Overview ConocoPhillips requests Bureau of Land Management (BLM) approve oil measurement by other methods pursuant to 43 CFR 3174.13 for the Greater Mooses Tooth #2 (GMT2) oil measurement system, described below. The GMT2 measurement system is based on the Greater Mooses Tooth #1 (GMT1) measurement system design that was previously approved by BUM. GMT2 production will be measured continuously prior to being commingled with GMT1 and Colville River Unit (CRU) production, and like GMT1 will be given an allocation factor of 1.0 at the CRU LACT meter. 2. Redundancy Verification of Oil Measurement Secondary Pressure and Temperature Instruments This application is also requesting approval for the use of redundancy verification of oil measurement secondary pressure and temperature instruments. The proposed oil measurement redundancy verification described follows the requirements codified in 43 CFR 3175.102(d) of the Measurement of Gas rules and in API 21.1 Subsection 8.2. B. GMT2 Project Description The GMT2 project will develop the second drill site in the Greater Mooses Tooth Unit (GMTU) which is in the northeast corner of the National Petroleum Reserve — Alaska (NPR -A). The GMT2 project consists of the construction of a planned drillsite, access road, pipelines, power lines, bridges, and ancillary facilities for recovery of petroleum resources within the GMTU. The GMT2 drillsite will be located 25 miles southwest of the CRU CD1 drillsite and the Alpine Central Facility (ACF). The GMT2 project will develop Arctic Slope Regional Corporation (ASRC) leases and BUM federal leases from an oil accumulation formed by a stratigraphic trap of Upper Jurassic sandstones (Alpine C sandstone equivalent) similar to what has been developed at CD1. The GMT2 satellite was discovered in 2000 by the Rendezvous A well. Rendezvous 2 (2001) and Rendezvous 3 (2014) wells were drilled and used for reservoir delineation. The GMT2 project will provide sufficient infrastructure to support development of up to 48 wells. The proposed GMT2 infrastructure will tie back to the CRU and will be the sixth satellite developed through the ACF following development of the Qannik CD2, Fiord CD3, Nanuq CD4, Alpine West CDS, and Lookout GMT1 satellites (see Attachment 1A). The project will produce 3-phase fluids (oil, gas, and water) which, after measurement at the GMT2 drillsite, will be carried by pipeline to the CRU ACF at CD1 for processing. Water and gas will be returned to GMTU by pipeline to support enhanced oil recovery of GMTU resources. Sales -quality crude oil produced at the ACF will be transported via the existing Alpine Sales Oil Pipeline and Kuparuk Pipeline to the Trans -Alaska Pipeline System (TAPS) for shipment to market. Development and production of hydrocarbons from GMT2 will help offset declines in production from the Alaskan North Slope and maintain throughput of TAPS. Development will also provide benefits to local, state, and national economies through local hire for jobs created 3 ConocoPhillips Alaska GMT2 Development & Measurement Approval Request Overview during construction and operations, tax revenues, revenue sharing, royalties, and new resources to help meet US domestic energy demand. The GMT2 development is expected to employ up to 700 people during the peak of construction and result in new full-time positions upon startup. The map and figures included as Attachments 1A, 1B, and 1C, show the GMTU leases, proposed development wells, conceptual unit participating area (PA), and lease ownership percentages. The map and figures illustrate how GMT2 pipelines tie back to GMT1 and the CRU. The GMT2 development drillsite consists of nine process modules and a well row. The process modules consist of a pig launcher/receiver module, production heater, test separator/ sand handling module, remote electrical & instrumentation module (REIM), emergency shutdown module (ESD), chemical injection module, fuel gas conditioning skid (fuel gas is supplied to the drillsites from the ACF), metering module, and a production separator system which will be used as the GMT2 point of royalty. Attachment 1D, the proposed GMT2 site plan, displays the layout of the drillsite infrastructure. Attachment 1E provides a GMT2 drillsite process flow diagram and Attachment IF provides additional detail on the GMT2 production separator measurement system. The ACF simplified process flow diagram is shown in Attachment 1G. The ACF separates and processes well bore fluids from the associated drillsite facilities and delivers sales -quality crude oil into the common carrier oil pipeline system that leads to the TAPS. ACF processed produced water is returned to the CRU drillsites for re-injection into the producing formations to maintain reservoir pressure and provide secondary flood support. Seawater or produced water will be delivered to GMT1 and GMT2 for pressure maintenance. ACF processed gas is: (i) used to fuel plant and drillsite facility equipment, (ii) provided to the Village of Nuiqsut, (iii) re -injected into CRU and GMTU reservoirs to maintain reservoir pressure for increased recovery, and (iv) used for gas lift. C. Proposed GMT2 Flow Measurement & Metering Description 1. Custody Transfer/Point of Royalty Metering and Oil Measurement The GMT2 produced oil and gas custody transfer/Point of Royalty Measurement (PRM) system is designed similar to the GMT1 system. The GMT2 system will consist of a horizontal vessel which will operate as a three-phase separator (vapor/water/oil). Vessel internals will consist of an inlet cyclonic separator, liquid coalescer, weir (three-phase operation), mist extractor on the gas outlet, vortex breaker and sand -jet system. The GMT2 returned gas custody transfer/PRM system will utilize the return gas meters installed with GMTI and located at CD5, shown on Attachment 1H. Additional gas measurement at GMT1 and GMT2 will be utilized to allocate the return gas flows between GMT1 and GMT2 (Lookout and Rendezvous Participating Areas, respectively). The method of allocation will be covered under the GMTU Gas Management Agreement. Shrinkage factors (SF) will be utilized to convert live oil drillsite flowrates to standard conditions and will be developed across a range of operating pressures and temperatures so that process variances 4 ConocoPhillips GMT2 Development & Measurement Alaska Approval Request Overview are captured to prevent a systematic bias impacting the measurement of oil. The same methodology used at GMT1 will be used for GMT2. An on-line water cut analyzer in the sampling fast loop will be utilized to measure water in the oil outlet PRM, identical to GMT1. It is anticipated that the water content flowing through the oil leg of the production separator will not exceed 10% by volume at any point in field life. The oil metering system for GMT2 is based on the GMT1 system. The GMT2 metering system will consist of a Micro Motion Elite Coriolis master meter in series with two Micro Motion Elite Coriolis line meters installed in a parallel configuration. (The proposal for GMT2 is to have 2 x 100% meters. The GMT2 meters are the next size larger model than installed for GMT1.) The project is also considering a 3 x 50% meters configuration for GMT2, which would utilize identical Coriolis meters as GMT1. Regardless of the selected meter configuration, the Coriolis in-service line meters are sized to handle the full range of expected normal operating flow rates from GMT2 and includes jet mixing and sampling extractor for the composite sampling system, pressure and temperature instrumentation and control valves. One line meter is expected to be in operation at any point, with the other as an in- line spare. An automatic flow proportional sample system will be installed to permit collection of representative oil samples for laboratory analysis. A common composite