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Home My WebLink AboutO 112 A1. 2. 3. 4. 5. 6. OTHER ORDER 112A Docket No. OTH-16-025 Greater Moose's Tooth Unit Greater Moose's Tooth 1 Pad North Slope Borough, Alaska February 26, 2016 CPAI's request for approval of production measurement October 4, 2016 Notice of public hearing, affidavit of publication, email distribution, mailings November 17, 2016 Transcript, sign -in sheet, exhibit -------------------- DOR, DNR, and CPAI's follow-up responses from hearing (CPAI's Attachment 1 B, Attachment 2, and Appendix B held confidential in secure storage) -------------------- Emails January 10, 2017 Notice of Clarification ORDERS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7tn 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. I I 2 potentially affected landowners the ) Greater Moose's Tooth Unit opportunity to comment on ConocoPhillips ) Greater Moose's Tooth 1 Pad 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 (GMT1) 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 GMT 1 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 GMT 1 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 GMT1 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 GMT1 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: 1. CPAI's request for a waiver of the requirements of 20 AAC 25.228 to allow for fiscal allocation of production from the GMT1 to be based on a metering system that does not meet custody transfer quality standards is hereby APPROVED. 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 GMT1 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 GMT1 must be approved by the AOGCC before being installed. Refer to AOGCC Industry Guidance Bulletin 13-002 for details regarding the measurement application(s). 4. The meter allocation factor for the GMT1 metering system shall be set at 1.0. DONE at Anchorage, Alaska and dated December 22, 2016. 0/�� Daniel T eamount, Jr. Commissioner Commissioner Other Order 112A December 22, 2016 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE 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 tiled 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 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. Misty Alexa Stephen Thatcher Brandon Viator Manager, WNS Development Manager, WNS Operations Project Integration Manager, GMTU ConocoPhillips Alaska, Inc. ConocoPhillips Alaska, Inc. ConocoPhillips Alaska, Inc. 700 G St. 700 G St. 700 G St. Anchorage, AK 99501-3439 Anchorage, AK 99501-3439 Anchorage, AK 99501-3439 r a%'L@ (. 12-23-\1- STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 711 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. I I 2 potentially affected landowners the ) Greater Moose's Tooth Unit opportunity to comment on ConocoPhillips ) Greater Moose's Tooth 1 Pad 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 (GMT1) 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 GMT 1 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 GMT 1 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 GMT1 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 GMT1 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: 1. CPAI's request for a waiver of the requirements of 20 AAC 25.228 to allow for fiscal allocation of production from the GMT1 to be based on a metering system that does not meet custody transfer quality standards is hereby APPROVED. 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 GMT1 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 GMT1 must be approved by the AOGCC before being installed. Refer to AOGCC Industry Guidance Bulletin 13-002 for details regarding the measurement application(s). 4. The meter allocation factor for the GMT 1 metering system shall be set at 1.0. OILO DONE at Anchorage, Alaska and dated December 22, 2016. //signature on file// //signature on file// PION ,�� Daniel T. Seamount, Jr. Hollis French Commissioner Commissioner Other Order 112A December 22, 2016 Page 3 of 3 RECONSIDERATION AND APPEAL NOTICE 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 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 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. Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, December 22, 2016 12:41 PM To: DOA AOGCC Prudhoe Bay; Bender, Makana K (DOA); Bettis, Patricia K (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Guhl, Meredith D (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Ben Boettger; Bill Bredar; Bob Shavelson; Brandon Viator; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller; Connie Downing; Crandall, Krissell; D Lawrence; Dale Hoffman; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David McCraine; David Tetta; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX); Gary Oskolkosf, George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff, Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); John Stuart; Jon Goltz; Chmielowski, Josef (DNR); Juanita Lovett; Judy Stanek; Julie Little; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin J (DNR); Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Rena Delbridge; Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler; Tim Jones; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham 0 (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Fair, Holly S (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jesse Chielowski; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster; William Van Dyke Subject: CO 112A (ConocoPhillips) Attachments: other112a.pdf Re: THE MOTION OF the Alaska Oil arrd Gas Conservation Commission to provide potentially affected landowners the opportunity to comment on ConocoPhillips Alaska, Inc. to set the meter allocation factor for the Greater Moose's Tooth 1 development at 1.0 Jody J. CoCom.6ie AOGCC Specia(Assistant A(aska Oi(andGas Conservation Commission 333 West 7`" Avenue Anchorage, A(aska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iody.colombie@alaska.gov. Bernie Karl K&K Recycling Inc. Gordon Severson Penny Vadla P.O. Box 58055 3201 Westmar Cir. 399 W. Riverview Ave. Fairbanks, AK 99711 Anchorage, AK 99508-4336 Soldotna, AK 99669-7714 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 �Z—Z?D —1Lp- INDEXES P ConocoPhillips s January 10, 2017 IRECEIVED Commissioner Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue Anchorage, AK 99501 JAN 10 2017 AAGCC Brandon Viator Project Integration Manager, GMTU ConocoPhillips Alaska 700 G Street Anchorage, AK 99501-3439 907.263.4653 RE: GMTU and CRU Measurement Application Docket Number OTH-16-025; Other Order Nos. 112 and 112A Notice of Clarification Dear Commissioner Foerster: ConocoPhillips Alaska, Inc. (CPAI), as Unit Operator of the Greater Mooses Tooth Unit (GMTU) and Colville River Unit (CRU), and on behalf of itself and the other working interest owners, submits this notice of clarification regarding both the Commission's December 1, 2016 letter denying reconsideration of Other Order No. 112, and Other Order 112A dated December 22, 2016. We submit this notice of clarification for the record due to our concern that misinterpretations or disagreements may arise from certain language used in the letter and Other Order 112A. In the letter denying reconsideration and in Other Order 112A, the word "sold" appears several times with respect to the gas going from the CRU to the GMTU. Use of the word "sold" clearly implies that gas from the CRU will be sold to the GMTU. Contrary that language, gas produced at GMTU and sent to CRU for processing will be returned to GMTU for use and injection without any sale. The terms "sold" and "sale" have significant meaning for fiscal purposes (e.g., tax and royalty) and CPAI's materials submitted in support of the application did not intend, provide or describe that gas sales would occur. The efficiencies of aligned ownership interests and inter -unit facility sharing are making GMT1 development possible by making it economically viable. Our application materials did not describe a gas sale, and introduction of the term "sold" may create significant confusion and result in complications with other agencies. CPAI wishes to correct any such confusion and avoid unnecessary complications therefore we submit this notice to clarify for the record that we have not proposed and do not intend that gas returned to the GMTU will have been sold anywhere in the process. If you have questions or need additional information, please contact me at 907-263-4653. Sincerely, Brandon Viator Project Integration Manager - Greater Mooses Tooth Unit ConocoPhillips Alaska Colombie, Jody J (DOA) From: French, Hollis (DOA) Sent: Thursday, December 15, 2016 3:31 PM To: Roby, David S (DOA); Foerster, Catherine P (DOA); Seamount, Dan T (DOA); Ballantine, Tab A (LAW) Cc: Regg, James B (DOA); Colombie, Jody J (DOA) Subject: RE: Comment for Docket Number OTH-16-025, GMT1 I agree with you Dave. I don't see that there is anything else we need. From: Roby, David S (DOA) Sent: Thursday, December 15, 2016 3:23 PM To: Foerster, Catherine P (DOA) <cathy.foerster@alaska.gov>; Seamount, Dan T (DOA) <dan.seamount@alaska.gov>; French, Hollis (DOA) <hollis.french@alaska.gov>; Ballantine, Tab A (LAW) <tab.ballantine@alaska.gov> Cc: Regg, James B (DOA) <jim.regg@alaska.gov>; Colombie, Jody J (DOA) <jody.colombie@alaska.gov> Subject: FW: Comment for Docket Number OTH-16-025, GMT1 All, We finally have received comments from all of the potentially affected landowners and they all either support (ASRC and BLM) or at least do not object (DNR) to setting the meter factor at 1.0 for the GMT1 metering system. Since we've given the landowners the opportunity to comment and they've all commented that they think their rights are being protected I propose we go ahead and approve the 1.0 meter factor for GMT1. We've left the record open until COB on the 19th, so we can't take formal action before then but if none of you object to approving the 1.0 meter factor I'll go ahead and add this to the list of stuff I'm trying to get off my desk before I leave for vacation on Wednesday. If you think we need more discussion on this we can work on it after the first of the year. Dave Roby (907)793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at (907)793-1232 or dave.robv@alaska.gov. From: Colombie, Jody J (DOA) Sent: Thursday, December 15, 2016 2:08 PM To: Roby, David S (DOA) <dave.robv@alaska.gov> Subject: FW: Comment for Docket Number 0TH -16-025, GMT1 From: Pike, Kevin W (DNR) Sent: Thursday, December 15, 2016 1:30 PM To: Carlisle, Samantha J (DOA) <samantha.carlisle @alaska.gov> Cc: Davidson, Temple (DNR) <temple.davidson@alaska.gov>; Larsen, John M (DOR) <iohn.larsen@alaska.gov>; Robert Brumbaugh <rbrumbau@blm.gov>; 'wsvejnoh@blm.gov' <wsveinoh@blm.gov>; Colombie, Jody J (DOA) <jody.colombie@alaska.gov>; Beckham, Jim B (DNR) <iim.beckham@alaska.gov>; Alexa, Misty J (Misty.J.Alexa@conocophillips.com) <Misty.J.Alexa@conocophillips.com>; Viator, Brandon S <Brandon.S.Viator@conocophillips.com>; Imm, Teresa (timm@asrc.com) <timm@asrc.com>; Davidson, Temple (DNR) <temple.davidson@alaska.gov>; Kruse, Rebecca D (DNR) <rebecca.kruse@alaska.gov> Subject: Comment for Docket Number OTH-16-025, GMT1 Hello, Please see the attached letter from Deputy Director James B. Beckham to Commissioner Foerster mailed on December 15, 2016. Kevin Pike Unit Manager State of Alaska DNR Division of Oil & Gas 907-269-8451 CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Department of Natural Resources (DNR), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e- mail, please delete it, without first saving or forwarding it, and, so that the DNR is aware of the mistake in sending it to you, contact Kevin Pike at 907-269-8451 or Kevin.Pike(&alaska.gov. Carlisle, Samantha J (DOA) From: Carlisle, Samantha J (DOA) Sent: Wednesday, November 23, 2016 10:11 AM To: Davidson, Temple (DNR); rbrumbau@blm.gov; 'mistyj.alexa@cop.com'; Larsen, John M (DOR); 'Chmielowski, Jessie'; 'wsvejnoh@blm.gov'; Munisteri, Islin W M (DNR) Cc: Colombie, Jody J (DOA) Subject: Time extension OTH-16-025 All - The AOGCC is extending the deadline and leaving the record open regarding Docket Number: OTH-16-025 until December 19, 2016 close of business. Any future communication regarding this matter must be submitted in writing AND a copy sent to ALL affected parties. Please send this to others in your organization who need it. Thank you, Samantha Carlisle [executive `secretary Ill ii is Alaska Oil. and (Gas (7onse.rvation C:'ornmission 333 11%rst Tit AV('rttrc , Anchorage, AK 995(7".1. (907) 793-122:3 ski iiiantha ca rtisie6()aIaska.s-Yov CONFIDENTIALITY iN077CE. This c -mail message, including, any atiachments, contains halon abon from the Alaska Oil and Gas Conservation Commission (ACXXV), State. of Alaska and is for the sole use of the. intended rccipient(s). It may contain confidential and/or privileged information. l'he unauthorized review, List,, or disclosuIV of such inforniatian nay violate staid or federal law. if you are an unintended recipient of this c -mail, please delete it, without first: saving or, forwarding, it:, and, so that the AOGC'C is aware of the mistake ni sending, it to you, contact Saniantha Carlisle at (907) 793-1223 or Saurantha.Ca7lislc<alaska. Carlisle, Samantha J (DOA) From: Davidson, Temple (DNR) Sent: Wednesday, November 23, 2016 9:41 AM To: Colombie, Jody J (DOA) Cc: Carlisle, Samantha J (DOA) Subject: TD has a question? Hi