sampling system with a water cut analyzer in the fast loop will be manifolded to the two parallel line meters. All flow measurement information will be fed to a dedicated flow computer to calculate net oil volume and evolved gas at standard conditions through application of a shrinkage factor. An oil -in -water analyzer will be installed on the water outlet. Simplified process flow diagrams of the GMT2 production separator and oil metering system are shown in Attachment 1F. 2. Gas Measurement Gas will be measured in accordance with applicable regulations, and no special approval or waiver is being requested. See 43 CFR 3175.10 et seq. As shown in Attachments 1E, 1F, & 1H total gas will be measured at GMT2 before being sent to the ACF for processing. The conditioned GMT2 gas will then be sent back to GMT2 for use as fuel, injection and artificial lift. Excess gas not used for fuel at ACF and not returned to GMT2 will be transferred to CRU and injected into CRU participating areas for enhanced oil recovery. A metering module at the CDS drill site will measure gas being sent back to GMTU for reinjection, lift and fuel at the GMT1 and GMT2 drill sites. As described above, the return gas allocations will be covered under the GMTU Gas Management Agreement. (i) Production Separator Gas Metering The production separator gas outlet metering system will be similar to GMT1. The GMT2 gas metering system will include two meter runs, which will cover the range of normal operating gas flowrates from the drill site. Conceptually this will be accomplished by two similar AGA compliant orifice meter runs of different size. GMT1 includes a 6 inch and 10 inch orifice meter run, while GMT2 is proposing a 6 5 Conoco Phillips GMT2 Development & Measurement Alaska Approval Request Overview inch and 12 inch run due to higher forecasted gas rates. Additionally, the two meter runs provide a level of redundancy to help ensure improved drill site uptime. Fully redundant meter runs are not necessary due to the highly reliable orifice metering technology and the relatively minimal maintenance down time to repair orifice meters. Each meter run will consist of upstream and downstream meter tubes, flow conditioner, senior orifice fitting and plate, pressure and temperature transmitters and control valve. A flow computer, DP Diagnostics, and a differential pressure diagnostic system will be installed on the gas meter runs to monitor the gas metering systems. Automatic flow proportional gas composite sampling systems will also be installed to collect representative produced gas samples for laboratory analysis. (ii) Drill Site Gas Metering Attachment 1H shows the GMTU Measurement Points currently anticipated to support custody transfer and reporting requirements. 3. Operation and Maintenance of Measurement Equipment The operation and maintenance program for measurement equipment will be based on the GMT1 operation and maintenance program. CPAI requests approval for redundancy verification for PRM oil measurement secondary pressure and temperature instruments equipment. CPAI proposes oil measurement redundancy verification following the requirements in 43 CFR 3175.102(d) of the Measurement of Gas rules, API 21.1 Subsection 8.2 and BLM's previous approval for GMT1. See Attachment L — Oil Secondary Instrument Redundancy Verification. (i) Sampling Sampling philosophy will be consistent with the GMT1 design and will follow all applicable BLM and AOGCC regulations. (ii) Well Allocation Methodology Each well will be tested in the Test Separator once per month and that data used in conjunction with the 3-phase separator to determine well allocation at GMT2. Net standard volumes will utilize this metering allocation information for royalty payment data. D. Rationale for Oil Measurement by Other Methods 1. Provides Accurate Measurement The need for oil measurement by other methods stems from the design of GMT2 as a satellite drill site that will deliver three-phase production to Alpine Central Facilities (ACF) for separation and processing. Accordingly, the measurement of hydrocarbon liquids will occur at elevated temperature and pressure which are not stable under the requirements of the American Petroleum Institute (API) Manual of Petroleum Measurement Standards (MPMS) chapter 6.1 Metering Assemblies - Lease 0 ConocoPhNpis Alaska GMT2 Development & Measurement Approval Request Overview Automatic Custody Transfer (LACT) Systems (2012), which is made applicable by 43 CFR § 3174.3(b)(14). Standard volume is not a wholly measured parameter; it is a parameter derived from a measurement of volume at operational conditions which is then converted by means of empirical or laboratory analysis data to a volume at standard conditions. The conversion of stable fluids from observed volume to standard volume is achieved using Volume Correction Factors (VCF) derived from tables and calculations created by the API and which have an uncertainty budget in the region of +/- 0.1%. The conversion of live fluids from observed volume to standard volume is achieved through the application of a Shrinkage Factor (SF) which is derived from laboratory pressure, volume and temperature (PVT) testing or equation of state (ECS) modeling based upon detailed compositional analysis. The conversion of volume at operational conditions to volume at standard conditions will incur a penalty of +/-0.1% when applied to stabilized fluids and a penalty of +/-2% when applied to live fluids. Table 2 below provides an illustration of the comparable measurement uncertainties for stable and live fluids. Table 2 — Comparable Measurement Uncertainties 7 Flow Meter Base Flow Meter Base Accuracy plus Pressure Accuracy plus Mass 0.15 Mass 0.16 Pressure and and Temperature Temperature Corrections Corrections Mass Uncertainty plus Mass Uncertainty plus Observed Observed Volume 0.25 Observed Density Volume 0.27 Observed Density Uncertainty Uncertainty Mass Uncertainty, Mass Uncertainty, Observed Density Observed Density Standard Uncertainty Plus Standard Uncertainty Plus Volume 0.35 Conversion to Volume 205 Conversion to Standard Volume Standard Volume Uncertainty (VCF) Uncertainty (SF) 7 ConocoPhillips GMT2 Development & Measurement Alaska Approval Request Overview It is important to note that the differences in performance in determining Standard Volume between the BLM rule requirements and ConocoPhillips' proposed metering system design are not related to the base accuracy of the flow meters or hardware components of the metering system. The ConocoPhillips proposed measurement system design, utilizing Coriolis flow meters, will meet the BLM performance requirements for the measurement of Mass and Gross Observed Volume but will not meet the performance standard required for Standard Volume. The measurement uncertainty estimate for GMT2 oil production is provided as Attachment 11 of this document where a maximum value of +/- 2.03% at 95% confidence level has been determined using the 2 x 100% meter configuration. The 3 x 50%meter configuration would result is an uncertainty of approximately 2.05%. The calculations required to determine Net Standard Volume are also contained within the uncertainty calculation provided in Attachment 11. Flow meter verification is accomplished by monthly proving of the line meters against the master meter per API MPMS and BLM proving standards. The Coriolis meters will also implement Smart Meter Verification (SMV) functionality, which permits automated and online verification of the flow meters. The results of the SMV verifications are trended over time and provide traceable evidence of meter performance within defined manufacturer limits. The Coriolis master meter will be sent off site for master meter proving initially after three months and annually after that per BLM Measurement of Oil regulations. 2. Minimizes Environmental Footprint and Makes the Project Economic The Naval Petroleum Reserves Production Act of 1976 (NPRPA) authorizes and directs the Secretary of the Interior to "further explore, develop, and operate" the National Petroleum Reserve -Alaska (NPR -A) (10 USC Section § 7422[c]). The GMT2 Development Project promotes the exploration and development of oil and gas resources in the NPR -A. Specifically, the NPRPA, as amended, encourages oil and gas leasing in the NPR -A while requiring protection of important surface resources and uses. One of the key aspects of this approach is the utilization of the existing installed processing capacity at the ACF. The current GMT2 Development Project seeks to minimize environmental impacts by leveraging existing infrastructure where available to avoid redundancy and waste. Facility sharing for GMT1 and GMT2 at Alpine was required and approved by BLM. Specifically, the Interior Secretary's Record of Decision provided that NPR -A developments to share facilities with existing developments to minimize project footprint. See 2/21/2013 ROD at Stipulation E-5. Similarly, the Continuing Development Obligations for GMT2 provide for handling of GMTU production at ACF. See, e.g., BLM Approval of 91h GMTU CDO (10/16/2017). 93 ConocoPhillips Alaska GMT2 Development & Measurement Approval Request Overview The use of ACF to process GMT2 production greatly reduces the environmental footprint of GMT2 by eliminating the need for a standalone GMT2 processing facility capable of producing sales -quality crude oil. Without approval of an alternative oil measurement method, a processing facility would have to be built as part of the proposed project to accommodate custody transfer metering prior to sales -quality crude leaving the lease or unit PA. Significantly, the measurement system submitted for approval for GMT2 is based on the system that was approved by the AOGCC and BLM for the GMT1 Satellite. The estimated incremental environmental and cost impacts associated with building a new processing facility are significant in nature. Environmental impacts include —8-10 additional acres of gravel to house a processing facility, and increased air emissions due to additional electric power generation, gas compression, and flare requirements. The incremental unescalated costs for building a processing facility for a single PA at the GMT2 site are estimated to be within a range of $700 - $900 million. If multiple PAs are produced at GMT2, some utilities and equipment may be shared, but the separation and compression systems will be needed for each PA. This will result in additional capital on the order of $400 - $500 million per additional PA. A related consideration that should be taken into account when evaluating this proposal is the viability of permitting a development which does not allow oil measurement by other methods. Permitting agencies and stakeholders are keen on reducing any impacts to the environment and subsistence lifestyle of local native residents. The wetlands fill permit for the GMT2 project was designed for a satellite drill site that relies on existing ACF infrastructure for processing. That permit is expected to be approved by the United States Army Corps of Engineers as the Least Environmentally Damaging Practicable Alternative (LEDPA). Changing course to install a new processing facility at GMT2 would likely result in a 4 -year delay to first oil resulting in deferred economic benefit to the BLM, the State of Alaska, and ASRC. Attachment 1K shows that the cost to add a processing facility to the GMT2 scope would result in an uncompetitive project and would not be sanctioned by ConocoPhillips, stranding valuable resource that is otherwise ready to be developed. In summary, installing a process facility to meet measurement requirements has significant environmental and cost impacts, which would lead to project delays and could potentially lead to other consequences including reconsideration of economic viability. CPAI strongly believes that overriding considerations merit the approval of oil measurement by other methods for GMT2 similar to what was previously approved for GMT1. E. Conclusion CPAI requests that BLM approve oil measurement by other methods for the GMT2 project. It is not practicable to meet the oil measurement requirements of 43 CFR § 3174, and the proposed measurement methodology will result in accurate measurement which will protect all interested parties. CPAI also requests approval for the use of redundancy verification of oil measurement secondary pressure and temperature instruments. 0 Attachment 1A: GMT2 and CRU Map (Gathering System) • Exploration Well SHL ..-.� 'E Road or Pad -'�•-' "•"'`•% — Pipeline `•--.' OAK Unit t!NPR-A N A T I O N A L P E T R O L E U M R E S E R V E - A L A S K A GMT2�i • Colville River Unit CD5 Greater Mooses Tooth Unit CD3 CD2 COi CD4 i r Alaska Greater Mooses Tooth Unit N and Colville River Unit Roads, Pads, 8 Pipelines o 1 2 Miles 3/2012018 Attachment 1B: GMT2 Conceptual PA, Wells, and Leases Moe»tie Moe»1e MU1823 AM1997 Bear Tooth Unit AAOe1101 ..,,..... AM1107 AA081700 AA0107f0 MO90»7 AM1321 i AAM1a0 M0923Az RANI s 1 PAGUM M091903 :...� AA01179i NG T2 \. AAaneoo M\� 0A778/ AAW1\ �\\\\ AA091780 AA09,739 MW17e2 AAM739 Colville i GMT1 f MW»16 MOn9/7 Maat97 I uacxreA A A8Rr W16 Greater ""0°1791 Mooses AAM75 Tooth Unit I IAA091796 M0A1795 A9RC-WR6 AA081779 N AAM2tl1 0 1 2 3 4 Miles — Proposed Well Targets Pipeline Road a Pad Rendezvous Reservoir Q Potential PA Boundary C3UWd Boundaries CPAI Leases ConocoPhillips Alaska Rendezvous Participating Area, Leases and Proposed Wells 312812018 Attachment M GMT2 List of Leases for Potential Rendezvous Participating Area Greater Mooses Tooth Unit Tract Description Number Serial Number Expiration Basic Basic Ownership Overriding Overriding Royalty Working Ownership No. of Lands of Acres Tobin Number Date Royalty Royalty Owner Percentage Royalty Owner Percentage Interest Owners) Percentage 13 TION-R1E, UM AA -081806 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 16: S1/2NE1/4,SE1/4 240.00 932541 Total 240.00 14 T10N-R1E, UM AA -081805 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 13: SW1/4NW1/4, 932540 W1/2SE1/4, SE1/4SE1/4, SW1/4 320.00 Section 14: W1/2, NW1/4NE1/4, S1/2NE1/4, SE1/4 600.00 Section 15: NEI/4NW1/4, S1/2NW1/4, E1/2, SW1/4 600.00 Total 1520.00 20 T10N-RIE, UM AA -081804 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 21: E1/2W1/2, E1/2 480.00 932539 Section 28: E1/2W1/2, E1/2 480.00 Section 33: EI/2W1/2, E1/2 480.00 Total 1440.00 21 T10N-R1E, UM AA -081803 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 22: All 640.00 932538 Section 23: All 640.00 Section 24: All 640.00 Section 25: All 639.00 Section 26: All 640.00 Section 27: All 639.00 Section 34: All 640.00 Section 35: All 639.00 Section 36: All 639.00 Total 5756.00 1 Attachment 1C: GMT2 List of Leases for Potential Rendezvous Participating Area Greater Mooses Tooth Unit Tract Description Number Serial Number Expiration Basic Basic Ownership Overriding Overriding Royalty Working Ownership No. of lands of Acres Tobin Number Date Royalty Royalty Owner Percentage Royalty Owner Percentage Interest. Owner(s) Percentage 22A T1 ON-R2E, UM AA -081800 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 19: W1/2, SW1/4NE1/4, 932535 W1/2SEI/4, SE114SE114 480.00 Section 28: W1/2SE1/4, SW1/4 240.00 Section 30: All 619.00 Section 31: All 621.00 Section 32: All 640.00 Section 33: All 640.00 Total 3240.00 22B T10N-R2E, UM AA -092341 8/31/09 14.16667%` ASRC 100% Kuukpik Corp. 2.5%` ConocoPhillips Section 29: W1/2NW1/4, 340762 SE1/4NW1/4, S112NE1/4, S1/2 520.00 Total 520.00 23 T10N-R2E, UM AA -081799 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 25: SW1/4SE1/4, S1/2SW 120.00 932534 Section 26: SE114SE114 40.00 Section 34: W1/2NW1/4, 520.00 