Jody, Left Samantha a message, but then it dawned on me to just email you. The AOGCC hearing on November 17 concluded with a request to the affected parties to provide non -objection to the meter allocation factor of 1 for GMT, and to provide the technical rationale for their response. The due date for those letters was designated as November 28. DNR would like to request an extension of that due date, until December 19. Our new Director arrives Monday the 28' and we need additional time to re -brief the issue. My specific question is — in what format would you like to receive that request? Thank you Temple Ms. Temple Davidson Petroleum Reservoir Engineer Units Section Chief State of Alaska Department of Natural Resources Division of Oil and Gas 550 W. 7th Avenue Anchorage, Alaska 99501 907.269.8784 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Department of Natural Resources (DNR), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the DNR is aware of the mistake in sending it to you, contact Temple Davidson at 907- 269-8784 or temple.davidson@alaska.gov. Carlisle, Samantha J (DOA) From: Chmielowski, Jessie <jchmielowski@blm.gov> Sent: Tuesday, November 22, 2016 2:56 PM To: Carlisle, Samantha J (DOA) Cc: Wayne Svejnoha; Brumbaugh, Robert Subject: BLM Allocation Factor Letter: request extension Follow Up Flag: Follow up Flag Status: Completed Samantha, The BLM requests an extension to the November 28, 2016 deadline to submit a letter to the AOGCC regarding the proposed Greater Mooses Tooth allocation factor. Due to the Thanksgiving holiday this week, several more days are needed to collect required internal approvals. The BLM proposes to have the letter to the AOGCC by close of business on Wednesday, November 30, 2016. Thanks, Jessie Jessie Chmielowski Petroleum Engineer, BLM Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Thursday, November 17, 2016 1:32 PM To: Brumbaugh, Robert Subject: FW: Greater Moose's Tooth metering FYI Email was discussed this moring. From: Roby, David S (DOA) Sent: Thursday, November 17, 2016 12:16 PM To: Colombie, Jody J (DOA) <jody.colombie@alaska.gov> Subject: FW: Greater Moose's Tooth metering Dave Roby (907)793-1232 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Dave Roby at (907)793-1232 or dave.robv@alaska.aov. From: Alper, Ken (DOR) Sent: Wednesday, November 16, 2016 6:24 PM To: French, Hollis (DOA) <hollis.french@alaska.gov>; Larsen, John M (DOR) <iohn.larsen@alaska.eov> Cc: Seamount, Dan T (DOA) <dan.seamount@alaska.gov>; Regg, James B (DOA) <iim.regg@alaska.eov>; Roby, David S (DOA) <dave.roby@alaska.gov> Subject: RE: Greater Moose's Tooth metering Hollis I'm sure John has more to add, and will be at the hearing in the morning. But in general we can assume that the Alpine production is legacy, and thus paying production taxes at the full rate (4% gross floor at low prices, 35% net less per barrel credit at high prices). In contrast, the new production from GMT1 will be GVR-eligible which means not held to the floor at low prices (we estimated for Rep. Gara last year that "new oil" paid a zero tax below about $73 oil), and a substantially reduced tax due to GVR at higher prices. I appreciate the comment on metering error, but my guess is that the more likely direction is down due to shrinkage / processing losses. So in that case, any volume reduction will come from the Alpine side of the mix and, in effect, the state could actually receive less total production taxes after production began. This is an important project and I don't want to be the fly in the ointment, but this is something that we all should be aware of. Best Ken Ken Alper, Director Alaska Department of Revenue Tax Division 907-465-8221 SECURITY NOTICE: The state cannot guarantee the security of emails sent to or from a state employee outside the state email system. If you do not want to communicate with the Department of Revenue Tax Division via email, please contact the Tax Division in Juneau at (907) 465- 2320 or in Anchorage at (907) 269-6620. CONFIDENTIALITY NOTICE: This email message including any attachments is for the sole use of the intended recipient(s) and may contain confidential and privileged information. Any unauthorized review, use, or disclosure is prohibited. From: French, Hollis (DOA) Sent: Wednesday, November 16, 2016 2:38 PM To: Larsen, John M (DOR) <iohn.larsen@alaska.gov> Cc: Alper, Ken (DOR) <ken.alper@alaska.gov>; Seamount, Dan T (DOA) <dan.seamount@alaska.gov>; Regg, James B (DOA) <iim.regg@alaska.gov>; Roby, David S (DOA) <dave.robv@alaska.gov> Subject: Greater Moose's Tooth metering John, We had a pre -hearing meeting today about the Greater Moose's Tooth metering request. In discussing it I came up with a question and it appears the answer may lie with you, or perhaps with someone at DNR who has knowledge of the appropriate royalty rates that apply. As you know, the request is to meter oil leaving GMT with a Coriolis meter and water cut analyzer. Since the Coriolis meter can't really be proved in the traditional sense, we are being asked to declare that the meter is accurate and gets a meter factor of 1.0. The GMT oil will then be combined with GMT's produced gas and shipped to CDS, where it will commingle with that fluid, which will all then be processed through Alpine's facilities. The LACT metering will take place in the normal fashion, at the outflow of the Alpine facility. I'm interested in the potential fiscal impact to the state if the Coriolis meter is inaccurate. Here's the hypothetical behind the question. Let's assume that Alpine oil is steady at 90,000 bbls per day. Let's assume that CD5 is steady at 10,000 bbls per day. 1. If GMT flow really equals 9000 bbls a day, but the Coriolis meter is off by about 11% and counts the oil as 10,000 bbls a day, then the LACT meters at Alpine will allocate the 109,000 bbls it counts as 10,000 to GMT and 99,000 to Alpine and CD5. 2. If GMT flow is really 11,000 bbls a day, but the Coriolis meter is off in the other direction by 10% and counts the oil as 10,000 bbls a day, then the LACT meters at Alpine will allocate the 101,000 bbls it counts as 10,000 to GMT and 101,000 to Alpine and CD5. The question is what is the financial impact to the state under each scenario? Any light you can shed on this will be very much appreciated. Yours Hollis French Colombie, Jody J (DOA) From: Foerster, Catherine P (DOA) Sent: Tuesday, November 01, 2016 10:02 AM To: Ballantine, Tab A (LAW) Cc: Colombie, Jody J (DOA) Subject: FW: Docket No. OTH 16-25 - 12Oct16- GMTU FYI. From: Foerster, Catherine P (DOA) Sent: Monday, October 31, 2016 10:04 PM To: Seamount, Dan T (DOA) <dan.seamount@alaska.gov>; French, Hollis (DOA) <hollis.french@alaska.gov> Subject: Fwd: Docket No. OTH 16-25 - 120ct16- GMTU FYI. I won't be there so please consider the DOR request. Sent from my Phone Begin forwarded message: From: "Larsen, John M (DOR)" <iohn.larsen@alaska.gov> Date: October 31, 2016 at 4:17:12 PM AKDT To: "Foerster, Catherine P (DOA)" <cathy.foerster@alaska.gov>, "Alper, Ken (DOR)" <ken.alper@alaska.gov> Subject: Docket No. OTH 16-25-12Oct16- GMTU Commissioner Foerster The Department of Revenue (DOR) respectfully requests the AOGCC proceed to hold the hearing scheduled for November 17, 2016 regarding the allocation factor to be used by ConocoPhillips for fiscal allocations for oil and gas produced from the Greater Moose's Tooth and Colville River Units. Additionally, the DOR also requests that the period for public comment be extended for a reasonable number of business days beyond the date of the public hearing in order to allow the DOR time to review and understand comments made at the hearing, as opposed to having comments due at the close of the hearing as indicated in the AOGCC's public notice. Respectfully, John Larsen Audit Master Department of Revenue, Tax Division 550 W. 7th Ave., Ste. 500 Anchorage, AK 99501 Tel (907) 269-8436 fax (907) 269-6644 aohn.la rsen(a)a laska.gov Any guidance provided by this emah ,s not a binding legal opinion, binding ruling o, binding interpretation that may be relied upon, but merely guidance concerning existing statutes and regulations. The statutes and regulations control. There may be other facts and circumstances or undisclosed facts and information that would have changed any guidance that may be provided if we were aware of it. SECURITY NOTICE: The state cannot guarantee the security of emails sent to or from a state employee outside the state email system. If you do not want to communicate with the Department of Revenue Tax Division via email, please contact the Tax Division in Anchorage at (907) 269-6620 or in Juneau at (907) 465-2320. CONFIDENTIALITY NOTICE: This email message including any attachments is for the sole use of the intended recipient(s) and may contain confidential and privileged information. Any unauthorized review, use, or disclosure is prohibited. THE STATE 'ALASKA GOVERNOR BILL WALKER December 19, 2016 Commissioner Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 W. 70'Avenue Anchorage, AK 99501 Re: Greater Moose's Tooth (GMTI) Meter Allocation Factor Dear Commissioner Foerster Department of Revenue TAX DIVISION Robert B. Atwood Building 550 West Th Avenue, Suite 500 Anchorage, Alaska 99501-3566 Main: 907.269.6620 Fax: 907.269.6644 HAND DELIVERED RECEIVE DEC 19 2016 ADCC ConocoPhillips Alaska, Inc. (CPAI) has proposed that a production allocation factor for oil and gas produced from GMTI be fixed at 1.0 and that an exception to 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 for the maximization of recovery from GMTI. By letter dated October 12, 2016 the AOGCC indicated that the AOGCC was not certain the mineral rights owners of GMTI and the Colville River Unit (CRU) fully understood the implications of assigning a fixed allocation factor of 1.0 to production from GMTI while allowing CRU a floating allocation factor. At a hearing held by the AOGCC on November 17, 2016, the AOGCC requested comment from the Department of Revenue (DOR) regarding CPAI's proposed GMTI allocation factor of 1.0. Even though the DOR is not a mineral rights owner in either GMT1 or the CRU, the DOR, as the taxing authority for the State of Alaska (State), does have an interest in these matters. The DOR does have some concerns regarding a potential loss of revenues to the State due to the absence of a sales quality meter prior to production leaving GMTI and the commingling with production from the CRU. As the AOGCC may, or may not, be aware production from GMTI will be eligible to receive the benefit of the 20 percent reduction in gross value, also known as the 'gross value reduction' under AS 43.55.160(f)(1), whereas, production from the CRU will be taxed at a higher standard rate without benefit of the reduction to the gross value. Assigning an allocation factor of 1.0 to GMTI means that volumes produced from GMTI will be considered to be true and accurate prior to being subtracted from total sales production measured by the LACT meter at the Alpine Central Facility in the CRU and that any error in measurement at GMTI will have a direct and inverse impact on production from the CRU. However, the DOR also understands that evidence presented by CPAI to the AOGCC demonstrates that a stand-alone production facility at GMTI in the current economic environment would be cost prohibitive and that the GMTI reserves would likely not be produced in the foreseeable future. Although assigning an allocation factor of 1.0 to the three phase separator and (non-LACT) metering system at GMT1 could result in minor over or under- reporting from either unit, the DOR also understands that there is no bias in the proposed metering system that might result in a consistent error with respect to either unit. Additionally, the BLM conditional approval requires an extensive audit trail and CPAI has proposed third party review of shrinkage factors. The DOR believes that development of the GMTI is in the economic interests of the State, and therefore, does not object to CPAI's proposed metering system and allocation factor of 1.0 for oil and gas produced from GMTL At the November 17, 2016 public hearing the AOGCC also requested the DOR provide the AOGCC with the effective royalty rates from each of the respective units. Attached please find copies of Exhibits A and B from the Alaska Department of Natural Resources Colville River Unit Agreement, 6"' Unit Expansion, and also Attachment 1, including Exhibit B fi-om the BLM's Unit Agreement for the Exploration, Development and Operations of the Greater Moose's Tooth Unit Area that include the requested royalty rates. Sincere nc en Iper Director, Tax ision Department of Revenue Attachments (2) Tr. ADL No./ No. AK No. Legal Description Acres 1 364472 T13N,R5E-U.M. 640.00 931986 Sec. 9, Protracted, All 640.00 Original Sec. 10, Protracted, All 640.00 Depth Royalty NPSL Royalty Mineral Net ORRI Sec. 15, Protracted, All 640.00 Restrictions (%) (%) Owners Owns. Royalty* Owners Sec. 16, Protracted, All 640.00 None 12.5 30 State 100 12.5 CPAI Sec. 21, Protracted, All 640.00 636.00 Sec. 22, Protracted, All 640.00 TOTAL Sec. 28, Protracted, All 640.00 TOTAL 4,480.00 Exhibit A None 12.5 30 State 100 12.5 Enea Tekna Inv. Attached to and made a part 931974 Sec. 17, Protracted, All 640.00 of the Colville River Unit Agreement 0.666600 APC 22.000000 Sec. 18, Protracted, All Original Net Working Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) None 