SE1/4NW1/4, S1/2NE1/4, S1/2 Section 35: S1/2NW1/4, E1/2, SW1/4 560.00 Section 36: All 640.00 Total 1880.OD. 25 T9N-RIE, UM AA -081785 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 4: N1/2NE1/4 80.00 932520 Total 80.00 26 T9N-RIE, UM AA -081784 8131/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 1: All 640.00 932519 Section 2: All 640.00 Section 3: N1/2, SE1/4, N1/2SW1/4 560.00 Section 10: N1/2NE1/4 80.00 Section 11: All 640.00 Section 12: All 639.00 Section 13: All 639.00 Section 14: All 639.00 Total 4477.00 2 Attachment M GMT2 List of Leases for Potential Rendezvous Participating Area Greater Mooses Tooth Unit Tract Description Number Serial Number Expiration Basic Basic Ownership Overriding Overriding Royalty Working Ownership No. of Lands of Acres Tobin Number Date Royalty Royalty Owner Percentage Royalty Owner Percentage Interest Owner(s) Percentage 27 T9N-R2E, UM AA -081781 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 4: All 640.00 932516 Section 5: All 640.00 Section 6: All 624.00 Section 7: All 626.00 Section 8: All 640.00 Section 9: All 640.00 Section 16: All 640.00 Section 17: All 640.00 Section 18: All 630.00 Total 5720.00 28 T9N-R2E, UM AA -081780 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 1: N1/2, NW1/4SE1/4, 932515 E/2SE1/4, N1/2SW1/4 520.00 Section 2: N1/2, N112SE1/4, SW1/4 560.00 Section 3: All 640.00 Section 10: W112NW1/4, NW1/4NW1/4, W1/2SW1/4 200.00 Section 15: W1/2W1/2 160.00 Total 2080.00 29 T9N-R3E, UM AA -081779 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 6: All 624.00 932514 Total 624.00 31 T9N-R1E, UM AA -081782 8/31/09 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 22: E1/2NW1/4, E1/2, SW1/4 560.00 932517 Section 23: All 640.00 Section 24: All 639.00 Section 25: All 640.00 Section 26: All 639.00 Section 27: All 640.00 Section 34: All 639.00 Section 35: All 639.00 Section 36: All 640.00 Total 5676.00 3 Attachment M GMT2 List of Leases for Potential Rendezvous Participating Area Greater Mooses Tooth Unit Tract Description No. of Lands 32 T9N-R2E, UM Section 19: All Section 20: All Section 21: All Section 29: All Section 30: All Section 31: All Section 32: All Total 33 T9N-R2E, UM Section 22: NW1/4NW1/4 Total Number Serial Number Expiration of Acres Tobin Number Date AA -081736 8/31/09 631.00 300840 640.00 640.00 640.00 635.00 638.00 640.00 4464.00 Basic Basic Royalty Royalty Owner 16.6667% U.S. AA -081735 8/31/09 16.6667% U.S. 40.00 300839 40.00 Ownership Overriding Overriding Royalty Percentage Royalty Owner Percentage 100% None None 100% None None Working Ownership Interest Owner(s) Percentage ConocoPhillips 100.00 100.00 45 T9N-R1E, UM AA -090709 11/30/18 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 21: SE1/4 160.00 310090 Section 28: E1/2NW1/4, E1/2, SW1/4 560.00 Section 32: NE1/4NE1/4, S1/2NE1/4, SEIM, E112SW114 360.00 Section 33: All 640.00 Total 1720.00 48 T8N-R1E, UM AA -092672 10/31/20 16.6667% U.S. 100% None None ConocoPhillips 100.00 Section 4: All 640.00 341731 Section 5: NEI/4, Ni/2SE1/4, 280.00 SE1/4SE1/4 Section 9: N1/2NE1/4 80.00 Total 1000.00 Totals 40,477.00 'Kuukpik Corp. Overriding Royalty deducted from ASRC Royalty as agreed between Kuukpik Corp. and ASRC for surface access. Key: ASRC - Arctic Slope Regional Corporation Kuukpik Corp. - Kuukpik Corporation ConocoPhillips - ConocoPhillips Alaska, Inc. - Operator U.S. - United States of America 4 �.�� r i ►� ro�� ► -a � �a r ea ►�+ ►_ate ► o� sa � a � 0 0 o� o o� ar- irrlln� in �— -----M- -----R— -----�©.-ir�� ----- ERM in c�aa oor ��. �rioa� oor ■�-.'�a::� Attachment 1E: GMT2 Drillsite Process Flow Diagram Test Separator 0 I I I I S I I I I ESD Vabes Test Sep. Prod. Separator Metering 00 I Full Fow3Phase I Production Separator 0 Production i Heater j I mor —u, L i Water Cut Meter and LJ Liquid Sampling Corrosion Inhibitor Scale Coriolis Meter Inhibitor EmulsionO Orifice Plate Meter and Breaker Gas Sampling Anti -foam Q Oil in Water Analyzer Pig Launcher To GMTI/ ACF GMT2 Fuel Gas Conditioning Additional Utilities Required: Line List: -------- I i Purple: Chemical Nitrogen Orange: Gas Uft Gas Plant Air Green: Oil+water �� I GI Fuel Gas Blue: Separated water Fuel Gas a Black:0il+water+gas To Injector Wells j MI I I _1 Test Separator 0 I I I I S I I I I ESD Vabes Test Sep. Prod. Separator Metering 00 I Full Fow3Phase I Production Separator 0 Production i Heater j I mor —u, L i Water Cut Meter and LJ Liquid Sampling Corrosion Inhibitor Scale Coriolis Meter Inhibitor EmulsionO Orifice Plate Meter and Breaker Gas Sampling Anti -foam Q Oil in Water Analyzer Pig Launcher To GMTI/ ACF Attachment IF: GMT2 Production Separator Measurement System ❑ Phase Dynamics Water Line List: Cut meter ® ❑U ® Coriolis Meter Orange: Gas Oil+water OGreen: Orifice Plate Meter Blue: Separated water OGas sample staton Black: Oil+water+gas QOil in Water Analyzer ❑" ❑D Production to GMTl/ACF Attachment 1G: ACF simple process flow diagram Crudel - Inlel Me FIN FK Alpine Central Facility Natural Gas Mon Fuel d FIBre wGas Saks 7 Processing Gas Gas Enrichment Enriched Oil Slabllizer Gas Processing Injection Condensate ...................... Oil Sales Water Inaction 7 LO NN ALP r4� --,FK> Sea Water P KKsy ALP - Alpine FN- Fiord- Nechelik FK - Fiord-Kuparuk Gas NN -Nanuq-Nanuq Alon QAN - Qannik LO -Lookout REN - Rendezvous' ►Drillsite Fuel Gas NLO NNS `,.REN.;-- ' Proamee PA 3 a 2 3 nT. I i I � I I I - I I I I I , G I I , , I � I NSI I I , I I E� Q 1 I__________ 1 _I I I M ' N s I I , 2 A $Y I rV I � I 4 I I �ommmrc e Er E� Q 1 I__________ 1 _I 2 A I I I I I I I I I I � I 'I II I I �ommmrc e Er E� a� I I I I I I I I I I � I 'I II I I Attachment 11 - GMT2 Oil Uncertainty Calculation Project: GMT2 Separator Analysis Project number: WCP.WAS. P0008.DF95PM04 Revision: 0 Prepared: Jodie L. Hosack, PE Signed: Date: July 3, 2018 Subject: Measurement Uncertainty Estimate Case: Net Volume Uncertainty for Oil in a Three Phase Measurement Application Utilizing a Coriolis Flow Meters (one line meter and one MM) and CEESI Ball Prover MM Calibration 1.0 General 1.1 Introduction 1.2 Process Parameters GMT2 Separator 1.3 Measurement Uncertainty of Net Oil Mass Flow 2.0 Measurement Uncertainty Contributors and Assumptions 2.1 Uncertainty in Primary Device (Micro Motion Coriolis)= 2.2 Uncertainty in BSW Value (Phase Dynamics Analyzer) 2.3 Uncertainty in Density at Operating Conditions 2.4 Meter Factor Uncertainty Contributors 2.5 Sensitivity Analysis for Meter Factor 2.6 Uncertainty of Meter Factor 3.0 Sensitivity Analysis for Net Oil Volume Flow 3.1 Uncertainty Estimate for Net Oil Measurement 3.2 Expanded Uncertainty of Net Volume of Oil (95% Confidence Level) Page 1 of 14 1.0 General 1.1 Introduction The GMT2 production separator measurement system operates in a three phase mode. The oil measurement system comprises of dual redundant Micro Motion Coriolis flow meters installed in a parallel configuration. The combined metering stream is fitted with a fast loop and Phase Dynamics water cut analyzer which provides a means of calculating Net Oil at operating conditions. The Coriolis meter is complete with an electronic flow transmitter (which is paired with the Coriolis flow meter from calibration) and outputs a pulse signal which is applied within a flow computer against a Meter Factor (MF) using units of pulses/bbl to output a Gross Volumetric flow in bbl/day. A density measurement performed by the Coriolis meter is used in the calculation of volume flow at operating conditions. Verfication of the in-service flow meters will be conducted using a Coriolis Master Meter proving arrangement. The separator liquid flow computer further employs a net oil calculation and water calculation through the use of the Phase Dynamics water cut analyzer. Additional measurement uncertainty will be incurred for the measurement of Oil and Water due to the use of the water cut