12.5 30 State 100 12.5 CPAI 1.200000 CPA] 78.000000 APC 22.000000 100.000000 2 364470 T13N,R5E-U.M. None 12.5 30 State 100 12.5 Enea Tekna Inv. 0.666600 CPAI 78.000000 931974 Sec. 17, Protracted, All 640.00 W.G. Stroecker 0.666600 APC 22.000000 Sec. 18, Protracted, All 631.00 D.K. Nerland 0.023400 100.000000 See. 19, Protracted, All 633.00 R.E. Wagner 0.643400 Sec. 20, Protracted, All 640.00 2.000000 Sec. 30, Protracted, All 636.00 TOTAL 3,180.00 3 364471 T13N,R5E-U.M. None 12.5 30 State 100 12.5 Enea Tekna Inv. 0.666600 CPAI 78.000000 931976 Sec. 26, Protracted, All 640.00 W.G. Stroecker 0.666600 APC 22.000000 Sec, 27, Protracted, All 640.00 D.K. Nerland 0.023400 100.000000 Sec. 29, Protracted, All 640.00 R. E. Wagner 0.643400 Sec. 31, Protracted, All 639.00 2.000000 Sec. 32, Protracted, All 640.00 Sec. 33, Protracted, All 640.00 Sec. 34, Protracted, All 640.00 Sec. 35, Protracted, All 640.00 Sec. 36, Protracted, All 640.00 TOTAL 5,759.00 Exhibit A to CRUA Revised May 10, 2016 Page t Exhibit A Attached to and made a part of the Colville River Unit Agreement CPAI 66.790810 APC 16.342170 Petro -Hunt 7.336490 XH, LLC 5.750530 RW Res 3.780000 100.000000 5 372104 T12N,R5E-U.M. Above 10,350' 12.5 State 100 12.5 Petro -Hunt 0.440190 CPAI 78.000000 Original 640.00 XH, LLC 0.345030 APC 22.000000 Sec. 4, All Net RW Res Working Tr. ADL No./ Legal CPAI Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions NO (%) Owners Owns. Royalty* Owners (%) Owners NO 4 372105 T12N,R5E-U.M. Above 10,350' 12.5 State 100 12.5 Petro -Hunt 0.440190 CPAI 78.000000 932002 Sec. 5 640.00 XH, LLC 0.345030 APC 22.000000 Sec. 6 577.00 RW Res 0.226800 100.000000 TOTAL 1,217.00 CPAI 1.701900 2.713920 Below 10,350' 12.5 State 100 12.5 CPAI 66.790810 APC 16.342170 Petro -Hunt 7.336490 XH, LLC 5.750530 RW Res 3.780000 100.000000 5 372104 T12N,R5E-U.M. Above 10,350' 12.5 State 100 12.5 Petro -Hunt 0.440190 CPAI 78.000000 932000 Sec. 3, All 640.00 XH, LLC 0.345030 APC 22.000000 Sec. 4, All 640.00 RW Res 0.226800 100.000000 TOTAL 1,280.00 CPAI 1.701900 2.713920 Below 10,350' 12.5 State 100 12.5 Exhibit A to CRUA Revised May 10, 2016 CPAI 66.790810 APC 16.342170 Petro -Hunt 7.336490 XH, LLC 5.750530 RW Res 3.780000 100.000000 Page 2 APC 17.101710 Petro -Hunt 4.286667 RW Res 3.780000 XH, LLC 3.360000 100.000000 Exhibit A to CRUA Revised May 10, 2016 Page 3 Exhibit A Attached to and made a part of the Colville River Unit Agreement Original Net Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 6 372103 T12N,R5E-U.M. Above 10,350' 12.5 State 100 12.5 CPA]* 1.200000 CPAI 78.000000 931998 Sec. 1, Unsurveyed, All 640.00 CPAI** 1.200000 APC 22.000000 Sec. 2, Unsurveyed, All 640.00 Petro -Hunt 0.257200 100.000000 TOTAL 1,280.00 RW Res 0.226800 XH, LLC 0.201600 CPAI 0.874400 3.960000 Below 10,350' 12.5 State 100 12.5 CPAI 71.471623 APC 17.101710 Petro -Hunt 4.286667 RW Res 3.780000 XH, LLC 3.360000 100.000000 7 372103 T12N, R5E-U.M. Above 10,350' 12.5 State 100 12.5 CPAI* 1.200000 CPAI 78.000000 931998 Sec. 11, All 640.00 CPAI** 1.200000 APC 22.000000 Sec. 12, All 640.00 Petro -Hunt 0.257200 100.000000 TOTAL 1,280.00 RW Res 0.226800 XH, LLC 0.201600 Chevron 1.703000 CPAI 0.874400 5.663000 Below 10,350' 12.5 State 100 12.5 Chevron 1.703000 CPAI 71.471623 APC 17.101710 Petro -Hunt 4.286667 RW Res 3.780000 XH, LLC 3.360000 100.000000 Exhibit A to CRUA Revised May 10, 2016 Page 3 Exhibit A Attached to and made a part of the Colville River Unit Agreement Below 10,350' 12.5 State 100 12.5 Chevron 1.703000 CPA] 66.790810 APC 16.342170 Petro -Hunt 7.336490 XH, LLC 5.750530 RW Res 3.780000 100.000000 Exhibit A to CRUA Revised May 10, 2016 Page 4 Original Net Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 8 372104 T12N,R5E-U.M. Above 10,350' 12.5 State 100 12.5 Petro -Hunt 0.440190 CPAI 78.000000 932000 Sec. 9, All 640.00 XH, LLC 0.345030 APC 22.000000 Sec. 10, All 640.00 RW Res 0.226800 100.000000 TOTAL 1,280.00 Chevron 1.703000 CPAI 1.701900 4.416920 Below 10,350' 12.5 State 100 12.5 Chevron 1.703000 CPAI 66.790810 APC 16.342170 Petro -Hunt 7.336490 XH, LLC 5.750530 RW Res 3.780000 100.000000 9 372105 T12N, R5E-U.M. Above 10,350' 12.5 State 100 12.5 Petro -Hunt 0.440190 CPAI 78.000000 932002 Sec. 7, All 580.00 XH, LLC 0.345030 APC 22.000000 Sec. 8, All 640.00 RW Res 0.226800 100.000000 TOTAL 1,220.00 Chevron 1.703000 CPAI 1.701900 4.416920 Below 10,350' 12.5 State 100 12.5 Chevron 1.703000 CPA] 66.790810 APC 16.342170 Petro -Hunt 7.336490 XH, LLC 5.750530 RW Res 3.780000 100.000000 Exhibit A to CRUA Revised May 10, 2016 Page 4 Exhibit A Attached to and made a part of the Colville River Unit Agreement Original Net Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (/) Owners (/) 10 25538 T12N,R5E-U.M. None 12.5 State 100 12.5 Chevron 1.703000 CPAI 78.000000 932100 Sec. 17, All 640.00 APC 22.000000 Sec. 18, All 583.00 100.000000 Sec. 19, All 585.00 Sec. 20, All 640.00 TOTAL 2,448.00 11 372107 T12N,RSE-U.M. Above 8.500' 12.5 State 100 12.5 Petro -Hunt 0.440190 CPAI 78.000000 932006 Sec. 21, SE1/4SE1/4,W1/2SE1/4, XH, LLC 0.345030 APC 22.000000 SW 1/4 280.00 RW Res 0.226800 100.000000 Sec. 22, SWI/4SE1/4, S1/2SW1/4 120.00 Chevron 1.703000 TOTAL 400.00 CPAI 0.880380 3.595400 8,500'-]0,350' 12.5 State 100 12.5 Petro -Hunt 0.440190 CPAI 78.000000 XH, LLC 0.345030 APC 22.000000 RW Res 0.226800 100.000000 Chevron 1.703000 CPAI 1.701900 4.416920 Below 10,350' 12.5 State 100 12.5 Chevron 1.703000 CPAI 66.790810 APC 16.342170 Petro -Hunt 7.336490 XH, LLC 5.750530 RW Res 3.780000 100.000000 Exhibit A to CRUA Revised May 10, 2016 Page 5 Tr. No. 11A Exhibit A Attached to and made a part 8,500'-10,350' 12.5 State 100 12.5 Petro -Hunt 0.440190 CPAI 78.000000 XH, LLC 0.345030 APC 22.000000 RW Res 0.226800 100.000000 Chevron 1.703000 CPAI 1.701900 4.416920 Below 10,350' 12.5 State 100 12.5 Chevron 1.703000 CPAI 66.790810 APC 16.342170 Petro -Hunt 7.336490 XH, LLC 5.750530 RW Res 3.780000 100.000000 Exhibit A to CRUA Revised May 10, 2016 Page 6 of the Colville River Unit Agreement Original Net Working ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 391577 T12N,R5E-U.M. Above 8.500' 12.5 State 100 12.5 Petro -Hunt 0.440190 CPAI 78.000000 341402 Sec. 15, All 640.00 XH, LLC 0.345030 APC 22.000000 See. 16, All 640.00 RW Res 0.226800 100.000000 TOTAL 1,280.00 Chevron 1.703000 CPAI 0.880380 3.595400 8,500'-10,350' 12.5 State 100 12.5 Petro -Hunt 0.440190 CPAI 78.000000 XH, LLC 0.345030 APC 22.000000 RW Res 0.226800 100.000000 Chevron 1.703000 CPAI 1.701900 4.416920 Below 10,350' 12.5 State 100 12.5 Chevron 1.703000 CPAI 66.790810 APC 16.342170 Petro -Hunt 7.336490 XH, LLC 5.750530 RW Res 3.780000 100.000000 Exhibit A to CRUA Revised May 10, 2016 Page 6 CPAI 68.928524 APC 17.641213 Petro -Hunt 5.409868 XH, LLC 4.240395 RW Res 3.780000 100.000000 There is no Tract 13 14 25530 T12N,R4E-U.M. None 12.5 State 51.97 6.49625 Chevron 1.703000 CPAI 78.000000 932098 Sec. 24, All 640.00 ASRC 48.03 5.00375 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 640.00 11.5 2.703000 100.000000 Exhibit A to CRUA Revised May 10, 2016 Page 7 Exhibit A Attached to and made a part of the Colville River Unit Agreement Original Net Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description p Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (% Owners (%) 12 372106 T12N,R5E-U.M. Above 8,500' 12.5 State 100 12.5 CPAI* 1.515000 CPAI 78.000000 932004 Sec. 13, All 640.00 Petro -Hunt 0.324590 APC 22.000000 Sec. 14, All 640.00 XH, LLC 0.254430 100.000000 Sec. 23, All 640.00 RW Res 0.226800 TOTAL 1,920.00 Chevron 1.703000 CPAI 0.649180 6.188000 8,500'-10,350' 12.5 State 100 12.5 CPAI* 1.515000 CPAI 78.000000 Petro -Hunt 0.324590 APC 22.000000 XH, LLC 0.254430 100.000000 RW Res 0.226800 Chevron 1.703000 CPAI 1.255180 5.279000 Below 10,350' 12.5 State 100 12.5 Chevron 1.703000 CPAI 68.928524 APC 17.641213 Petro -Hunt 5.409868 XH, LLC 4.240395 RW Res 3.780000 100.000000 There is no Tract 13 14 25530 T12N,R4E-U.M. None 12.5 State 51.97 6.49625 Chevron 1.703000 CPAI 78.000000 932098 Sec. 24, All 640.00 ASRC 48.03 5.00375 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 640.00 11.5 2.703000 100.000000 Exhibit A to CRUA Revised May 10, 2016 Page 7 Exhibit A Attached to and made a part of the Colville River Unit Agreement 16 25529 T12N,R4E.-U.M. None 12.5 State 47.37 5.92125 Original 1.703000 CPAI 78.000000 ASRC 73.77 10.628335 932096 Sec. 22 excl. NPRA 346.19 Net Kuukpik Corp. Working Tr. ADL Nol Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 15 25529 T12N,R4E-U.M. None 12.5 State 50.05 6.25625 Chevron 1.703000 CPAI 78.000000 932096 Sec. 23, All 640.00 ASRC 49.95 5.24375 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 640.00 11.5 2.703000 100.000000 16 25529 T12N,R4E.-U.M. None 12.5 State 47.37 5.92125 Chevron 1.703000 CPAI 78.000000 ASRC 73.77 10.628335 932096 Sec. 22 excl. NPRA 346.19 ASRC 52.63 5.57875 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 346.19 11.5 2.703000 100.000000 17 387211 T12N,R4E-U.M. None 16.66667 State 47.37 7.895002 Kuukpik Corp. 1.666667 CPAI 78.000000 932197 Sec. 22, All, within 257.86 ASRC 52.63 7.105001 APC 22.000000 NPRA, excl. USS 9502 15.000003 100.000000 Lot 2 TOTAL 257.86 18-A 387211 T12N,R4E-U.M. None 16.66667 State 26.23 4.371668 Kuukpik Corp. 1.666667 CPAI 78.000000 932197 Sec. 21, All, within NPRA 229.92 ASRC 73.77 10.628335 APC 22.000000 TOTAL 229.92 15.000003 100.000000 18-B 387211 T12N,R4E-U.M. None 16.66667 State 26.23 4.37167 Kuukpik Corp. 1.000000 CPAI 78.000000 932197 Sec. 21, tide & submerged lands ASRC 73.77 11.295 APC 22.000000 seaward of the line of mean high 15.66667 100.000000 water as shown on the official tract map for Oil and Gas Lease Sale 43 90.00 TOTAL 90.00 Exhibit A to CRUA Revised May 10, 2016 Page 8 Exhibit A Attached to and made a part of the Colville River Unit Agreement Exhibit A to CRUA Revised May 10, 2016 Page 9 Original Net Working Tr. ADL Nol Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 19 380095 T12N,R4E-U.M. None 16.667 State 26.23 4.37175 Kuukpik Corp. 1.000000 CPAI 78.000000 932056 Sec. 21, All, excl. tide & ASRC 73.77 11.29525 APC 22.000000 submerged lands seaward of the 15.667 100.000000 line of mean high water as shown on the official tract map for Oil and Gas Lease Sale 43 and NPRA 320.08 TOTAL 320.08 20 380095 T12N,R4E-U.M. None 16.667 State 87.45 14.57529 Kuukpik Corp. 1.000000 CPAI 78.000000 932056 Sec. 20, All, excl. tide & ASRC 12.55 1.09171 APC 22.000000 submerged lands seaward of 15.667 100.000000 the line of mean high water as shown on the official tract map for Oil and Gas Lease Sale 43 178.00 TOTAL 178.00 21 387211 T12N,R4E-U.M. None 16.66667 State 87.45 14.575 Kuukpik Corp. 1.000000 CPAI 78.000000 932197 Sec. 20, All, tide & submerged ASRC 12.55 1.09167 APC 22.000000 lands seaward of the line 15.66667 100.000000 of mean high water as shown on the official tract map for Oil and Gas Lease Sale 43 462.00 TOTAL 462.00 Exhibit A to CRUA Revised May 10, 2016 Page 9 Exhibit A Attached to and made a part of the Colville River Unit Agreement Original Net Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 22 ASRC NPRA 1 T12N,R3E-U.M. None 12.5 ASRC 100 11.25 Kuukpik Corp. 1.250000 CPAI 78.000000 932126 Sec. 25 640.00 AEP 22.000000 Sec. 26 640.00 100.000000 Sec. 27 640.00 Sec. 34 640.00 Sec. 3 5 640.00 Sec. 36 640.00 TOTAL 3,840.00 23 ASRC NPRA 2 T12N,R4E-U.M. None 16.667 ASRC 100 15 Kuukpik Corp. 1.666700 CPAI 78.000000 932128 Sec. 28 565.98 AEP 22.000000 Sec. 29 402.79 100.000000 Sec. 30 321.28 Sec. 31 541.00 Sec. 32 534.95 Sec. 33 640.00 TI1N,R4E-U.M. Sec. 4 640.00 Sec. 5 640.00 Sec. 7 593.24 Sec. 8 640.00 Sec. 9 640.00 Sec. 21 640.00 TOTAL 6,799.24 24 387212 T12N,R4E-U.M. None Sliding State 8 1.333334 KuukpikCorp. **1.66666 CPAI 78.000000 932199 Sec. 27, All, within NPRA 550.29 Scale ASRC 92 **13.66666 APC 22.000000 TOTAL 550.29 ** 16.6666 15.000003 100.000000 Exhibit A to CRUA Revised May 10, 2016 Page 10 Exhibit A Attached to and made a part of the Colville River Unit Agreement 29 25558 1 12N-R5E, U.M. None 12.5 State 100 12.5 Chevron 1.703000 CPAI 78.000000 Original Sec. 29, All 640.00 APC 22.000000 Net Sec. 30, All Working Tr. ADL No./ Legal Sec. 31, All Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 25 25530 T12N,R4E-U.M. 640.00 None 12.5 State 8 1.000000 Chevron 1.703000 CPAI 78.000000 640.00 932098 See. 27, All, excl. NPRA 89.71 ASRC 92 10.500000 Kuukpik Corp. 1.000000 APC 22.000000 Sec. 34, All TOTAL 89.71 TOTAL 2,560.00 11.500000 2.703000 100.000000 26 387212 T12N,R4E-U.M. None Sliding State 60.18 10.030002 Kuukpik Corp. **1.66666 CPAI 78.000000 932199 Sec. 26, All, within NPRA 17.36 Scale ASRC 39.82 **4.970001 APC 22.000000 TOTAL 17.36 ** ] 6.6666 15.000003 100.000000 27 25530 T12N,R4E-U.M. None 12.5 State 60.18 7.522500 Chevron 1.703000 CPAI 78.000000 932098 Sec, 26, All, excl. NPRA 622.64 ASRC 39.82 3.977500 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 622.64 11.500000 2.703000 100.000000 28 25530 T12N,R4E-U.M. None 12.5 State 55.79 6.973750 Chevron 1.703000 CPAI 78.000000 932098 Sec. 25, All 640.00 ASRC 44.21 4.526250 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 640.00 11.500000 2.703000 100.000000 29 25558 1 12N-R5E, U.M. None 12.5 State 100 12.5 Chevron 1.703000 CPAI 78.000000 932102 Sec. 29, All 640.00 APC 22.000000 Sec. 30, All 588.00 100.000000 Sec. 31, All 591.00 Sec. 32, All 640.00 TOTAL 2,459.00 30 25557 T12N-R5E,U.M. None 12.5 State 100 12.5 Chevron 1.703000 CPAI 78.000000 932106 Sec. 27, All 640.00 APC 22.000000 Sec. 28, All 640.00 100.000000 Sec. 33, All 640.00 Sec. 34, All 640.00 TOTAL 2,560.00 Exhibit A to CRUA Revised May 10, 2016 Page 1 1 Exhibit A Attached to and made a part of the Colville River Unit Agreement Original Net Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 31 372108 T12N,R5E-U.M. Above 8,500' 12.5 State 100 12.5 CPA]* 1.515000 CPAI 78.000000 932008 Sec. 26, NWI/4NW 1/4, Petro -Hunt 0.324590 APC 22.000000 S 1/2 NW 1/4, SW 1/4, W 1/2SE1/4, 360.00 XH, LLC 0.254430 100.000000 TOTAL 360.00 RW Res 0.226800 Chevron 1.703000 CPAI 0.649180 4.673000 8,500'-10,350' 12.5 State 100 12.5 CPAI* 1.515000 CPAI 78.000000 Petro -Hunt 0.324590 APC 22.000000 XH, LLC 0.254430 100.000000 RW Res 0.226800 Chevron 1.703000 CPAI 1.255180 5.279000 Below 10,350' 12.5 State 100 12.5 Chevron 1.703000 CPAI 68.928524 APC 17.641213 Petro -Hunt 5.409868 XH, LLC 4.240395 RW Res 3.780000 100.000000 There is no Tract 32 33 391579 T12N,R5E-U.M. Above 7,130' 16.667 State 58.42 9.736860 CPAI 0.745500 CPAI 78.000000 341413 Sec. 36, SWI/4SW1/4 40.00 ASRC 41.58 5.930140 Chevron 1.703000 APC 22.000000 TOTAL 40.00 15.667000 Kuukpik Corp. 1.000000 100.000000 3.448500 Exhibit A to CRUA Revised May 10, 2016 Page 12 Exhibit A Attached to and made a part of the Colville River Unit Agreement APC 17.641213 Petro -Hunt 5.409868 XH, LLC 4.240395 RW Res 3.780000 100.000000 35 380096 T12N,R4E-U.M. None 16.667 Original 50.72 8.453500 Chevron Net CPAI Working Tr. ADL No] Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 33 391579 Below 7,130' 16.667 State 58.42 9.736860 CPAI 0.745500 7.405000 Chevron 1.703000 341413 78.000000 932058 ASRC 41.58 5.930140 Chevron 1.703000 CPAI 77.700000 Kuukpik Corp. (cont.) APC 22.000000 TOTAL 15.667000 Kuukpik Corp. 1.000000 APC 22.000000 11.500000 2.703000 100.000000 3.448500 Petro -Hunt 0.300000 100.000000 34 391580 T12N,R5E-U.M. Above 10,350' 12.5 State 100 12.5 CPAI* 1.515000 CPAI 78.000000 341403 Sec. 35, All 640.00 Petro -Hunt 0.324590 APC 22.000000 TOTAL 640.00 XH, LLC 0.254430 100.000000 RW Res 0.226800 Chevron 1.703000 CPAI 1.255180 5.279000 Below 10,350' 12.5 State 100 12.5 Chevron 1.703000 CPAI 68.928524 APC 17.641213 Petro -Hunt 5.409868 XH, LLC 4.240395 RW Res 3.780000 100.000000 35 380096 T12N,R4E-U.M. None 16.667 State 50.72 8.453500 Chevron 1.703000 CPAI 78.000000 932058 Sec. 36, All 640.00 ASRC 49.28 7.213500 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 640.00 15.667000 2.703000 100.000000 36 25530 T12N,R4E-U.M. None 12.5 State 59.24 7.405000 Chevron 1.703000 CPAI 78.000000 932058 Sec. 35, All, excl. NPRA 596.62 ASRC 40.76 4.095000 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 596.62 11.500000 2.703000 100.000000 Exhibit A to CRUA Revised May 10, 2016 Page 13 Exhibit A Attached to and made a part of the Colville River Unit Agreement 38 387212 T12N,R4E-U.M. None Sliding Original 78.000000 932191 Sec. 3, All, within NPRA 932199 Sec. 34, All, within NPRA Net ASRC 99.82 **14.97000 APC Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 37 387212 T12N,R4E-U.M. None Sliding State 59.24 9.873335 Kuukpik Corp. **1.66666 CPAI 78.000000 932199 Sec. 35, All, within NPRA 43.38 Scale ASRC 40.76 **5.126668 None 16.667 APC 22.000000 8.918510 TOTAL 43.38 **16.6666 CPAI 78.000000 15.000003 Sec. 1, All 640.00 100.000000 38 387212 T12N,R4E-U.M. None Sliding State 0.18 0.03 Kuukpik Corp. **1.66666 CPAI 78.000000 932191 Sec. 3, All, within NPRA 932199 Sec. 34, All, within NPRA 640.00 Scale ASRC 99.82 **14.97000 APC 22.000000 588.85 **16.6666 TOTAL 640.00 **16.6666 15.000003 100.000000 57.25 39 387207 T11N,R4E-U.M. None Sliding State 10.25 1.708334 Kuukpik Corp. **1.66666 CPAI 78.000000 932191 Sec. 3, All, within NPRA 588.85 Scale ASRC 89.75 **13.29166 APC 22.000000 TOTAL 588.85 **16.6666 15.000003 100.000000 40 380075 TI IN-R4E- U.M. None 16.667 State 10.25 1.708370 Kuukpik Corp. 1.000000 CPAI 78.000000 932034 Sec. 3, All, excl. NPRA 51.15 ASRC 89.75 13.958630 APC 22.000000 TOTAL 51.15 15.667000 100.000000 TIIN-R4E, U.M. There is no Tract 41 42 380075 TIIN-R4E, U.M. None 16.667 State 57.25 9.541860 Kuukpik Corp. 1.000000 CPAI 78.000000 932034 Sec. 2, All 640.00 ASRC 42.75 6.125140 APC 22.000000 TOTAL 640.00 15.667000 100.000000 43 380075 T11N-R4E,U.M. None 16.667 State 53.51 8.918510 Chevron 1.703000 CPAI 78.000000 932034 Sec. 1, All 640.00 ASRC 46.49 6.748490 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 640.00 15.667000 2.703000 100.000000 Exhibit A to CRUA Revised May 10, 2016 Page 14 Tr. ADL No./ No. AK No. Legal Description Acres 44 25559 T11N,R5E-U.M. (%) 932104 Sec. 5, All 640.00 932108 Sec. 6, All 593.00 0.226800 Sec. 7, All 596.00 Sec. 8, All 640.00 TOTAL 2,469.00 Exhibit A Attached to and made a part of the Colville River Unit Agreement Original Depth Royalty NPSL Royalty Mineral Net ORRI Restrictions (%) (%) Owners Owns. Royalty* Owners None 12.5 State 100 12.5 Chevron 45 372095 T11N,R5E-U.M. Above 10,350' 12.5 State 100 12.5 CPAI* 931992 Sec. 3, All 640.00 Petro -Hunt Sec. 4, All 640.00 XH, LLC Sec. 9, All 640.00 RW Res Sec. 10, All 640.00 Chevron TOTAL 2,560.00 CPAI Below 10,350' 12.5 State 100 12.5 Chevron Net Working ORRI Tract Interest (%) Owners (%) 1.703000 CPAI 78.000000 APC 22.000000 100.000000 1.515000 CPAI 78.000000 None 12.5 0.324590 APC 22.000000 CPAI 0.254430 932108 100.000000 640.00 0.226800 1.703000 22.000000 TOTAL 1.255180 5.279000 100.000000 1.703000 CPAI 68.928524 APC 17.641213 Petro -Hunt 5.409868 XH, LLC 4.240395 RW Res 3.780000 100.000000 46 25560 T11N,R5E-U.M. None 12.5 State 100 12.5 Chevron 1.703000 CPAI 78.000000 932108 Sec. 2, All 640.00 APC 22.000000 TOTAL 640.00 100.000000 47 391581 T11N,R5E-U.M. None 12.5 State 63.69 7.961250 Chevron 1.703000 CPAI 78.000000 341400 Sec. 1, W1/2W1/2 160.00 ASRC 36.31 3.538750 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 160.00 11.500000 2.703000 100.000000 Exhibit A to CRUA Revised May 10, 2016 Page 15 Exhibit A Attached to and made a part of the Colville River Unit Agreement 53 380075 T11N-R4E, U.M. None 16.667 Original 2.39 0.398340 Kuukpik Corp. 1.000000 CPAI Net Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners N There is no Tract 48 54 387207 T11N-R4E-U.M. None 49 25560 T11N,R5E-U.M. 0.398333 None 12.5 State 57.68 7.210000 Chevron 1.703000 CPAI 78.000000 ASRC 932108 Sec. 11, All 640.00 APC 22.000000 ASRC 42.32 4.290000 Kuukpik Corp. 1.000000 APC 22.000000 15.000003 TOTAL 640.00 100.000000 11.500000 2.703000 100.000000 50 380075 T11N-R4E, U.M. None 16.667 State 76.87 12.811920 Chevron 1.703000 CPAI 78.000000 Kuukpik Corp. **1.66666 932034 Sec. 12, All 640.00 932193 Sec. 16, All, within NPRA ASRC 23.13 2.855080 Kuukpik Corp. 1.000000 APC 22.000000 APC 22.000000 TOTAL 640.00 TOTAL 630.47 **16.6666 15.667000 2.703000 100.000000 51 380075 T11N-R4E, U.M. None 16.667 State 70.59 11.765240 Kuukpik Corp. 1.000000 CPAI 78.000000 932034 Sec. 11, All, excl. NPRA 594.02 ASRC 29.41 3.901760 APC 22.000000 TOTAL 594.02 15.667000 100.000000 52 387207 T11N,R4E-U.M. None Sliding State 70.59 11.765002 Kuukpik Corp. **1.66666 CPAI 78.000000 932191 Sec. 11, All, within NPRA 45.98 Scale ASRC 29.41 **3.235001 APC 22.000000 TOTAL 45.98 **16.6666 15.000003 100.000000 53 380075 T11N-R4E, U.M. None 16.667 State 2.39 0.398340 Kuukpik Corp. 1.000000 CPAI 78.000000 932034 Sec. 10, All, excl. NPRA 5.83 ASRC 97.61 15.268660 APC 22.000000 TOTAL 5.83 15.667000 100.000000 54 387207 T11N-R4E-U.M. None Sliding State 2.39 0.398333 Kuukpik Corp. **1.66666 CPAI 78.000000 932191 Sec. 10, All, within NPRA 634.17 Scale ASRC 97.61 **14.60167 APC 22.000000 TOTAL 634.17 **16.6666 15.000003 100.000000 55 387208 T11N-R4E-U.M. None Sliding State 0.34 0.056667 Kuukpik Corp. **1.66666 CPAI 78.000000 932193 Sec. 16, All, within NPRA 630.47 Scale ASRC 99.66 **14.94333 APC 22.000000 TOTAL 630.47 **16.6666 15.000003 100.000000 Exhibit A to CRUA Revised May 10, 2016 Page 16 Exhibit A Attached to and made a part of the Colville River Unit Agreement 57 387208 T11N-R4E-U.M. None Sliding Original Kuukpik Corp. **1.66666 CPAI 78.000000 Net 103.94 Scale Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 56 380075 T11N-R4E, U.M. None 16.667 State 0.34 0.05667 Kuukpik Corp. 1.000000 CPAI 78.000000 932034 Sec. 16, All, excl. NPRA 9.53 ASRC 99.66 15.61033 APC 22.000000 TOTAL 9.53 15.667 100.000000 57 387208 T11N-R4E-U.M. None Sliding State 39.8 6.633335 Kuukpik Corp. **1.66666 CPAI 78.000000 932193 Sec. 15, All, within NPRA 103.94 Scale ASRC 60.2 **8.366668 APC 22.000000 TOTAL 103.94 **16.6666 15.000003 100.000000 58 380075 T11N-R4E, U.M. None 16.667 State 39.8 6.633470 Kuukpik Corp. 1.000000 CPAI 78.000000 932034 Sec. 15, All, excl. NPRA 536.06 ASRC 60.2 9.033530 APC 22.000000 TOTAL 536.06 15.667000 100.000000 59 380075 T11N-R4E, U.M. None 16.667 State 53.63 8.938510 Kuukpik Corp. 1.000000 CPAI 78.000000 932034 Sec. 14, All 640.00 ASRC 46.37 6.728490 APC 22.000000 TOTAL 640.00 15.667000 100.000000 60 380075 T11N-R4E, U.M. None 16.667 State 67.55 11.258560 Kuukpik Corp. 1.000000 CPAI 78.000000 932034 Sec. 13, All 640.00 ASRC 32.45 4.408440 APC 22.000000 TOTAL 640.00 15.667000 100.000000 61 372097 T11N,R5E-U.M. Above 10,350' 12.5 State 100.00 12.50000 CPAI* 1.515000 CPAI 78.000000 931996 Sec. 17, All 640.00 Petro -Hunt 0.324590 APC 22.000000 Sec. 18, All 599.00 XH, LLC 0.254430 100.000000 TOTAL 1,239.00 RW Res 0.226800 Chevron 1.703000 CPAI 1.255180 5.279000 Exhibit A to CRUA Revised May 10, 2016 Page 17 Exhibit A Attached to and made a part of the Colville River Unit Agreement Petro -Hunt 5.409868 XH, LLC 4.240395 RW Res 3.780000 100.000000 62 372096 TI IN, R5E-U.M. Above 10,350' 12.5 State 100 12.50000 CPAI* 1.515000 CPAI 78.000000 931994 Sec. 16, All 640.00 Petro -Hunt 0.324590 APC 22.000000 TOTAL 640.00 XH, LLC 0.254430 100.000000 RW Res 0.226800 Chevron 1.703000 CPAI 1.255180 5.279000 Below 10,350' 12.5 State 100 12.50000 Chevron 1.703000 CPAI 68.928524 APC 17.641213 Petro -Hunt 5.409868 XH, LLC 4.240395 RW Res 3.780000 100.000000 63 384210 T11N,R5E,U.M. None 16.667 State 50.01 8.335170 Chevron 1.703000 CPAI 78.000000 932078 Sec. 15, W1/2,NE1/4,N1/2SE1/4, ASRC 49.99 7.331830 CPAI 1.328100 APC 22.000000 S W 1/4SE 1 /4 600.00 15.667000 Kuukpik Corp. 1.000000 100.000000 TOTAL 600.00 4.031100 Exhibit A to CRUA Revised May 10, 2016 Page 18 Original Net Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 61 372097 Below 10,350' 12.5 State 100.00 12.500000 Chevron 1.703000 931996 CPAI 68.928524 (Cont.) APC 17.641213 Petro -Hunt 5.409868 XH, LLC 4.240395 RW Res 3.780000 100.000000 62 372096 TI IN, R5E-U.M. Above 10,350' 12.5 State 100 12.50000 CPAI* 1.515000 CPAI 78.000000 931994 Sec. 16, All 640.00 Petro -Hunt 0.324590 APC 22.000000 TOTAL 640.00 XH, LLC 0.254430 100.000000 RW Res 0.226800 Chevron 1.703000 CPAI 1.255180 5.279000 Below 10,350' 12.5 State 100 12.50000 Chevron 1.703000 CPAI 68.928524 APC 17.641213 Petro -Hunt 5.409868 XH, LLC 4.240395 RW Res 3.780000 100.000000 63 384210 T11N,R5E,U.M. None 16.667 State 50.01 8.335170 Chevron 1.703000 CPAI 78.000000 932078 Sec. 15, W1/2,NE1/4,N1/2SE1/4, ASRC 49.99 7.331830 CPAI 1.328100 APC 22.000000 S W 1/4SE 1 /4 600.00 15.667000 Kuukpik Corp. 1.000000 100.000000 TOTAL 600.00 4.031100 Exhibit A to CRUA Revised May 10, 2016 Page 18 Tr. ADL No./ Legal No. AK No. Description Acres 64 391583 TIIN,R5E,U.M. 341411 Sec. 14, NW 1/4NW 1/4 40.00 Kuukpik Corp. TOTAL 40.00 There are no Tracts 65-67 Exhibit A State 57.26 9.543520 Chevron 1.703000 CPAI 78.000000 50 Attached to and made a part ASRC 42.74 6.123480 Kuukpik Corp. 1.000000 APC 22.000000 1.000000 of the Colville River Unit Agreement 15.667000 640.00 2.703000 100.000000 50 Original Kuukpik Corp. 1.000000 Net 22.000000 Working Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest Restrictions (°/6) (%) Owners Owns. Royalty* Owners (%) Owners (%) None 16.667 State 10.465210 Chevron 1.703000 CPAI 78.000000 ASRC 37.21 5.201790 CPAI 1.328100 APC 22.000000 70 384211 15.667000 Kuukpik Corp. 1.000000 State 100.000000 9.298520 CPAI 1.328100 4.031100 78.000000 jovviy 11uN-x:)b,U.M. None 16.667 State 57.26 9.543520 Chevron 1.703000 CPAI 78.000000 50 932040 Sec. 22, NW 1/4, NW 1/4SW 1/4 200.00 ASRC 42.74 6.123480 Kuukpik Corp. 1.000000 APC 22.000000 1.000000 TOTAL 200.00 15.667000 640.00 2.703000 100.000000 50 oy .564L11 111N,KSE-U.M. 9.298520 None 16.667 State 50 8.333500 CPAI 1.328100 CPAI 78.000000 1.000000 932080 Sec. 21, All 640.00 ASRC 50 7.333500 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 640.00 100.000000 T11N,R5E-U.M. Above 7,631' 16.667 State 52.88 15.667000 CPAI 2.328100 CPAI 100.000000 Sec. 19, All 601.00 ASRC 47.12 6.853490 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 601.00 15.667000 2.328100 70 384211 T11N,R5E-U.M. Above 7,631' 16.667 State 55.79 9.298520 CPAI 1.328100 CPAI 78.000000 932080 Sec. 20, All 640.00 ASRC 44.21 6.368480 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 640.00 15.667000 2.328100 100.000000 ] 384211 932080 Exhibit A to CRUA Revised May 10, 2016 Below 7,631' 16.667 State 55.79 9.298520 CPAI 1.328100 CPAI 77.620000 ASRC 44.21 6.368480 Kuukpik Corp. 1.000000 APC 22.000000 15.667000 2.328100 Petro -Hunt 0.380000 100.000000 T11N,R5E-U.M. Above 7,631' 16.667 State 52.88 8.813510 CPAI 1.328100 CPAI 78.000000 Sec. 19, All 601.00 ASRC 47.12 6.853490 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 601.00 15.667000 2.328100 100.000000 Page 19 Exhibit A Attached to and made a part of the Colville River Unit Agreement Original Net Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 