analyzer. This document constitutes a high level measurement uncertainty estimate for the Oil Coriolis measurement system in use. This measurement uncertainty report has been completed in accordance with ISO5168 and all uncertainty terms shown are expressed at the 95% confidence level. This model uses the estimated flow rates for Oil taken from the Basis of Design Forecasts for GMT2. The Expanded Uncertainty is a numerical representation of the expected distribution for the majority (95%) of measured values. Page 2 of 14 1.2 Process Parameters GMT1 Separator Unit conversion for Gallons to Barrels bbl := gal • 42 • • _ • 11 JUJIFFIllillifilluivi 1 : • M0 •• • • nAN • T Netoil:=11000 bbl day Netwater:=110 bbl day Net BSW:—_ water `Netwater+Neton J TotalmixFlow := Netoil +Netwater Poil := 52 lb ft PMix := Poa . (1— BSW) + Pwater • BS W Flow Calibration Factor (FGF) FCF :=1543234 lb 2 a At := PMix • TotalmixFlow FCF Meter Factor Determined from Onsite Proving Mass Flow Mass := TotalmixFlow' PMix Netoil=(4.62.10s) gal day Netwater=(4.62.10a) gal day BSW=0.9901% Totalmi= 4.666.10' \/ gal xFlowday Pwater := 61.55 lb ft pmix = 52.095 lb ft At= 0.00002 s Mass =1.354.10') lb l hr Page 3 of 14 1.3 Measurement Uncertainty of Net Oil Mass Flow The measurement uncertainty contributors considered for this high level estimate are: 1. Design Performance Estimate of Coriolis Meter 2. Density measured by the Coriolis meter at operating conditions 3. Water content measured by the Phase Dynamics analyzer Design Performance Estimate The practical implementation of the Coriolis Mass flow calculation, as taken from AGAll, is: Mass Flow in Ib/hr qM = FCF FT FP (4t—Ato) Where: FCF = Flow Calibration Factor derived from offsite calibration FT = Temperature Compensation FP = Pressure Compensation At = Phase induced by the flowing fluid at Operating Conditions Ato = Residual phase at Zero Flow Conditions Expanding Sub -Equations: Temperature Compensation FT= 1—KT -T Where: KT = Temperature Coefficient of Flow Meter T = Operating Temperature of Flow Meter Pressure Compensation Fa=1+Ka •P Where: KP = Pressure Coefficient of Flow Meter P = Operating Pressure of Flow Meter Page 4 of 14 2.0 Measurement Uncertainty Contributors and Assumptions In order to determine Net Standard Volume Flow the following calculations apply Where: poilmix = Density of oil at operating conditions BSW = The percentage volume of water content contained within the oil flow MF = The Meter Factor determined from onsite proving SF = The shrinkage factor associated with converting observed volume to standard volume Fully Expanded practical Volume flow calculation FCF • (1— K -r • T) • (1 + Kp • P) • (At — Ato) qu = Fully Expanded Net Oil Standard Volume calculation Neto:a = FCF•(1—KT•T)•(1+Kp•P)•(At —Ato)•(1—BS'4t0 Po€WLV Shrinkaae Factor used to convert observed volume to Standard Volume :y 11911N.Y1 Uncertainty Associated with Shrinkage Factor ESF := 2% Netoii:= Mass . MF • (1—BSW) • SF Pmix Net 9.551.103\ bbl oii = / day Page 5 of 14 The Contributors to Measurement Uncertainty for the purpose of this study are taken as: 1. FCF Flow Calibration Factor determined from flow calibration facility 2. At Frequency determination as per manufacturers base accuracy data 3. BSW Water content from Phase Dynamics 4. pOilMix Mixture Density Measured at the Meter 5. MF Meter Factor determined from onsite proving The Assumptions applied within this measurement uncertainty review are as follows: 1. The measurement uncertainty associated with the At term is included within the manufacturers base accuracy statement. 2. The measurement uncertainty associated with the At term is included within the Flow meter zero stability and base accuracy term as supplied by the manufacturer. 3. Temperature and Pressure effects are considered negligible. 4. There are no installation effects to be considered. 5. Mixture density uncertainty is taken from the manufacturers technical specification. Page 6 of 14 2.1 Uncertainty in Primary Device EBase This is determined from the following components: EBaseAccuracy = Uncertainty in base accuracy of flow meter. EZeroStability = Uncertainty in zero stability of Flow meter CalFacility = Uncertainty in calibration facility Flowrange = Flow range of specified flow meter Uncertainty in Mass Flow rate as provided within the manufacturers specification Using the manufacturers technical specification as our primary source of measurement uncertainty for the flow meter in respect to Linearity, Hysterisis, and Repeatability. Base Accuracy Statement from Manufacturers Literature as aerp centage of flow rate BaseA.c := 0.1% • .• R• ..0 Meterstability °=1.08 lb min Meterstability 7'stab'= Nix Zstab=5.317 bbl day Zero:= Zstab Zero=0.04786% TotalmixFlow Eot:= BaseA��2 +Zero2 V Eot=0.11086% EFCF := 0.024% Uncertainty in Mass Flow 2 EMas := Eat +EFCFz Page 7 of 14 EMass = 0.11343% 2.2 Uncertainty in BSW value measured by the Phase Dynamics Analyzer The measurement uncertainty for water content shall be determined from the following uncertainty contributors: Oil Phase = The given oil continueous phase uncertainty and repeatability data for the instrument from the manufacturer Water Phase = The given water continueous phase uncertainty and repeatability data for the instrument from the manufacturer Uncertainty in the BSW Calculation The water content of the flowing fluids is obtained directly from the Phase Dynamics water cut analyser. Specifications below are those given for the Phase Dynamics low range (0-20%) water cut analyzer: BSW uncertainty is 0.2% for water cut 0-20%. BSW repeatability is 0.1% for water cut 0-20%. BSW=0.9901% BSWUncertainty'= 0.276 BS WRepeatability'— 0.1% 2 2 E'BSW'— VBSWUncertalnty +BSWRepeatability EBSW = 0.22361% Page 8 of 14 2.3 Uncertainty in Mixture Density The measurement uncertainty for Density variables shall be determined from the following uncertainty contributors: pa m. = The density of the oil and water mixture as measured by the Coriolis Meter. The mixture density of the flowing fluids is obtained directly from the Coriolis Flow Meter. specifications below are those given for the Micro Motion Elite series flow meters: Densitypccuracy°=0.5 -k9- 3 M UMix:= VDensitYAccurmy2 + DensitYRepeatability2 Umix = 0.03362 lb ft UMix F'pMix'= PMix Page 9 of 14 DensitYRepeacatu;ty=0.2 kg3 M EpMix = 0.06453% EMassmm °=EMass' Mass Epmm:= EpMix' PMix EMassmut := EMass *Mass Epmut = EpMix' PMix MassMM := Mass • MF MassMUT := Mass PMM:= PMix PMUT:= PMix Massmm PMM MF�.d�: MF�.j�=0.998 MassMUT PMUT Page 10 of 14 2.s 2.6 Sensitivity Analysis for Meter Factor MassMM OMassMM'= d PMM dMassmm MassMUT PMUT OMassMUT'— Ma.ss..... d PMM dMasSMUT MasSMUT PMUT MassMM OPMMd PMM '- d PMM MaSSMUT PMUT Mass-- d PMM OPMUT'— dPMUT MassMUT PMUT Uncertainty of Meter Factor OMassMM=0.02659 s 1b OMaSSMUT=-0.02654 8 Tb OpMM=-0.01916 AL db OPMUT=0.01916 b6 EMF'— V (EMassmm' OMassMM) 2 + (Epmm' OPMM) 9 + (EMassmut' OMassMUT) 2 + (Epmut' OPMUT) 2 EMF = 0.18433% Page 11 of 14 3.0 Sensitivity Analysis for Net Oil Volume Flow OMass:= d I(Mass •(1—BSW) •MF•SF� OMass=0.0165 t dMass \ PMix Ib OBSW d (Mass •(1—BSW) •MF•SF) OBSW 281.352 ou'= II I oii=— 9P'm dBSW l PMix / O d (Mass•(l—BSW) -MF-SF) O 0.01191 ft Poii:= I Poil=— d PMix PMix / Ib • s OMF:=d I(Mass•(1—BSW) ,MF•SF� OMF=279.125 gpm dMF\ PMix / OSF:= d I(Mass •(1—BSW),MF•SF) OSF=320.192gpm dSF \ PMix f 3.1 Uncertainty Estimate for Net Oil Measurement Input Uncertainty Distribution Coverage Factor (K) EMme = 0.11343% Normal Km.a := 2 EBSµ, = 0.22361% Normal KBSµ, := 2 EPMix = 0.06453% Normal KPoi1:= 2 EMF = 0.18433% Normal KMF := 2 ESF= 2% Normal KSF:= 2 Page 12 of 14 Sensitivi Variance 3 2 OMass=0.017 ft lb VarMass;=(UMasg•OMass) 2 OMF = 279.125 gpm VarMF:= (UMF • OMF) OBSWoil=-281.352 gpm 6 Opoil=-0.012 lb -ss VarMaas=0.02496 gpm2 VarMF=0.06592 gpm2 VarBsw:=(Stdasw'OBSWoi1)2 