71 384211 T11N,R4E-U.M. None Below 7,631' 16.667 State 52.88 8.813510 CPAI 1.328100 CPAI 77.620000 932080 Sec. 22, All, excl. NPRA 228.74 ASRC 47.12 6.853490 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL (Cont.) 15.667000 15.667000 100.000000 2.328100 Petro -Hunt 0.380000 75 387208 TI IN,R4E-U.M. None Sliding State 100.000000 3.558334 72 380077 Tl 1N,R4E-U.M. 78.000000 None 16.667 State 60.51 10.085200 Kuukpik Corp. 1.000000 CPAI 78.000000 22.000000 932036 Sec. 24, All 640.00 411.26 ASRC 39.49 5.581800 15.000003 APC 22.000000 TOTAL 640.00 15.667000 100.000000 73 380077 Tl 1N,R4E-U.M. None 16.667 State 50.67 8.445170 Kuukpik Corp. 1.000000 CPAI 78.000000 932036 Sec. 23, All 640.00 ASRC 49.33 7.221830 APC 22.000000 TOTAL 640.00 15.667000 100.000000 74 380077 T11N,R4E-U.M. None 16.667 State 21.35 3.558400 Kuukpik Corp. 1.000000 CPAI 78.000000 932036 Sec. 22, All, excl. NPRA 228.74 ASRC 78.65 12.108600 APC 22.000000 TOTAL 228.74 15.667000 100.000000 75 387208 TI IN,R4E-U.M. None Sliding State 21.35 3.558334 Kuukpik Corp. **1.66666 CPAI 78.000000 932193 Sec. 22, All, within NPRA 411.26 Scale ASRC 78.65 **11.44166 APC 22.000000 TOTAL 411.26 **16.6666 15.000003 100.000000 76 387209 T11N,R4E-U.M. None Sliding State 2.6 0.433333 Kuukpik Corp. **1.66666 CPAI 78.000000 932195 Sec. 27, All, within NPRA 614.70 Scale ASRC 97.4 **14.56667 APC 22.000000 TOTAL 614.70 **16.6666 15.000003 100.000000 77 380077 932036 Exhibit A to CRUA Revised May 10, 2016 TI1N,R4E-U.M. None 16.667 Sec. 27, All, excl. NPRA 25.30 TOTAL 25.30 State 2.6 0.433340 Kuukpik Corp. 1.000000 CPAI 78.000000 ASRC 97.4 15.233660 APC 22.000000 15.667000 100.000000 Page 20 Exhibit A Attached to and made a part of the Colville River Unit Agreement 79 380077 T11N,R4E-U.M. Original None 16.667 State 48.75 8.125160 Net 1.000000 Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns, Royalty* Owners (%) Owners (% 78 387209 T11N,R4E-U.M. None Sliding State 48.75 8.125002 Kuukpik Corp. **1.66666 CPAI 78.000000 932195 Sec. 26, All, within NPRA 25.23 Scale ASRC 51.25 **6.875001 78.000000 APC 22.000000 640.00 TOTAL 25.23 **16.6666 36.59 5.098460 15.000003 1.000000 APC 22.000000 100.000000 79 380077 T11N,R4E-U.M. 1.328100 CPAI None 16.667 State 48.75 8.125160 Kuukpik Corp. 1.000000 CPAI 78.000000 604.00 15.667000 932036 Sec. 26, All, excl. NPRA 614.77 ASRC 51.25 7.541840 APC 22.000000 TOTAL 614.77 15.667000 100.000000 80 384209 T11N-R4E,U.M. None 16.667 State 63.41 10.568540 CPA] 1.328100 CPAI 78.000000 932076 Sec. 25, All 640.00 ASRC 36.59 5.098460 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 640.00 15.667000 2.328100 100.000000 81 384211 T11N,R5E-U.M. None 16.667 State 50.17 8.361830 CPAI 1.328100 CPAI 78.000000 932046 Sec. 29, All 932080 Sec. 30, All 604.00 ASRC 49.83 7.305170 Kuukpik Corp. 1.000000 APC 22.000000 640.00 15.667000 TOTAL 604.00 15.667000 2.328100 100.000000 82 380082 T11N-R5E,U.M. None 16.667 State 50.86 8.476840 Kuukpik Corp. 1.000000 CPAI 78.000000 932046 Sec. 29, All 640.00 ASRC 49.14 7.190160 APC 22.000000 TOTAL 640.00 15.667000 100.000000 384215 T13N,R4E-U.M. 932084 Sec. 36, Unsurveyed, All excl. tide & submerged lands seaward of the line of mean high water and channel closing line as shown on the official tract map for Oil and Gas Lease Sale 43 TOTAL Exhibit A to CRUA Revised May 10, 2016 597.00 597.00 None 16.667 State 57.35 9.558525 CPAI ASRC 42.65 6.108476 Kuukpik Corp. 15.667000 1.328100 Petro -Hunt 0.380000 1.000000 CPAI 77.620000 2.328100 APC 22.000000 100.000000 Page 21 85 380092 T12N-R4E, U.M. Exhibit A State 54.62 9.103515 Kuukpik Corp. 1.000000 CPAI 78.000000 932052 Attached to and made a part ASRC 45.38 6.563485 APC 22.000000 of the Colville River Unit Agreement tide & submerged lands 15.667000 Original Net Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 84 380092 T12N-R4E, U.M. None 16.667 State 55.36 9.226851 Kuukpik Corp. 1.000000 CPAI 78.000000 932052 Sec. 1, Unsurveyed, All 640.00 ASRC 44.64 6.440149 APC 22.000000 TOTAL 640.00 15.667000 100.000000 85 380092 T12N-R4E, U.M. None 16.667 State 54.62 9.103515 Kuukpik Corp. 1.000000 CPAI 78.000000 932052 Sec. 2, Unsurveyed, All excl. ASRC 45.38 6.563485 APC 22.000000 tide & submerged lands 15.667000 100.000000 seaward of the line of mean high water as shown on the official tract map for Oil and Gas Lease Sale 43 583.00 TOTAL 583.00 86 388525 T12N-R4E, U.M. None 16.66667 State 54.62 9.103335 Kuukpik Corp. 1.000000 CPAI 78.000000 932306 Sec. 2, Unsurveyed, All within ASRC 45.38 6.563335 APC 22.000000 the bed of the unnamed 15.666670 100.000000 channel for the Colville River as shown on the official tract map for State Oil and Gas Lease Sale 75, dated August 26, 1992 57.00 TOTAL 57.00 87 380092 T12N-R4E, U.M. None 16.667 State 73.42 12.236911 Kuukpik Corp. 1.000000 CPA] 78.000000 932052 Sec. 3, Unsurveyed, E1/2, ASRC 26.58 3.430089 APC 22.000000 EI/2W1/2, excl. tide & 15.667000 100.000000 submerged lands seaward of the line of mean high water as shown on the official tract map for Oil and Gas Lease Sale 43 293.00 TOTAL 293.00 Exhibit A to CRUA Revised May 10, 2016 Page 22 Exhibit A Attached to and made a part of the Colville River Unit Agreement Exhibit A to CRUA Revised May 10, 2016 Page 23 Original Net Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 88 388525 T12N-R4E, U.M. None 16.66667 State 73.42 12.236669 Kuukpik Corp. 1.000000 CPAI 78.000000 932306 Sec. 3, Unsurveyed, All within ASRC 26.58 3.430001 APC 22.000000 the beds of the Nechelik 15.666670 100.000000 Channel and the bed of the unnamed channel of the Colville River as shown on the official tract map for Oil and Gas Lease Sale 75, dated August 26, 1992 327.00 TOTAL 327.00 89 25526 T12N-R4E,U.M. None 12.5 State 70.39 8.798750 Chevron 1.703000 CPAI 78.000000 932094 Sec. 10, Unsurveyed, All, ASRC 29.61 2.701250 Kuukpik Corp. 1.000000 APC 22.000000 east of the highest high water 11.500000 2.703000 100.000000 mark on the left bank of the Nechelik Channel of the Colville River 375.36 TOTAL 375.36 90 25526 T12N-R4E,U.M. None 12.5 State 52.87 6.608750 Chevron 1.703000 CPAI 78.000000 932094 Sec. 11, Unsurveyed, All 640.00 ASRC 47.13 4.891250 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 640.00 11.500000 2.703000 100.000000 91 25526 T12N-R4E,U.M. None 12.5 State 53.32 6.665000 Chevron 1.703000 CPAI 78.000000 932094 Sec. 12, Unsurveyed, All 640.00 ASRC 46.68 4.835000 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 640.00 11.500000 2.703000 100.000000 92 25526 T12N-R4E,U.M. None 12.5 State 55.09 6.88625 Chevron 1.703000 CPAI 78.000000 932094 Sec. 13, Unsurveyed, All 640.00 ASRC 44.91 4.61375 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 640.00 11.50000 2.703000 100.000000 Exhibit A to CRUA Revised May 10, 2016 Page 23 Exhibit A Attached to and made a part of the Colville River Unit Agreement Tr. No. ADL No./ AK No. Legal Description Acres Depth Restrictions Original Royalty (%) NPSL Royalty (%) Owners Mineral Owns. Net Royalty* ORRI Owners Net ORRI (%) Tract Owners Working Interest (%) 93 388901 T12N,R4E-U.M. None 12.5 State 64.45 8.05625 Chevron 1.703000 CPAI 78.000000 932349 Sec. 14, Unsurveyed, All 640.00 ASRC 35.55 3.44375 Kuukpik Corp. 1.000000 APC 22.000000 TOTAL 640.00 11.50000 2.703000 100.000000 94 388901 T12N,R4E-U.M. None 12.5 State 58.34 7.29250 Chevron 1.703000 CPAI 78.000000 TOTAL 932349 Sec. 15, Unsurveyed, All, east of ASRC 41.66 4.20750 Kuukpik Corp. 1.000000 APC 22.000000 the highest high water mark on T12N,R4E-U.M. None 16.66667 State 58.34 9.72334 Kuukpik Corp. 11.50000 78.000000 2.703000 Sec. 15, 100.000000 ASRC 41.66 the left bank of the Nechelik APC 22.000000 Unsurveyed, All, 15.00000 100.000000 within the NPR -A, Channel of the Colville River 398.55 excluding U.S. TOTAL 398.55 Survey 9502 Lots 1 and 2 95 388904 T12N,R4E-U.M. None 16.667 State 58.34 9.72353 Kuukpik Corp. 1.000000 CPAI 78.000000 932355 Sec. 15, Unsurveyed, ASRC 41.66 5.94347 APC 22.000000 All, West of highest high water 15.66700 100.000000 mark on the left bank of the Nechelik Channel of the Colville River, excluding U.S Survey 9502 Lots 1 and 2 and the NPR -A 73.46 TOTAL 73.46 96 388906 T12N,R4E-U.M. None 16.66667 State 58.34 9.72334 Kuukpik Corp. 1.666667 CPAI 78.000000 932359 Sec. 15, ASRC 41.66 5.27667 APC 22.000000 Unsurveyed, All, 15.00000 100.000000 within the NPR -A, excluding U.S. Survey 9502 Lots 1 and 2 7.66 TOTAL 7.66 Exhibit A to CRUA Revised May 10, 2016 Page 24 Tr. ADL No./ No. AK No. Legal Description Acres 97 388906 T1.2N,R4E-U.M. 932359 Sec. 16, Unsurveyed all 78.000000 within the NPR -A, excl. U.S. Survey 9502 Lot 1 17.08 of the Colville River Unit Agreement TOTAL 17.08 Exhibit A None 16.667 State 46.21 7.70182 Kuukpik Corp. Attached to and made a part 78.000000 932355 Sec. 16, Unsurveyed, All of the Colville River Unit Agreement Original ASRC Net 7.96518 Working Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) None 16.66667 State 46.21 7.70167 Kuukpik Corp. 1.666667 CPAI 78.000000 ASRC 53.79 7.29834 APC 22.000000 15.00000 TOTAL 579.27 100.000000 98 388904 T12N,R4E-U.M. None 16.667 State 46.21 7.70182 Kuukpik Corp. 1.000000 CPAI 78.000000 932355 Sec. 16, Unsurveyed, All ASRC 53.79 7.96518 APC 22.000000 excluding U.S. Survey 9502 15.66700 100.000000 Lot 1 and the NPR -A 579.27 TOTAL 579.27 There are no Tracts 99-100 78.000000 101 380093 T12N,R4E-U.M. None 16.667 State 51.53 8.58851 Kuukpik Corp. 1.000000 CPA] 932054 Sec. 9, Unsurveyed, All 640.00 ASRC 48.47 7.07850 APC 22.000000 TOTAL 640.00 15.66700 100.000000 -)ouUy-) 1 IL1N,K4b-U.M. None 16.667 State 70.39 11.731901 Kuukpik Corp. 1.000000 CPAI 78.000000 932054 Sec. 10, Unsurveyed, All West of ASRC 29.61 3.935099 APC 22.000000 the highest high water mark on 15.667000 100.000000 the left bank of the Nechelik Channel of the Colville River 264.64 TOTAL 264.64 Exhibit A to CRUA Revised May 10, 2016 Page 25 Exhibit A Attached to and made a part of the Colville River Unit Agreement Tr. No. ADL No] AK No. Legal Description Acres Depth Restrictions Original Royalty N NPSL Royalty (%) Owners Mineral Owns. Net Royalty* ORRI Owners Net ORRI N Tract Owners Working Interest (%) 103 380093 T12N,R4E-U.M. None 16.667 State 73.42 12.236911 KuukpikCorp. 1.000000 CPAI 78.000000 932054 Sec. 3, Unsurveyed, W1/2W 1/2, ASRC 26.58 3.430089 APC 22.000000 excl. tide and submerged lands 15.667 100.000000 seaward of the line of mean high water as shown on the official tract map for O&G Lease Sale 43 20.00 TOTAL 20.00 104 380093 T12N,R4E-U.M. None 16.667 State 57.69 9.615192 Kuukpik Corp. 1.000000 CPAI 78.000000 932054 Sec. 4, Unsurveyed, All, excl. ASRC 42.31 6.051808 APC 22.000000 tide and submerged lands 15.667 100.000000 seaward of the line of mean high water as shown on the official tract map for O&G Lease Sale 43 502.00 TOTAL 502.00 105 389726 T12N,R4E-U.M. None 16.66667 State 57.69 9.615002 Kuukpik Corp. 1.000000 CPAI 78.000000 932684 Sec. 4, Unsurveyed, All within ASRC 42.31 6.051668 APC 22.000000 the bed of the Nechelik Channel 15.66667 100.000000 of the Colville River as shown on the official Tract Map for the State O&G Lease Sale 75, dated August 26, 1992 138.00 TOTAL 138.00 There is no Tract 106 Exhibit A to CRUA Revised May 10, 2016 Page 26 Tr. ADL No) No. AK No. Legal Description Acres 107 389725 T13N,R4E-U.M. 932682 Sec. 33, Unsurveyed, All, Attached to and made a part excluding tide and submerged lands seaward of the line of mean high water as shown on the official of the Colville River Unit Agreement tract map for O&G Lease Sale 43 278.00 TOTAL 278.00 108 388529 T13N,R4E-U.M. 932310 Sec. 33, Unsurveyed, All tide and submerged lands seaward of the line of mean high water and all uplands within the bed of the Nechelik Channel of the Colville River, both as shown on the official tract map for State O&G Lease Sale 75A dated June 17, 1993 362.00 TOTAL 362.00 109 388528 T13N,R4E-U.M. 932308 Sec. 34, Unsurveyed, All tide and submerged lands seaward of the line of mean high water and the channel closing line, and all uplands within the bed of the unnamed channel of the Colville River, both as shown on the official tract map for State O&G Lease Sale 75A dated June 17, 1993 420.00 TOTAL 420.00 Exhibit A Attached to and made a part of the Colville River Unit Agreement Original Net Working Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) None 16.667 State 76.96 12.826923 CPA] 1.328100 CPAI 77.620000 ASRC 23.04 2.840077 Kuukpik Corp. 1.000000 APC 22.000000 15.667000 2.328100 Petro -Hunt 0.380000 100.000000 None 16.66667 None 16.66667 State 76.96 12.826669 Kuukpik Corp. 1.000000 CPAI 78.000000 ASRC 23.04 2.840001 APC 22.000000 15.66667 100.000000 State 67.65 11.275023 Kuukpik Corp. 1.000000 CPAI 78.000000 ASRC 32.35 4.391677 APC 22.000000 15.6667 100.000000 Exhibit A to CRUA Revised May 10, 2016 Page 27 Tr. ADL No./ No. AK No. Legal Description Acres 110 389725 T13N,R4E-U.M. 932682 Sec. 34, Unsurveyed, All, N excluding tide and submerged (%) lands seaward ofthe line of CPAI mean high water as 1.000000 shown on the official tract 22000000 map for O&G Lease Sale 43 220.00 Petro -Hunt TOTAL 220.00 Exhibit A Attached to and made a part of the Colville River Unit Agreement Original Depth Royalty NPSL Royalty Mineral Restrictions (%) (%) Owners Owns. None 16.667 State 67.65 ASRC 32.35 Net ORRI Royalty* Owners 11.275226 CPAI 4.391775 Kuukpik Corp 15.667000 Net Working ORRI Tract Interest N Owners (%) 1.328100 CPAI 77.620000 1.000000 APC 22000000 2.328100 Petro -Hunt 0.380000 100.000000 ] ] 1 389725 T13N,R4E-U.M. None 16.667 State 60.52 10.086868 CPAI 1.328100 CPAI 77.620000 932682 Sec. 35, Unsurveyed, All, ASRC 39.48 5.580132 Kuukpik Corp. 1.000000 APC 22.000000 excluding tide and submerged 15.667 2.328100 Petro -Hunt 0.380000 lands seaward of the line of 100.000000 mean high water and channel closing line as shown on the official tract map for O&G Lease Sale 43 555.00 TOTAL 555.00 112 388527 T13N,R4E-U.M. None 16.66667 State 60.52 10.086669 A. James III 8.333330 CPAI 78.000000 932623 See. 35, Unsurveyed, All tide ASRC 39.48 5.580001 Revocable APC 22.000000 and submerged lands seaward 15.66667 Trust 100.000000 of the line of mean high water Kuukpik Corp. 1.000000 and the channel closing line 9.333330 as shown on the official tract map for O&G Lease Sale 75A dated June 17, 1993 85.00 TOTAL 85.00 Exhibit A to CRUA Revised May 10, 2016 Page 28 Exhibit A Attached to and made a part of the Colville River Unit Agreement Original Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral No. AK No. Description Acres Restrictions (%) (%) Owners Owns. us SIS6.)2/ 1'13N,R4E-U.M. None 16.66667 932623 Sec. 36, Unsurveyed, All tide and submerged lands seaward of the line of mean high water and the channel closing line as shown on the official tract map for O&G Lease Sale 75A dated June 17, 1993 43.00 TOTAL 43.00 Net Working Net ORRI ORRI Tract Interest Royalty* Owners (%) Owners (%) State 57.35 9.558335 A. James III 8.333330 ASRC 42.65 6.108335 Revocable 15.66667 Trust Kuukpik Corp. 1.000000 9.333330 CPAI 78.000000 APC 22.000000 100.000000 114 389725 T13N,R4E-U.M. None 16.667 State 83.68 13.946946 CPAI 1.328100 CPAI 77.620000 932682 Sec. 25, Unsurveyed, All, ASRC 16.32 1.720054 Kuukpik Corp. 1.000000 APC 22.000000 excluding tide and submerged 15.667 2.328100 Petro -Hunt 0.380000 lands seaward of the line of 100.000000 mean high water as shown on the official tract map for 0&G Lease Sale 43 196.00 TOTAL 196.00 115 388527 T13N,R4E-U.M. None 16.66667 State 83.68 13.946669 A. Jaynes III 8.333330 CPAI 78.000000 932623 Sec. 25, Unsurveyed, All tide ASRC 16.32 1.720001 Revocable APC 22.000000 and submerged lands seaward 15.66667 Trust 100.000000 of the line of mean high water Kuukpik Corp. 1.000000 as shown on the official tract 9.333330 map for O&G Lease Sale 75A dated June 17, 1993 444.00 TOTAL 444.00 There are no Tracts 116-118 Exhibit A to CRUA Revised May 10, 2016 Page 29 Exhibit A Attached to and made a part of the Colville River Unit Agreement Tr. No. ADL No./ AK No. Legal Description Acres Depth Restrictions Original Royalty (%) NPSL Royalty (%) Owners Mineral Owns. Net Royalty* ORR] Owners Net ORRI (%) Tract Owners Working Interest (%) 119 380081 T1 1N,R5E-U.M. **9.915002 None 16.667 State 50.06 8.3435 Kuukpik Corp. 1.000000 CPAI 78.000000 15.000003 932044 Sec. 28, Unsurveyed, All 640.00 TOTAL ASRC 49.94 7.3235 APC 22.000000 TOTAL 640.00 15.667 122 388902 100.000000 120 ASRC NPRA 2 T11N,R4E-U.M. 30.51 None 16.667 ASRC 100.00 15.0003 Kuukpik Corp. 1.666700 CPA] 78.000000 69.49 932128 Sec. 28, All 640.00 excluding the NPR -A 353.37 APC 22.000000 100.000000 Sec. 33, All 640.00 353.37 100.000000 Sec. 34, A I I 640.00 TOTAL 1,920.00 121 388905 T11N,R4E-U.M. None Sliding State 30.51 5.085001 Kuukpik Corp. **1.666667 CPAI 78.000000 932357 Sec. 35, Unsurveyed, All, Scale ASRC 69.49 **9.915002 APC 22.000000 within NPR -A 286.63 **16.66667 15.000003 100.000000 TOTAL 286.63 122 388902 Tl 1N,R4E-U.M. None 16.667 State 30.51 5.085102 Kuukpik Corp. 1.000000 CPAI 78.000000 932351 Sec. 35, Unsurveyed, All, ASRC 69.49 10.581898 APC 22.000000 excluding the NPR -A 353.37 15.667 100.000000 TOTAL 353.37 123 388902 Tl IN,R4E-U.M. None 16.667 State 60.97 10.16187 Kuukpik Corp. 1.000000 CPAI 78.000000 932351 Sec. 36, Unsurveyed, All 640.00 ASRC 39.03 5.50513 APC 22.000000 TOTAL 640.00 15.667 100.000000 124 388903 T11N,R5E-U.M. None 16.667 932353 Sec. 31, Unsurveyed, All 607.00 Sec. 32, Unsurveyed, All 640.00 TOTAL 1,247.00 State 50.00 8.3335 Kuukpik Corp. 1.000000 CPAI 78.000000 ASRC 50.00 7.3335 APC 22.000000 15.667 100.000000 Exhibit A to CRUA Revised May 10, 2016 Page 30 There are no Tracts 126-130 131 380044 T10N,R5E-U.M. None 16.667 State 50.00 8.3335 Kuukpik Corp. 1.000000 CPAI 78.000000 932015 Sec. 6, Unsurveyed, All 609.00 ASRC 50.00 7.3335 CPAI 1.290000 APC 22.000000 TOTAL 609.00 15.667 1.290000 100.000000 131A 391590 T10N,R5E-U.M. Exhibit A State 50.00 8.3335 Kuukpik Corp. 1.000000 Attached to and made a part 78.000000 341405 Sec. 5, N1/2NW1/4, SWI/4NW1/4, ASRC of the Colville River Unit Agreement 7.3335 CPAI 1.290000 APC 22.000000 Original Net 160.00 Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners N 125 391587 Ti 1N,R5E-U.M. None 16.667 State 50.20 8.366834 Kuukpik Corp. 1.000000 CPAI 78.000000 341409 Sec. 33, Unsurveyed, All 640.00 ASRC 49.80 7.300166 APC 22.000000 1.000000 TOTAL 640.00 15.667 932351 Sec. 1, Unsurveyed, All, There are no Tracts 126-130 131 380044 T10N,R5E-U.M. None 16.667 State 50.00 8.3335 Kuukpik Corp. 1.000000 CPAI 78.000000 932015 Sec. 6, Unsurveyed, All 609.00 ASRC 50.00 7.3335 CPAI 1.290000 APC 22.000000 TOTAL 609.00 15.667 1.290000 100.000000 131A 391590 T10N,R5E-U.M. None 16.667 State 50.00 8.3335 Kuukpik Corp. 1.000000 CPAI 78.000000 341405 Sec. 5, N1/2NW1/4, SWI/4NW1/4, ASRC 50.00 7.3335 CPAI 1.290000 APC 22.000000 NW / 14S W 1 /4 160.00 15.667 1.290000 100.000000 TOTAL 160.00 132 388902 T10N,R4E-U.M. None 16.667 State 55.07 9.178517 Kuukpik Corp. 1.000000 CPAI 78.000000 932351 Sec. 1, Unsurveyed, All, ASRC 44.93 6.488483 APC 22.000000 excluding the NPR -A 586.43 15.667 100.000000 TOTAL 586.43 133 388902 T10N,R4E-U.M. None 16.667 State 7.86 1.310026 Kuukpik Corp. 1.000000 CPAI 78.000000 932351 Sec. 2, Unsurveyed, All, ASRC 92.14 14.356974 APC 22.000000 excluding the NPR -A 87.63 15.667 100.000000 TOTAL 87.63 There are no Tracts 134 - 161 Exhibit A to CRUA Revised May 10, 2016 Page 31 164 390345 T12 N, R4E, U.M. 933510 Section 17, Unsurveyed, All, excluding tide and submerged lands seaward of the line of mean high water as shown on the official tract map for O&G Lease Sale 43 448.00 TOTAL 448.00 Exhibit A to CRUA Revised May 10, 2016 None 16.667 State 69.63 11.60523 Kuukpik Corp. 1.00000 CPAI 78.000000 ASRC 30.37 4.06177 APC 22.000000 15.667000 100.000000 Page 32 Exhibit A Attached to and made a part of the Colville River Unit Agreement Original Net Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 162 390344 T12 N, R4E, U.M. None 16.667 State 76.19 12.698587 Kuukpik Corp. 1.00000 CPAI 78.00 933508 Section 5, Unsurveyed, ASRC 23.81 2.9684127 APC 22.00 All, excluding tide and submerged 15.6670000 100.000000 lands seaward of the line of mean high water as shown on the official tract map for O&G Lease Sale 43 308.00 TOTAL 308.00 163 390344 T12 N, R4E, U.M. None 16.667 State 64.60 10.76688 Kuukpik Corp. 1.00000 CPAI 78.000000 933508 Section 8, Unsurveyed, ASRC 35.40 4.90012 APC 22.000000 All, excluding tide and 15.66700 100.000000 submerged lands seaward of the line of mean high water as shown on the official tract map for O&G Lease Sale 43 531.00 TOTAL 531.00 164 390345 T12 N, R4E, U.M. 933510 Section 17, Unsurveyed, All, excluding tide and submerged lands seaward of the line of mean high water as shown on the official tract map for O&G Lease Sale 43 448.00 TOTAL 448.00 Exhibit A to CRUA Revised May 10, 2016 None 16.667 State 69.63 11.60523 Kuukpik Corp. 1.00000 CPAI 78.000000 ASRC 30.37 4.06177 APC 22.000000 15.667000 100.000000 Page 32 Tr. ADLNo./ No. AK No. Legal Description Acres 165 390348 T12 N, R4E, U.M. 933516 Section 17, Unsurveyed, Depth Royalty All, tide and Mineral submerged lands seaward ORRI ofthe mean high Restrictions (%) water as shown on the Owns. official tract map for O&G Owners Lease Sale 43 192.00 None 16.66667 TOTAL 192.00 Exhibit A Attached to and made a part of the Colville River Unit Agreement Original Net Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Restrictions (%) (%) Owners Owns. Royalty* Owners N None 16.66667 State 69.63 11.60523 Kuukpik Corp. 1.00000 ASRC 30.37 4.06177 15.667000 Working Tract Interest Owners (%) CPAI 78.000000 APC 22.000000 100.000000 166 390350 T12 N, R4E, U.M. None 16.66667 State 64.60 10.76667 Kuukpik Corp. 1.00000 CPAI 78.000000 933520 Section 8, Unsurveyed, ASRC 35.40 4.90000 APC 22.000000 All, tide and submerged 15.66667 100.000000 lands as shown on the official tract map for O&G Lease Sale 75 109.00 TOTAL 109.00 167 390350 T12 N, R4E, U.M. None 16.66667 State 76.19 12.69834 Kuukpik Corp. 1.00000 CPAI 78.000000 933520 Section 5, Unsurveyed, ASRC 23.81 2.96833 APC 22.000000 All, tide and submerged 15.66667 100.000000 lands and all uplands within the bed of the unnamed channel of the Colville River as shown on official tract map for O&G Lease Sale 75 332.00 TOTAL 332.00 Exhibit A to CRUA Revised May 10, 2016 Page 33 Exhibit A Attached to and made a part of the Colville River Unit Agreement Original Net Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 168 388465 T12 N, R4E, U.M. None 16.66667 State 100.00 N/A None None CPAI 78.000000 300632 Section 6, Protracted, All 577.00 APC 22.000000 tide and submerged lands 100.000000 Section 7, Protracted, All 580.00 tide and submerged lands TOTAL 1,157.00 169 388466 T12 N, R4E, U.M. None 16.66667 State 100.00 N/A None None CPAI 78.000000 300634 Section 18, Protracted, All APC 22.000000 tide and submerged lands 583.00 100.000000 Section 19, Unsurveyed, All tide and submerged lands seaward of the line of mean high water and the channel closing lines as shown on the official tract map 444.59 Jection 16, Unsurveyed, All title and submerged lands seaward of the line of mean high water and the channel closing lines as shown on the official tract map 62.67 Section 29, Unsurveyed, All tide and submerged lands seaward of the line of mean high water 237.21 Section 30, Unsurveyed, All tide and submerged lands seaward of the line of mean high water and the channel closing lines as shown on the official tract map 286.90 Section 3l, Unsurveyed, All tide and submerged lands seaward of the line of mean high water 47.04 Section 32, Unsurveyed, All tide and submerged lands seaward of the line of mean high water 90.66 TOTAL 1,752.07 Exhibit A to CRUA Revised May 10, 2016 Page 34 Exhibit A Attached to and made a part of the Colville River Unit Agreement Tr. ADL No./ No. AK No. Legal Description Acres Original Net Working Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest Restrictions (%) (%o) Owners Owns. Royalty* Owners (%) Owners (%) 169 388466 THE CHANNEL CLOSING LINES 320.00 300634 WITHIN SECTIONS 19,28 AND tide and submerged lands (cont.) 30 WERE DRAWN BASED ON submerged lands seaward of the line COASTAL BOUNDARY BAY of mean high water and the channel CLOSING LINE PROCEDURE. tract map THE PURPOSE IS TO Section 12, Protracted, All tide and SEGREGATE TIDE AND 640.00 Section 13, Unsurveyed, All tide and SUBMERGED ACREAGE FROM submerged lands seaward of the line UPLAND ACREAGE. 170 388463 T12 N, R3E, U.M. None 16.66667 State 100.00 N/A None None CPAI 78.000000 300628 S1/2 of Section 1, Protracted, All APC 22.000000 tide and submerged lands 320.00 S1/2 of Section 2, Protracted, All 100.000000 tide and submerged lands 320.00 Section 11, Unsurveyed, all tide and submerged lands seaward of the line of mean high water and the channel closing lines as shown on the official tract map 476.33 Section 12, Protracted, All tide and submerged lands 640.00 Section 13, Unsurveyed, All tide and submerged lands seaward of the line of mean high water and the channel closing lines as shown on the official tract map 454.20 Section 14, Unsurveyed, All tide and submerged lands seaward of the line of mean high water and the channel closing lines as shown on the official tract map 43.11 Section 24, Unsurveyed, All tide and submerged lands seaward of the line of mean high water 22.86 TOTAL 2,276.50 Exhibit A to CRUA Revised May 10, 2016 Page 35 Tr. ADL No./ No. AK No. Legal Description Acres 170 388463 THE CHANNEL CLOSING LINES 300628 WITHIN SECTIONS 11, 13 AND (cont.) 14 WERE DRAWN BASED ON submerged lands seaward of the line COASTAL BOUNDARY BAY of mean high water CLOSING LINE PROCEDURE. Section 13: all excluding tide and THE PURPOSE IS TO submerged lands seaward of the line SEGREGATE TIDE AND of mean high water SUBMERGED ACREAGE FROM Section 14: all excluding tide and UPLAND ACREAGE. Exhibit A Attached to and made a part of the Colville River Unit Agreement Original Depth Royalty NPSL Royalty Mineral Net Restrictions (%) (%) Owners Owns. Royalty* Net Working ORRI ORRI Tract Interest Owners (%) Owners (%) There are no Tracts 171-176 None 12.50 ASRC 100.00 10.500000 Kuukpik Corp. 2.000000 CPAI 78.000000 177 ASRC NPRA 1 T12N, R3E, U.M. 932126 Section 11: all excluding tide and AEP 22.000000 submerged lands seaward of the line of mean high water 178.72 Section 13: all excluding tide and 100.000000 submerged lands seaward of the line of mean high water 184.11 Section 14: all excluding tide and submerged lands seaward of the line of mean high water 624.00 Section 23 640.00 Section 24: All, excluding tide and submerged lands seaward of the line of mean high water 625.00 TOTAL 2,251.83 Exhibit A to CRUA Revised May 10, 2016 Page 36 Exhibit A Attached to and made a part of the Colville River Unit Agreement 179 ASRC Tl IN, R3E, U. M. None 16.667 ASRC 100.00 15.0000 Kuukpik Corp. 1.66670 CPAI 78.000000 NPRA3 Section 1, All 640.00 AEP 22.000000 932671 Section 2, All 640.00 