VaXBSw=0.09895 gpm2 2 Varpoil'= (Upoil' Opoil) Var poil = 0.00808 gpm2 OSF=320.192 gpm VarMF'= (USF 'OSF)2 VarsF=7.75994 gpm2 Page 13 of 14 Relative Standard Uncertainty Absolute Standard Uncertainty Stdm.:= EM"e Stdm83 =0.05672% UMass:= Mass •Stdm.e Kmms StdMF:=EMF StdMF=0.09216% UMF:=MF•StdMF KMF StdBsw:=EBsw StdBSW=0.1118% UBSW:=Netwate3•StdBsw KBSw Epm._ .5'tdpoil'= Std . poi1=003227% U pOil'=pMix' Std poll Kpoil StdsF:= EsF StdsF=1% UsF:=SF•StdsF KSF Sensitivi Variance 3 2 OMass=0.017 ft lb VarMass;=(UMasg•OMass) 2 OMF = 279.125 gpm VarMF:= (UMF • OMF) OBSWoil=-281.352 gpm 6 Opoil=-0.012 lb -ss VarMaas=0.02496 gpm2 VarMF=0.06592 gpm2 VarBsw:=(Stdasw'OBSWoi1)2 VaXBSw=0.09895 gpm2 2 Varpoil'= (Upoil' Opoil) Var poil = 0.00808 gpm2 OSF=320.192 gpm VarMF'= (USF 'OSF)2 VarsF=7.75994 gpm2 Page 13 of 14 MUM AM --7107 i Sumva,,.j� :=VarMaas+VarMF+VarBSW+Va pOil+VarSF SumVariance— = 7.95785 9P'm 2 Ice am, a I-$ �. Combinedstmdard_Uncertainty:= Sumvariance Combinedstandard_Uncertainty=2.821 gpm Relative Standard Uncertainty Combinedstandard_uwo rtaiaty Esta:_ Netoil Net0il=278.567 gpm 3.2 Expanded Uncertainty of Net Standard Volume of Oil (95% Confidence Level) Expanded Uncertainty (95% Convidence Level) Expandeduncertainty := Esta' 2 Expandeduncertainty = 2.02534% UnCbarrels°=ExpandedUncertainty'Netoil'1 day Barrels:= UnCbarrels 42 gal Page 14 of 14 UnCbarrels = (8.124.103) gal Barrels =193.438 ATTACHMENT 1.1 Oil Secondary Instrument Redundancy Verification (static pressure and temperature) The frequency of the GMT2 Production Separator oil meter secondary instrument calibrations is governed by the BLM Measurement of Oil regulations in 43 CFR 3174.11. That section provides that the measurement instruments which are used in the determination of standard oil volume shall be verified as part of each required meter prove, which is monthly for GMT2. Verification is also required on any transmitter following a repair or replacement. ConocoPhillips is requesting approval of redundancy verification for oil secondary instruments. The proposed oil measurement redundancy verification for pressure and temperature transmitters will follow the requirements of §3175.102(d) of the Measurement of Gas rules and API Manual of Petroleum Measurement Standards Chapter 21. 1, Section 8.2. Redundancy verification is a type of continuous verification which confirms device accuracy at operating conditions for a period of time as a percent of the reading difference between the flowtime linear average of the custody device and an independent check device. The primary pressure or temperature transmitter flowtime linear average are compared to the independent check transmitter monthly. If the monthly check is outside of allowed tolerance, both the primary and check transmitters will be calibrated within the first five (5) days of the following month. The independent temperature check transmitter conforms with the installation requirements of §3174.11(f) and is installed in a thermowell that is less than 12 inches from the primary temperature device. This provides a level of continuous transmitter verification that exceeds the routine verification requirements in §3174.11. The tolerance utilized for monthly redundancy verification checks is defined as: Tolerance = (Transmitter Uncertainty)z + (Check Transmitter Uncertainty)2 Documentation for the automated monthly redundancy verification checks and all performed calibrations will be retained per the requirements of §3170.7 and made available to the AO upon request. 120% 100% 80% 60% 40% a z 20% 0% -20% -40% Current Value Four Year Delay Facility Cost Operating Cost Revised Value (No PF) (PF) Range of Possible Outcomes Production Facility impacts (besides potential for negative NPV) would move GMT2 project to the bottom 10% of projects in COP's global portfolio and thus not compete for capital Production Facility adds -$800 MM in capital, -$40 MM /year in annual expense, and will delay production at least four years to achieve LACT quality measurement ConocoPhillips Conoco Phillips Alaska GMT2 Development & Measurement Approval Request Overview ATTACHMENT 2 GMT1 Oil Measurement by Other Methods Approval (10/14/2016) 10 Fnrm 116n.S (August 2007) UNITED STATES FORM APPROVED DEPARTMENT OF THE INTERIOR OMB No. 1004-0135 " BUREAU OF LAND MANAGEMENT Expires: July 31, 2010 5:—Lerae- Serial -No.---_—.— - AKAA81798 SUNDRY NOTICES AND REPORTS ON WELLS Do not use this form for proposals to drill or to re-enter an 6. If Indian, Allottee car Tribe Name abandoned well. Use form 3160-3 (APO) for such proposals. SUBMIT IN TRIPLICATE - Other instructions on reverse side. 7. If Unit or CA/Agreement, Name andior No. 1. Type of Well S. Well Name and No. ❑ Oil Well Q Gas Well H Other: UNKNOWN OTH GMT1 B2 2. Name of Operator Contact: SAMWIDMER CONOCOPHILLIPS E -Mail: Sam.Widmer@conocophillips.com 9. API Well No. 3a Address 700 G STREET 36. Phone No. (include ansa code) 10. Field and Pool, or Exploratory ANCHORAGE, AK 99510 Ph: 907-227-1777 LOOKOUT PROSPECT 4. Location of Well (Footage, Sec., T., R, M., or Survey Description) 11. County or Parish, and State Sec 6 Tl ON R3E NORTH SLOPE COUNTY, AK 12. CHECK APPROPRIATE BOX(ES) TO INDICATE NATURE OF NOTICE, REPORT, OR OTHER DATA TYPE OF SUBMISSION I TYPE OF ACTION ® Notice of Intent ❑ Acidize ❑ Deepen ❑ Production (Start/Resome) Q Water Shut -Off Q Alter Casing p Fracture Treat p Reclamation p Well Integrity Q Subsequent Report 8 Repair r O PO New Construction p Recomplete ®Other Q Final Abandonment Notice p Change Plans p Plug and Abandon p Temporarily Abandon (3 Convert to Injection p Plug Back ❑ Water Disposal 13. Describe Proposed or Completed Operation (clearly state an pertinent details, including estimated starting date of any proposed work and approximate duration thereof. If the proposal is to deepen directionally or recompleter horizontally, give subsurface locations and measured and true vertical depths of all pertinent markers and zones. Attach the Bond under which the work will be performed or provide the Bond No. on file with BLMBIA. Required subsequent reports shall be filed within 30 days following completion of the involved operations. If the operation results in a multiple completion or recompledon in a new interval, a Form 31604 shall be filed once testing has been completed. Final Abandonment Notices shall be filed only after all requirements, including reclamation, have been completed, and the operator has determined that the site is ready for final inspection.) ConocoPhillips Alaska, Inc. (ConocoPhillips), as Unit Operator of the Greater Mooses Tooth Unit (GMTU) and on behalf of itself and the other working Interest owner in the GMTU, Anadarko E&P Onshore LLC, requests Oil Measurement by Other Methods approval for Greater Mooses Tooth #1 (GMT1) oil production. The GMT1 project will develop the first drill site in the GMTU which is in the northeast corner of the National Petroleum Reserve - Alaska (NPR -A). The GMT1 project will develop Arctic Slope Regional Corporation (ASRC) and federal resources, therefore ConocoPhillips requests approval for measurement system design from the Bureau of Land Management. The required supporting information is included in the following 3 attachments: (1) GMT1 Development and Measurement Approval Request Overview; (2) GMT1 Flow Measurement and Metering Philosophy - Three Phase Production Separator; and (3) October 1, 2014 Whitepaper- GMT1 Commingling, Allocation, and Measurement Summary. 