100.000000 Section 3, All 640.00 Section 12, All 640.00 Total 2,560.00 180 ASRC TI IN, R4E, U.M. None 16.667 ASRC 100.00 Original Net 932669 Section 17, All Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions N (%) Owners Owns. Royalty* Owners (%) Owners N 178 ASRC TI 2N, R4E, U.M. None 16.667 ASRC 100.00 15.0000 Kuukpik Corp. 1.667000 CPAI 78.000000 NPRA 2 Section 19 (fractional): All, AEP 22.000000 932128 excluding tide and submerged lands 100.000000 seaward of the line of mean high water 118.97 TOTAL 118.97 179 ASRC Tl IN, R3E, U. M. None 16.667 ASRC 100.00 15.0000 Kuukpik Corp. 1.66670 CPAI 78.000000 NPRA3 Section 1, All 640.00 AEP 22.000000 932671 Section 2, All 640.00 100.000000 Section 3, All 640.00 Section 12, All 640.00 Total 2,560.00 180 ASRC TI IN, R4E, U.M. None 16.667 ASRC 100.00 NPRA4 Section 6, All 593.45 932669 Section 17, All 640.00 Section 18, All 598.58 Section 29, All 640.00 Section 32, All 640.00 T1 ON, R4E, U.M. Section 3, All 640.00 Section 4, All 640.00 Section 5, All 640.00 Total 5,032.03 15.0000 Kuukpik Corp. 1.66670 CPAI 78.000000 AEP 22.000000 100.000000 181 AA087888 TI IN, R3E, U. M. None 16.6667 BLM 100.00 16.66667 None None CPAI 78.000000- 307461 Section 10, All 640.00 AEP 22.000000 Section 14, All 640.00 100.000000 Total 1,280.00 Exhibit A to CRUA Revised May 10, 2016 Page 37 Exhibit A Attached to and made a part of the Colville River Unit Agreement 0.74883 Exhibit A to CRUA Revised May 10, 2016 Page 38 Original Net Working Tr. ADLNo./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions N (%) Owners Owns. Royalty* Owners N Owners N 181A AA092347 TI IN, R3E, U. M. None 16.6667 ASRC 100.00 15.00000 Kuukpik Corp. 1.6667 CPAI 78.000000 340758 Section 11, All 640.00 AEP 22.000000 Section 13, All 640.00 100.000000 Total 1,280.00 182 AA081817 TI IN, R4E, U.M. None 16.6667 BLM 100.00 16.66667 None None CPAI 78.000000 932552 Section 31, All 605.00 AEP 22.000000 TI IN, R3E, U. M. 100.000000 Section 23, All 640.00 Section 26, All 640.00 Section 36, All 640.00 Total 2,525.00 182A AA092344 Tl 1N, R4E, U.M. None 16.6667 ASRC 100.00 15.00000 Kuukpik Corp. 1.6667 CPAI 78.000000 340757 Section 19, All 600.00 AEP 22.000000 Section 20, All 640.00 100.000000 Section 30, All 602.00 TI IN, R3E, U. M. Section 24, All 640.00 Section 25, All 640.00 Total 3,122.00 183 390337 TI ON, R4E, U.M. None Sliding State 7.86 1.31000 Kuukpik Corp. 1.53566 CPAI 78.000000 300618 Section 2, Surveyed by Scale ASRC 92.14 13.82100 APC 22.000000 protraction, Lots 2 and 4 552.37 16.66667** 100.000000 Total 552.37 0.74883 Exhibit A to CRUA Revised May 10, 2016 Page 38 Exhibit A Attached to and made a part of the Colville River Unit Agreement Original Net Working Tr. ADL No/ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) 184 390337 T10N, R4E, U.M. None Sliding State 55.07 9.17834 Kuukpik Corp. 0.74883 CPAI 78.000000 300618 Section 1, Surveyed, by Scale ASRC 44.93 6.73950 APC 22.000000 protraction, Lot 4 53.57 16.66667** 100.000000 Total 53.57 Tracts 185-205 are identified in the Fifth Expansion Application (Pending Resubmission) 206 AA094165 TI IN, R3E, U.M. None 16.6667 BLM 100.00 16.66667 None None CPAI*** 100.000000 366606 Section 22, All 640.00 AEP*** 0.000000 Section 27, All 640.00 100.000000 Section 34, All 640.00 Section 35, All 640.00 Total 2,560.00 207 AA094167 TION, R3E, U.M. None 16.6667 BLM 100.00 16.66667 None None CPAI*** 100.000000 366608 Section 1, All 638.00 AEP*** 0.000000 Section 2, All 639.00 100.000000 Section 3, All 639.00 Total 1,916.00 208 AA092675 TION, R4E, U.M. None 16.6667 BLM 100.00 16.66667 None None CPAI 78.000000- 341734 Section 6, All 609.00 AEP 22.000000 Total 609.00 100.000000 TOTAL UNIT ACREAGE 122,091.71 Exhibit A to CRUA Revised May 10, 2016 Page 39 Exhibit A Attached to and made a part of the Colville River Unit Agreement Original Net Working Tr. ADL No./ Legal Depth Royalty NPSL Royalty Mineral Net ORRI ORRI Tract Interest No. AK No. Description Acres Restrictions (%) (%) Owners Owns. Royalty* Owners (%) Owners (%) * ASRC's net royalty amount reflects the net ORRI granted to Kuukpik. ** This lease has a sliding scale overriding royalty therefore the original royalty percentage will vary between 16.66667% and 33.33333%. Kuukpik shall receive an overriding royalty equal to 10% of the Original Royalty Percentage, payable out of ASRC Original Royalty Percentage share of production. For example, using a fictitious tract with equal ownership of mineral interest between the State and ASRC, if the royalty rate escalates to 201/o, then Kuukpik shall be entitled to receive 2% overriding royalty (0.10 x 0.20 = 0.02) on 8/8ths of production, the State would receive 10% royalty on 8/8ths of production (0.50 x 0.20 = 0.10), and ASRC would receive 8% royalty on 8/8ths of production [(0.50 x 0.20) — (0.10 x 0.20) = 0.08]. *** CPAI has executed an assignment for 22% working interest to AEP. The fully executed assignment is currently being routed to the BLM for approval. KEY: APC: Anadarko Petroleum Corporation AEP: Anadarko E&P Onshore LLC ASRC: Arctic Slope Regional Corporation BLM: Bureau of Land Management Chevron: Chevron U.S.A. Inc. CPAI: ConocoPhillips Alaska, Inc. CPAI*: CPAI, et al, as successor to Texaco CPAI**: CPAI, et al, as successor to Midgard Energy Company D.K. Nerland: Delores K. Nerland Enea Tena Inv.: Enea Tekna Investments Kuukpik Corp.: Kuukpik Corporation Petro -Hunt: Petro -Hunt, L.L.C. R.E. Wagner: Richard E. Wagner R W Res: Rosewood Resources, Inc. State: State of Alaska W.G. Stroecker: William G. Stroecker Exhibit A to CRUA Revised May 10, 2016 Page 40 1:150,000 0 0.5 1 2 3 Miles NN �S // W+r CS T13N R4E T1 3N R5E 1-' 79 A DL364472 ADI -364470 O ADT3885 09 -'11 '.'S 165 ADL364471 ADL389726 707 ° 170 77 169 19 ADL39035b 1058 - tp ADL391577 167 ADL380092 7 16 .,�, _ 15, 14 �� 16 1�.. 86 66 84 O4 ;: � 4/ C 103 i ADL388463 Flyz... _., ADL388525 ,_. AD1372105 ADL372104 ASRC-NPR1 aDl]8009] '170 .mvvee 183 101ADL372103 " 10 891 90 � 91 ' O9 •< a 8O ;-p 166 y `' ADL390348 ADL390345 i 3 I ADL025528 95 n� Z' 28 T12N R3E n— 165 0L372106 77 169 19 gDL388 901 - tp ADL391577 176 21 18A 16 .,�, _ 15, 14 �� ' ... _.-.__ 788 117 ADL025529 ADL025538 -: 11 -.I ASRC-NPR1 25 28 ADL372108 22, 31 _ w�xrsss 26 ADL025530 _ 29 30 ... - 67J 35 36 35 36 35 « .., <.� I ( 34 8 (180 ASRC-NPR2 ADL3800T5L ADL025558 ADL025557 l 'v1°B ADL391579 ADL025559 ADL372095 ASRC-NPR3 .147 181A 181 ..1 L2 51; AD L39158' 49 m T 1 1 N R 3 E vat, ee =1.IA�b5" 665766 59 60 6J O ,av,m, 67 nan ADL372097 '62) fi4 a w-, ASRC-AA092344 gDL3900]9 .i4 - r 21 75 74 73 72 I 2 71 70 , 18 182A I ADL380077 4 __ AD08421, 77- _ 1 1 N R 5 E 88 81 (g11 ^119 78 r 4L 8 ADL388903 12 -^ AA094166 121 123 3s 124 J2 7124 �' ""' . "' A0088905 'ADL3aes0z 0i {4M192R>5 O' 71xe 33 D ]r5m r131A Zw AA094187 '''tom' S80ASRC-NPR4 13 783 131•` (6th CRU Expansion Area CRU unit Tracts T 1 0 N R 4 E T 10 Unit Boundary 6th CRU Expansion Area QLease Boundary Unit Boundary Tract Boundary 1d Tract Number 778 )Phillips Ainka, inc. Exhibit A Greater Mooses Tooth Unit 8-28-07 07050103E02 tiL row ` "AAOF 1745 AAUB 17,*F n 1i AA081746 4 AAt 1b_3 AA081857 AAOR 921 AA08182 AAN AO SIB AA081810 Aii(1€31Ft¢C$ ttA0818 `AA081805 AAO 1802 `}AAL 1801 AAfi81801 AA081P,^7 AA081804. AA081,301L 3 4,W-,1?3Q � s ga7�ca S � .3t'17t� "�'° 081784 i AAIS1r'R" ire �e ��vBfT x 77 www N �—€ t„ 1�� s A06 ConOCOR Exhibit Unit Boundary --�-- Frac: B.Dunaarj ASRC Lands XGreater M Exhibit B Greater Mooses Tooth Unit Area Leases Unit Agreement for the Exploration, Development and Operation of the Greater Mooses Tooth Unit Area _Tract _Description ,Number_ Se --Anter Expiration Basic _ Basic Ownership Lessee verndingRoya _Working__ Ownership. 7 T11 N•R1E, UM! - AA -087745 8137/09 :6.6667%! U.S. Percents of Record and Percents Interest Owners Percents e No. of Lands of Acres Tobin Number Date Ro alt Ro alt Owner I 100% ConocoPhillips None cnn—Phillips ]A nn Section 10: All i 639.00. 953088 Section 35: All640.00:' 100% ConocoPhd6ps- None Anadarko Section 36: All Section 11: All i 639A0I 3837.00 .--- --- -- 6 T11 N -R 1 E, UM: Section 12: All 639.00' 640.00! 932592 Section 28: All 640.00: Section 13: All ! 639.00'',- Section 30: At j 603.00': Section 31: Alli . Section 14: All 640.00' Section 32: All ! 640.001 - 640.00; Section 15: All 640.00'. I 7 711 N -RIE, UM ------- AA -081621 8/31/09 ----- % Section 22: All I 3836.00 9325% '.. Section 23: All ! , 11 Section 24: All 1 639.001.. j Section 25: All 640.00; Section 26: All w 2 rTttN-R2E, UM. -- AA -081743 8/31109 .16.6667%1 U.S. 100°k ConocoPhllhps. None Section 13: All 1 i 640.00; 953086 Section 36: All 640.001 Anadarko 5756.00 640.00 9 ; T11N R2E, UM AA -081820 8/31!09 166667%. Section 19: All 601.00 932555'. Section 20: AH 640.001. Section 21: All ' 640.00', 3 , T77N R3E, UM! 640.00' qA-Ogi742 6131!09 16.6667% U.S. 100% ConocoPhllllps None - !. Section 17: All 640.00 954847 605.00' - Anadarko 640.001', Section 18: All 596.00 i 1 1-2361.0.0. I_ - 4 !T71N-R1 W, UMI - AA -081746 i 8/31/09 i 16.6667%I U.S.- 100% ;ConocoPhdhps'. None Section 33: All 640.00! 953089 ! ! Anadarko _ 5 .T11 N-R1W, UM- I _ AA -081823 8131/09 16.6667%: U_S. 100% ICon000Phllllpsl None Section 25. All 639.00, 932558''. Anadarko Section 26: Ali 640.00: Section 27: All 1 639.00: Section 34: All 639.00: Anadarko Section 35: All640.00:' 100% ConocoPhd6ps- None ConocoPhillips Section 36: All 640.001 3837.00 .--- --- -- 6 T11 N -R 1 E, UM: i AA -081857 - ' 8/31109 ! 16.6667 Section 21: All 640.00! 932592 Section 28: All 640.00: Section 29: Al:640.00 Section 30: At j 603.00': Section 31: Alli 605.001, ; Section 32: All ! 640.001 -'. Section 33: All 1 640.00; I I 7 711 N -RIE, UM ------- AA -081621 8/31/09 ----- % Section 22: All I 640.00, 9325% '.. Section 23: All ! 639.001; 11 Section 24: All 1 639.001.. j Section 25: All 640.00; Section 26: All 639.001- Section 27: All 639.00: Section 34: All ! 640.001,'1 Section 35: All ! 640.00i Section 36: All 640.001 5756.00 9 ; T11N R2E, UM AA -081820 8/31!09 166667%. Section 19: All 601.00 932555'. Section 20: AH 640.001. Section 21: All ' 640.00', Section 28: All 640.00' Section 29: All. 640.00' Section 30: All 602.00'; Section 31: All 605.00' Section 32: All : 640.001', Section 33. All 640.00' 1 Anadarko Anadarko 1 UU7n 1 ConocoPhillips.. None Conocophillips Anadarko Anadarko' 100% ConocoPhd6ps- None ConocoPhillips Anadarko I Anadarko: 1 1!30;2008 Exhibit B Greater Mooses Tooth Unit Area Leases Unit Agreement for the Exploration, Development and Operation of the Greater Mooses Tooth Unit Area Tract Description, Number SenaNumber Expiration Basic Basic Ownership_j _Lessee _, Overrldmg Royzk, working -,Owner@hip,., No. of Lands of Acres Tobin Number Date Rc alt Ro alt Owner Percema a of Record and Percentage Interest Owners Percents e 9 ;T11 N-R2E, UM.! AA -081819 8/31/09 :16.6667%! U.S. - 1001 ! ConocoPhiilips None ConocoPhillips. 78.0 Section 22: All 640.00` 932554 ''. Anadarko Anadarko: 2200. Section 23: All j. 639.00, 100.00 Section 24: All 640.00'.. -- Section 25: All'; 640.00: Section 26: All •. 639.00 Section 27: All 640.00 j Section 34: All I 639.00': j Section 35: All 639.00' Section 36: Ail 640.00'.. -- 5756.00 10 � T71N R3E, UM -- -�-_. -- - --- AA -081818 � 8/31/09 1 16.6687667 % U.S. 100% `----- -....- --- : None ConocoPhdhps 1 ConocoPhdlips, --.._.- -- - 78.00 Section 19: Alt 600.00; 932553 I Anadarko j Anadarko! 22.00 Section 30: All ! 603.00: ! '�, 100.00 Section 31: Ali ''. 605.00 - ._...... ---i 1808.00 -......_. _. +._._.._--. � '_----- - �--_---.-__-_. _.._.._._ --- --.. _ 11 ':T10N R1W, UM AA -081810 1 8/31/09 16.6667% U.S. 1170% ConocoPhillipsj None -.-_ ConocoPhillips 78.00 Section 4: All 640.00. 932545 Anadarko Anadarko! 2200. Section 5: All li 640,00. 'll j '.', 100.00 Section 6: All ; 607.00 '... Section 7: All '', 611.00; Section 8: All 640.00 Section 9: All 640.00' - Section 16: All ! 640.00'x,. Section 17: All 640.00; I : Section 18: All ' I I ._Section 5672.00: _..__ _ 12 T10N-R1 W, UM __.... -S. --.. AA•081808 8/31/09 16.6667% U.S. 100°h 1, -- - ------.._..-+ ConocoPhilh s None ... !._------- onoeo iii s 78. 1: All 639.00• 932543 1 Anadarkop Anadarko 22.00 Section 2: All 640.00; ., 100.00 Section 3: All ! 639.001 j Section 10: Al 640.00', ! Section 11: All 639.00' - Section 12: All 640.00; :. Section 13: All 639.001; . Section 14: All - 640.00'1 Section 15: All 640.00! I 5756.0- ___--__..... t3 T10N•R1 E, UM - AA -081806 6/31/09 16.6667%' U.S. 1009' :ConowPhii6ps' None ConocePhdhps 7800 Section 4: All 640.00; 932541 !� Anadarko Anadarko, 22.00 Section 5: All 640.00:., 100.00 ! Section 6: All 608.001 - Section 7: All 611.0011 Section 8: All 640.00'1.. Section 9: All - 640.00; Section 16: All 640.00; Section 17: All' 640.00; Section 18: All 613.06. 5672.001 - _ 1____._. 14 t TSection 5 8/31/09 16.6667 % U.S. 100°/ ConocoPhillipsl None 1 !, ConocoPhillipsl 78.00 _ 1 All 640.00 932540 Anadarko Anadarko. 22.00 Section 2: All 639.00; ! 100.00 Section 3: All 640.001 ! ! Section 10: All 639.00, Section 11: All 640.00':: Section 12: All 639.Od. Section 13: All - 640.06 Section 14: All 639-00', Section 15: All. 640.001 - 5756.00 2�^12009 Exhibit 6 Greater Mooses Tooth Unit Area Leases Unit Agreement for the Exploration, Development and Operation of the Greater Mooses Tooth Unit Area Trac(_ _ Descnplkw` Number Senal NumberIL: Expiration Basi9 Basic__ Ownership Overriding att Working Ownership No. of Lands of Acres Tobin Number Date Ro al Ro al Owner Percentage .Lessee of Record and Percenta a Interest Owners Percents e 15 T10N-R2E, UM j AA -081802 8/31109 ! 