14. I hereby certify that the foregoing is true and correct. Electronic Submission #329405 verifiby the BLM Well Information System For CONOCOPHILLIPS sent to the Anchorage Name(Prints&75Ped) BRANDON VIIATOf3� Title PRO.IFCT MAMAr FR Q,isffatc¢cramc numamstonp a I Date 01/21/2016 THIS SPACE WR F DERAL OR STATE OFFICE USE 6/^/// to Approved By _ _ _ _ _ Title — � _ � _ Date Conditions of approval, i an , are attar . Approv of ' notice does not warrant or I �rC STv fe 0,/e2 certify thaz the aQphcan of legal or equitable rade tot se rights N the subject lease which would entitle the app 'cant to conduct operation cocoa. Office Title 18 U.S.C. Section 1001 and Title 43 U.S.C. Section 1212, make it a crime for any person knowingly and willfully to make to any department or agency of the United States any false, fictitious or fraudulent statements or representations as to any matter within its jurisdiction. OPERATOR -SUBMITTED ** OPERATOR -SUBMITTED ** OPERATOR -SUBMITTED ** Additional data for EC transaction #329405 that would not fit on the form 32. Additional remarks, continued ConocoPhillips requests that the Onshore Order 4, Section E, Oil Measurement by Other Methods approval be effective from the date of first production, which is currently targeted in 2018. Conditions of Approval for the Use of Coriolis Oil Measurement Systems (Lookout PA) A. General 1. The Coriolis metering system must be designed and operated in a manner to achieve an overall uncertainty of the flow rate of un -shrunk oil of±0.5% of reading, or better. 2. The shrinkage factor must be derived in a manner that achieves an overall uncertainty of ±2%, or better. 3. The operator must notify the authorized officer in writing at least 3 days prior to changing any Coriolis meter internal calibration factors including, but not limited to: meter factor, pulse -scaling factor, flow -calibration factor, density -calibration factor, or density -meter factor. B. Required Components In addition to the components proposed in the variance request, the following components must also be installed and operational at all Coriolis metering facilities: 1. Pressure sensor and method of pressure averaging; 2. Meter proving connections, per OO4.III.D.2.g; 3. Isolation valves upstream and downstream of the Coriolis meter; and 4. Back pressure valve or sufficient hydrostatic head to ensure single phase flow through the meter. C. On-site information 1. The Coriolis meter system display must be readable without the need for data collection units, laptop computers, or any special equipment, and must be on-site and accessible to the AO. 2. For each Coriolis meter, the following values and corresponding units of measurement must be displayed: a. The instantaneous density of liquid (specific gravity or AN gravity); b. Instantaneous indicated volumetric flow rate through the meter (bbls/day); c. Meter factor; d. Instantaneous pressure (psi); e. Instantaneous temperature (" F); f. Instantaneous water content (%); g. Instantaneous drive gain; h. Cumulative indicated volume through the meter (non-resettable totalizer) (bbls); i. The previous day's uncorrected volume through the meter (bbls); and j. Meter alarm conditions. 3. The following information must be correct, be maintained in a legible condition, and be accessible to the AO at the Coriolis meter without the use of data collection equipment, laptop computers, or any special equipment: a. Make, model, and size of each sensor; b. Make, range, calibrated span, and model of the pressure and temperature transducer used to determine gross standard volume; and c. Make, model, and range of water cut meter(s). 4. A log must be maintained of all meter factors, zero verifications, and zero adjustments (observed zero value prior to adjustment and zero value after adjustment). This log must be available to the A0. D. Coriolis meter 1. The Coriolis meter must be installed in accordance with the manufacturer's specifications. 2. The pulse output must be proportional to uncorrected volume and must beset at a minimum of 8,400 pulses per barrel. 3. The Coriolis meter must have a non-resettable totalizer for the uncorrected barrels that have passed through the meter since it was installed. The uncorrected barrels is the number of pulses generated by the Coriolis meter divided by the meter's K -factor (pulses per barrel). 4. Each Coriolis meter must have installed and maintained in operable condition a backup power supply or a nonvolatile memory capable of retaining all data in the unit's memory to ensure that the audit trail information is protected. E. Proving 1. The Coriolis meter must be proved on a volume basis per the requirements of 004.III.D.3 with the following exceptions and additions: a. Proving must be done with a master Coriolis meter with an overall uncertainty of ±0.25% of indicated flow rate, or better, b. The run -to -run repeatability requirements of 004.III.D.3.c do not apply, however, the uncertainty due to consecutive run -to -run repeatability must be included in the calculation of overall flow rate uncertainty (COA A.1) and must be calculated under API 4.2, Appendix C; and c. The new meter factor is determined using all the runs from COA E.1.b. 2. Before proving the meter, or any time the AO requests it, the zero value stored in the meter (see API 5.6) must be verified by stopping the flow through the meter and then monitoring the indicated volumetric flow rate under this condition. If the zero error equals or exceeds the stated zero stability specification of the meter the meter must be zeroed and the Coriolis meter must be proved. 3. During all provings, the drive gain of both the master meter and the duty meter must be logged and the log must be retained for at least 7 years. F. Audit trail The following information shall be recorded beginning on the date of this approval and saved for at least 7 years from the date it was generated. All data shall be submitted to BLM upon request. 1. Measurement Ticket -A measurement ticket must be opened at the beginning of every calendar month. The measurement ticket must include the following: a. The opening and closing non-resettable totalizer readings; b. The average pressure over the measurement ticket period; c. The average temperature over the measurement ticket period; d. The average density over the measurement ticket period (either measured by the Coriolis or determined from a composite sample); e. The average water content over the measurement ticket period; f. The meter factor(s) used during the month; g. The gross un -shrunk oil volume (indicated barrels x meter factor); and h. The net un -shrunk oil volume (gross oil volume x (1—sediment and water)). 2. Configuration Log - The configuration log shall comply with the requirements of API 21.2. In addition, the configuration log shall include the low flow cutoff (if applicable), the methods by which the average temperature, pressure, and density are weighted, and the instantaneous values of mass flow, temperature and density at the time the configuration Log was retrieved. 3. Event Log - The event log shall comply with the requirements of API 21.2. In addition, the event log shall be of sufficient capacity to record all events for the previous 7 years beginning from the date of this approval. 4. Alarm Log—The type and duration of any of the following alarm conditions: a. Drive gain deviates from acceptable parameters; b. Density deviates from acceptable parameters; c. Flow rate through meter exceeds manufacturer's maximum recommended flow rate or drops below the flow rate needed to achieve the overall meter station uncertainty in Condition A.1; and d. Power failures. 5. Shrinkage Factor —The latest shrinkage factor table and all data (e.g. composition and equation of state results) used to determine the shrinkage factor table. G. Reporting Oil removed from the participating area that is measured by a Coriolis metering system approved under this variance and which is riot first placed into inventory, must be reported on the Oil and Gas Operations Report (OGOR), Part B as follows: 1. Volume: The total volume of net oil as determined from: a. The measurement ticket(s) in the calendar month for which the OGOR B is submitted, multiplied by the shrinkage factor determined from the shrinkage factor table based on the most recent compositional analysis, the average monthly temperature, and the average monthly pressure; or b. The summation of the instantaneous net un -shrunk volume as determined by the Coriolis meter and water cut meter, multiplied by the instantaneous shrinkage factor, over the calendar month for which the OGOR B is submitted. 2. API Gravity: a. The API gravity determined from a composite sampler in accordance with 004.III.C.5; or b. The volume -weighted average density from the Coriolis meter taken over the calendar month for which the OGOR B is submitted, corrected for water content and shrinkage, and converted into API gravity units. ConocoPhillips Alaska GMT2 Development & Measurement Approval Request Overview ATTACHMENT 3 GMT1 Measurement Re -confirmation and Redundancy Verification Approval (1/25/2018) 11 roan 2015) UNITED STATES (June 2015) FORM APPROVED DEPARTMENT OF THE INTERIOR OMB NO. 1004-0137 BUREAU OF LAND MANAGEMENT Expires: January 31 2018 5. Lease Serial No. O Hydraulic Fracturing SUNDRY NOTICES AND REPORTS ON WELLS AKAA81798 Do not use this form for proposals to drill or to re-enter an 6. If Indian, Allottee or Tribe Name abandoned well. Use form 3160-3 (APD) for such proposals. SUBMIT /N TRIPLICATE - Other instructions on page 2 7. If Unit or CA/Agreement, Name and/or No. O Final Abandonment Notice AKAA87852 I. Type of Well 8. Well Name and No. ® Oil Well O Gas Well O Other GMT1 B2 2. Name of Operator Contact: BRANDON VIATOR 9. API Well No. CONOCOPHILLIPS ALASKA INC E -Mail: Brandon.S.Viator@conocophillips.com 3a. Address 3b. Phone No. (include area code) 10. Field and Pool or Exploratory Area PO BOX 100360 Ph: 190-726-3465 EXPLORATION ANCHORAGE, AK 99510-0360 4. Location of Well (Footage, Sec., T., R., M, or Survey Description) 11. County or Parish, State Sec 6 T10N R3E NENW Tract 991-H-046 897FNL 3397FEL HARRISON BAY COUNTY, AK 70.151546 N Lat, 151.290686 W Lon 12. CHECK THE APPROPRIATE BOX(ES) TO INDICATE NATURE OF NOTICE, REPORT, OR OTHER DATA TYPE OF SUBMISSION I TYPE OF ACTION ® Notice of Intent O Acidize O Deepen O Production (StartfResume) O Water Shut -Off O Alter Casing O Hydraulic Fracturing O Reclamation O Well Integrity O Subsequent Report O Casing Repair O New Construction O Recomplete ® Other O Final Abandonment Notice O Change Plans O Plug and Abandon O Temporarily Abandon Onshore Order Varian cc O Convert to Injection O Plug Back O Water Disposal 13, Describe Proposed or Completed Operation: Clearly state all pertinent details, including estimated starting date of any proposed work and approximate duration thereof. If the proposal is to deepen directionally or recomplete horizontally, give subsurface locations and measured and true vertical depths of all pertinent markers and zones. Attach the Bond under which the work will be performed or provide the Bond No. on file with BLM/BIA. Required subsequent reports must be filed within 30 days following completion of the involved operations. If the operation results in a multiple completion or recompletion in a new interval, a Form 3160-4 must be filed once testing has been completed. Final Abandonment Notices must be filed only after all requirements, including reclamation, have been completed and the operator has determined that the site is ready for final inspection. ConocoPhillips Alaska, Inc. (ConocoPhillips), as Unit Operator of the Greater Mooses Tooth Unit (GMTU) and on behalf of itself and the other working interest owner in the GMTU, Anadarko E&P Onshore LLC, requests Oil Measurement by Other Methods re -approval for GMT1 oil production. ConocoPhillips submitted its original GMT1 measurement application to the BLM on January 21, 2016. BLM approved the original application on October 14, 2016 with Conditions of Approval. Subsequent to BLM?s approval, the BLM codified new oil measurement rules in 43 C.F.R. ? 3174. The GMT1 project is currently in construction with an estimated first oil date in Q4 2018. 43 C.F.R. ? 3174.2(e) requires immediate compliance with the 43 C.F.R. ? 3174 requirements for facilities installed after January 17, 2017. To ensure compliance with the new regulations, ConocoPhillips is submitting this sundry application to BLM seeking confirmation of BLM?s approval of the GMT1 oil measurement system under the new rules, using the same measurement system that BLM 14. I hereby certify that the foregoing is true and correct. Electronic Submission #398566 verifiby the BLM Well Information System ILLIPS For CONOCOPHALAS INC, sent to the Anchorage Committed to AFMSS for processing by SHA N YARAWSKY on 01/09/2018 (18SLY0077SE) Name(Printed/Typed) BRANDON VIATOR Title PROJECT MANAGER Date 12/19/2017 THIS SPACE FOR FEDERAL OR STATE OFFICE USE ApP_rovedBy WgYNESYEJROIjA _ _ _ _ _ _ _ _ _ I Title Conditions of approval, if any, are attached. Approval of this notice does not warrant or certify that the applicant holds legal orequimble title to those rights in the subject lease which would entitle the applicant to conduct operations thereon. Office Tide 18 U.S.C. Section 1001 and Title 43 U.S.C. Section 1212, make it a crime for any person knowingly and willfully to make to any department or agency of the United States any false, fictitious or fraudulent statements or representations as to any matter within its jurisdiction. (Instructions on page 2) ** BLM REVISED ** BLM REVISED ** BLM REVISED ** BLM REVISED ** BLM REVISED ** Additional data for EC transaction #398566 that would not fit on the form 32. Additional remarks, continued previously approved. ConocoPhillips is also submitting a proposed revision to the Conditions of Approval (COA) to remove conditions that are now codified in the new regulations, and, therefore, do not need to be listed as additional requirements. The proposed revised COAs are included with this request. In addition to the above oil measurement approval, ConocoPhillips is also requesting that it be allowed to use redundancy verification for oil secondary instruments consistent with the methodology set forth in 43 C.F.R. ? 3175.102(d) of the Measurement of Gas rules and as described in this sundry application. This methodology will be used in place of the requirements of 43 C.F.R. ? 3174.11(f) and (g) for the routine verification of pressure and temperature transmitters. Use of the 43 C.F.R. ? 3175.102(d) methodology for pressure and temperature transmitters meets the criteria set forth in 43 C.F.R. ? 3174.13, as use of this methodology will meet or exceed the objectives of the oil measurement minimum requirements in 43 C.F.R. ? 3174 and will not affect royalty income or production accountability. Revisions to Operator -Submitted EC Data for Sundry Notice #398566 Operator Submitted BLM Revised (AFMSS) Sundry Type: OTHER VARI NOI NOI Lease: AKAA81798 AKAA81798 Agreement: AKAA87852(AKAA87852X) Operator: CONOCOPHILLIPS 700 G STREET ANCHORAGE, AK 99501 Ph: 907-276-1215 Admin Contact: BRANDON VIATOR PROJECT INTEGRATION MANAGER E -Mail: BRANDON.S.VIATOR@CONOCOPHILLIPS.COM Cell: 907-229-1462 Ph: 907-263-4653 Tech Contact: BRANDON VIATOR PROJECT INTEGRATION MANAGER E -Mail: BRANDON.S.VIATOR@CONOCOPHILLIPS.COM Cele 907-229-1462 Ph: 907-263-4653 Location: Slate: AK County: NORTH SLOPE COU Field/Pool: LOOKOUT Well/Facility: GMT162 Sec 6 T10N R3E CONOCOPHILLIPS ALASKA INC PO BOX 100360 ANCHORAGE, AK 99510-0360 Ph: 907.263.4824 BRANDON VIATOR PROJECT MANAGER E -Mail: Brandon.S.Viator@conocophillips.mm Ph: 190-726-3465 BRANDON VIATOR PROJECT MANAGER E -Mail: Brandon.S.Viator@conomphillips.com Ph: 190-726-3465 AK HARRISON BAY EXPLORATION GMT1 B2 Sec 6 TION R3E NENW Tract 991-H-046 897FNL 3397FEL 70.151546 N Lat. 151.290686 W Lon ConocoPhillips Alaska GMT2 Development & Measurement Approval Request Overview ATTACHMENT 4 GMT2 Measurement Application Package for AOGCC 12