16.6667% i U.S. 1001/6 ConocoPhillips_ None ConocoPhillips; 78.0 Section 4: All 640.00: 932537 Anadarko Anadarko!. 22.0 :,. Section 5: All Section 6: All; 540.00' 607.001 : ':. j 100.00 Section 7: Alt 617.00'.. Section 8: All - 640.00' Section 9: All 640.00: Section 16: All ! 640.00: ., -. Section 1T. All 1 640.00. j Section 18: All 614.00;:.,, 16 T10N R2E. UMC _____._.... .._----- AA-081801 ----- -�---- i 8/31/09 : t6.o667y _._.. _ U.S. 100% �ConocoPhillips: None iiConocoPhiihps. --- 78.0 . Section t: All ',. 639.00 932536 Anadarko Anadarko-; 22.0 Section 2: All Section 3: All - 639.00. 640.00 j 100.0 Section 10: All 639.00 Section 1 L All; 640.00. -, Section 12: All j 640.00' - - Section 13: All i 639.00'. Section 14: All 640.00 �1 Section 15: Alli 640.00 '. .. 5756.00 .._..__._._ 77 � T10N-R3E, UM - AA -087798 • - 8131/09 16.6667°/ U.S. 700% •ConocoPhilhps� None ConocoPhillips Section 6: All 607.00; 932533 '',. Anadarko - ! Anadarko : 2200 'i__ __. ;.__ 100.00 18 'T10N R7W UM Section 19: All j AA -081809 8131109 X 16.6667% - U.S. i 100% co n- Hips ooPhlHi ' _-- None - _ ConocoPhdhps - 7800 Section 20: All 675.00 640. W'' 932544 : Anadarko Anadarko. 22.00 Section 21: Ali •', 640-00i j I 100.00 Section 28: All 640.00', Section 29: All i 640.00', , Section 30: All j 619.00': Section 31: All 622.00. Section 32: All 640.00' Section 33: All 640.00:. j 19 TIONion22 Section AA -081807 ',� 8/31/09 � 16.6667% � .6667 U.S. -00 ._....__ U.S. 100°0 ConocoPhdh None ConocoPhtlhps 78. All 22: All Section 23: All '', 640.00 639.00': 932542 : �I - Anadarko : � � Anadarko. 2 00 Section 24: All 640.00' ':, % j 100.0 Section 25: All ' 639.00' Section 26: All 640.00'- I Section 27: All 639.00: '., Section 34: All 640.00,,' Section 35: All 639.00' ! Section 36: All 640.00' '. 5756.00 -__ ___..____ ..... _.._ - ._... 20 1 T10N RIE, UM Section 19: All 616.00 AA -081804 8!31/09 76.6667% U.S. 100% .ConocoPhillipr None ConocoPhillips 78.00 932539 Anadarko - Anadarko 2200. j Section 20: All . Section 21: All 640.00: 640.00•- - -.. 100.00 Section 28: All 640.00: - Section 29: All 640.00 - Section 30: All 619.00. j Section 31: All 621.001 Section 32: All 640.00: -: Section 33: All 640.00: 5696.00 __. •`__.____ _....__ __...._.._ _. 3 v3cnoae Exhibit S Greater Mooses Tooth Unit Area Leases Unit Agreement for the Exploration, Development and Operation of the Greater Mooses Tooth Unit Area Tract Description_ Number Serial Numper Expiration Basic Basic OwnersMp Lessee_ _- vemding Royait Working, ._ 2wnershil No. of Lands of Acres Tobin Number Date Ro alt Ro alt Owner Percents a of Record and Percents a Interest Owners Percents 21 T1 ON -RI E, UMI i AA -081803 8/31109 16.6667%', U.S. ,. 100% ConocoPhillips, None ConocoPhillipsl 78.E Section 22. All 640.00! 932538 '', Anadarko '.. : Anadarko', 22 Section 23: All 640.00 Section 24: All 640.001 Section 25: All 639.001 - Section 26: All 640.00' - - Section 27: All 639.001 Section 34: All 640.06: - Section 35: All 1 639-001... Section 35: All i 639.M -. 22 --.. -1 -ON -20: - 061800 -- _- ....---., 8/31/09 16.6667h ---- -- U.S. 100ro ----- ConocoPhili s None ConocoPhdk s 78. Secton 19: 932535 Anadarkop Anadarko Section All ''. 640.00 100. on 2t: All! Section 640.001. Section 28: Al:: 640.001 Section 29: All ! 640.00;' Section 30: All 1 619.00',, Section 31: All 621.001, Section 32: All 640.00', Section 33: All 1 640.00; i - 23 T10N R2E, UM i AA -081799 8/31/09 16.66671e U.S. 100/ ConocoPhilkps, None i ConocoPhtlfips,• 78.E Section 22: All I 640.00 932534 '',... Anadarko Anadarko. 22. Section 23: All 640.00; i 100.E .' Section 24: All 639.00 Section 25: All ' 639.00 Section 26: Alli 639.00. I Section 27: All 639.00 Section 34: All !, 640.00 Section 35: Al 640.00 '.. Section 36: All 1 640.00 5756.00 24 8131109 16.6667kf -U.S.Section -, COAnadark Ips; one __._... Con �-� �t78 1: l 93252388 Anadarko .• Section 2: All 64�0�0 Section 13: All 639.00! 1919.00', .._- 25 T9N R1E. UM - AA -081785 -8/31---- 16.6667 109 UFS]. ---- 10000% - ConocoPhrlkps. None ConocoPh�llips 78.1 Section 4: All 640.00 932520 Anadarko, Anadarko 22-1 Section 5: All 640.00 100., Section 6: All ! 624.00': L. Section 7: All ` 626.00.. Section 8: All 640,00' - Section 9: All - 640,00, Section 16: Al:640.001 Section 17: All 640.00' '.'. Section 18: All 630.00: - -:... _.......__• ......__ 5720.00 ......---- : -_.. __ _......_...._._ 26 T9N RIE, UM AA -081784 8/31109 ' 16.6667/ U.S. 100% : ConocoPhillips, None ConocoPhillips 78.1 Section 1: All 640.00' 932519 ! Anadarko Anadarko. 22.1 Section 2: All 640.00: 100.( Section 3: All : 640.001 - Section 10_ All 640.00! - Section 11: All 640.00'. Section 12: All 639.00'. - Section 13: All 639.001 -, Section 14: All -. 639.00' - - Section 15: All 639.00': - 5756.00 .-___ .. ......... __ -__.. 4 a-zoea Exhibit B Greater Mooses Tooth Unit Area Leases 113012me Unit Agreement for the Exploration, Development and Operation of the Greater Mooses Tooth Unit Area Tract Descnplion Number SenaLNumber Expiration Basic Basic Ownership Lessee erriding Royal Working Ownership No. of Lands of Acres ToGn Number Date Ro It Ro a Owner Percents a of Record and Percent -e (merest Owners Percents e- 27 T9N-R2E, UM :, AA -081781 8131/09 16.6667% U.5. 100% % ConocoPhillips'.. None ConocoPhillipsl. 78.00 Section 4: All ! 640.00"'. 932516 : Anadarko Anadarko: 22.0 Section 5: All _ Section 6: All 640.00'. 624.00' - -,• 100.00 Section 7: All ! 626.00' Section 8: All 640.00 Section 9: All i 640.00'. Section 16: All ! 640.00. Section 17: All 640.00: -; Section 18: All ! 630.001. 5720.00 -081760 8/31109 16.6667 . U.S. 100-ConocoPhilhpsl ---- --i None ! ----- ConocoPhllllps- ------- 78.00 Section 1: All 640.00 932515 :. Anadarko j j Anadarko' 22.00 Section 2: Atl Section 3: All 639.00, 640.00'':' 100.00 Section 10: All 639.00, j Section 11: All 639.00: Section 12: All 640.00`: - I Section 13: All i 639.00:- Section 14: All 640.00-'I Section 15: All 640.00 j 575&00:._..______r.____ . 29 _ T9R3E, UM AA 1779 8131109 6.6 :1667% U.S. 100%--ConocoPhillips!. None ConocoPhtlhps, 78.00 Section 5: All 640.00 932514 : Anadarko Anadarko: 22.0 Section 6: Alf'-. Section 7: All 624.00:, 627.00! - - :. 100. 00 Section 8: All 640.00' Section 9: AN ::' 640.00'.,.., Section 16: All 640.00'. Section 17: All':, 640.00'. Section 18: All i 630.00'; 5081,00' : -_.__...._._ _._....._._._... -_t.__._-__ _..___.__ ?__._.___ ..__.._',;_ AA -081778 : 8/31!09 -16.6667%' U.S. 100% ConocoPhtlhpsl None ConocoPhillrps 78.017 Section 10: Alli 640.00, 932513 Anadarko Anadarko:22.00 Section 15: All 640.00 __._-_._._ 100. 00 1280.00 _ ...._.._ 31 ; T9N R1 E, UM AA -081782 : 8/31/09 16.W7%:U.S. - 100% •ConocoPhilkpsl None ': -- ConowPbillips; ---- 78.0 Section 22: All 640.00 932517 Anadarko Anadarko) 22.00 Section 23: All Section 24; All 640.00. 639.00 :, . j 100.00 Section 25: All : 640.00' Section 26: Alli 639.00'': Section 27: All 640.001 - -' Section 34: All 639.001 Section 35: All 63900 '.. Section 36: All', 640.00' 5756.00 32 T9N R2E. UM AA -081736 8131/09 18.6667% __._._._ .___._. _.op U.S. 100% Connadarko s ..... .�... None ... GonocoPhil6ps, 78.00 Section 19: All 631.00 300840 :, - Anadarko Anadarko' 'Section 20: All 640.00; ',. ',. 0 Section 21: All 6.00: 40 100 � Section 29: All 640.001 - - Section 30: All 635.00; Section 31: All 638.00 Section 32: All 640.00• - - 4464.00. ........, .................. ,... .......,.......... .,..................._...... 113012me Exhibit B Greater Mooses Tooth Unit Area Leases 6 713012608 Unit Agreement for the Exploration, Development and Operation of the Greater Mooses Tooth Unit Area Tract Description Number Serial Number Expiration Basic Basic Ownership Lessee Overriding Royalt Working Ownership_. No. of Lands of Acres Tobin Number Date Ro aA Ro al Owner Percents a of Record and Percents a Interest Owners Percents e 33 T9N-R2E, UM AA -081735 8/31109 16.6667`%',, U.S. 100% ConocoPhillipsi None ConocoPhillipsi 76.00 Section 22. All 640,00 300839 Anadarko Anadarko! 2200 Section 23' All 640.ODI,. 100.00 Section 24: All. 640.00. 34 T9N-R3E, UM - _ _ ,._.. ...__.___ p ._ __ .......__.._.._. AA -081777 8131/09 16.6667 U.S. 100 O si None ._.. ._........_ ConocoPhtltips _— _._ _ 78.00 Section 19: All 632.00 932512 I Anadarko Anadarko 22.00 __._.. Section 20: All : 640 001, 1272.00.. __...__ .........__ 6 713012608 4 ".-in ` LOokou! i A AA08°l85;AA,. " " G,_ f a WAPA_.. AA08181() AA08f+ AAt981 808 AAO „ �m� Mitre F' a AA 1802 AA08 :801 a iiEtgiYLZ>$ A .� {�[ C�Dery7�PAY e.r r rr5�� ryw.A AA -- f). lS!'S0 0".......��t t K3W MF`.if'fw` ,m+ A A (�y� Aa' a ai^c �5.n {{'��-� Frv%yvr�i er P rw t t Ari_ AAz 7�, 5 . ' L w. 3 L�iisa Area t ; AAS�1 pp t� ' OR _... 782 AA061i36 Conocof C10) Tract Num ber ..8', AA061785 Lease i') Ex it ---r--�- Participating Area Prone ourtdaries (Red, Blue car Green) rY., _ . am EXHIBIT D PROPRIETARY DATA NOT AVAILABLE FOR PUBLIC VIEW EXHIBIT E PROPRIETARY DATA NOT AVAILABLE FOR PUBLIC VIEW THE STATE Department of Natural Resources OIALASKA R Ear E' V E ® DIVISION OF OIL & GAS 550 W 7" Avenue, Suite 1100 DEC 16 2016 Anchorage, AK 99501-3560 Main: 907.269.8800 GOVERNOR BILL WALKER Fax: 907.269.8939 December 15, 2016 Commissioner Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue Anchorage, AK 99501 Re: Greater Mooses Tooth Unit Measurement Application Dear Commissioner Foerster: CERTIFIED MAIL RETURN SERVICE REQUESTED During a November 17, 2016 public hearing held by the Alaska Oil and Gas Conservation Commission (AOGCC) the Commissioners requested comment from the State of Alaska, Department of Natural Resources, Division of Oil and Gas (Division), concerning the proposed meter allocation factor applied to the Greater Mooses Tooth Number 1 (GMT I) development. The Division has carefully considered the information provided by ConocoPhillips Alaska, Inc. (CPAI) in support of the application for a waiver of the 20 AAC 25.228(a) requirements, testimony provided to the AOGCC during the public hearing process, and the conditional approval by United States Department of the Interior, Bureau of Land Management (BLM) for the use of Coriolis meters. The Division finds that the metering tools and procedures proposed by CPAI to the AOGCC are sufficient to accurately differentiate between the volume and quality of production originating from GMT and the volume and quality of production originating from the Colville River Unit for royalty accounting purposes. The BLM conditional approval requiring meter proving and an extensive audit trail, and additional information CPAI provided proposing third party review of shrinkage factors have increased our confidence in the metering system and our ability to verify volumes allocated to GMTI. Accordingly, the Division does not object CPAI's proposed metering system. Sincerely, Ja j B. Beckham Deputy Director cc: Department of Law ConocoPhillips December 8, 2016 Commissioner Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 W. 7t" Avenue Anchorage, AK 99501 RE: Greater Mooses Tooth Unit Measurement Application Follow -Up Responses to November 17, 2016 Hearing Docket Number OTH-16-025 Dear Commissioner Foerster: Brandon Viator Project Integration Manager, GMTU ConocoPhillips Alaska 700 G Street Anchorage, AK 99501-3439 907.263.4653 DEC G 8 2016 ConocoPhillips Alaska, Inc. (CPAI), as Unit Operator of the Greater Mooses Tooth Unit (GMTU) and Colville River Unit (CRU), and on behalf of itself and the other working interest owners presents the information in the enclosed attachment to address questions posed by the Commissioners at the November 17, 2016 hearing on the GMT1 allocation factor (Docket Number OTH-16-025). If you have questions or need additional information, please contact me at 907-263-4653. Sincerely, Brandon Viator Project Integration Manager - Greater Mooses Tooth Unit ConocoPhillips Alaska Attachment 1. AOGCC Allocation Factor Hearing Follow -Up Responses a. Attachment 2, Appendix B (from application) b. BLM Measurement Approval — 14Oct2016 c. Attachment 1F — Updated Nov 2016 d. Attachment 2 (from application) e. AOGCC Hearing Presentation (from May 3, 2016) f. Attachment 1B (from application) g. Attachment 1C (from application) h. AOGCC Hearing Follow-up—Jun 2, 2016 AOGCC Allocation Factor Hearing Follow -Up Responses to AOGCC Questions December 7, 2016 The following information answers questions raised by the AOGCC Commissioners during the November 17, 2016 hearing on ConocoPhillips Alaska, Inc.'s (CPAI) GMT1 measurement application regarding the allocation factor of 1. AOGCC QUESTIONS and CPAI RESPONSES 1. What is the range in error of using this type of meter (referring to Coriolis meters)? The Coriolis meter range in error comes from the manufacturer's literature as having a base accuracy of+/- 0.1%. This results in a meter flow calibration factor (FCF) uncertainty of+/- 0.03%, which can be found in section 2.1 in the uncertainty calculations CPAI provided in our application, Attachment 2, Appendix B. Those calculations are provided here for quick reference on page 7. Ej Attach 2 -App B.pdf Through the course of progressing our measurement application with the AOGCC, the BLM was also reviewing our measurement application and ultimately required GMT1 to include a means of meter proving other than smart meter verification. The additional proving requirement has now been incorporated into the current GMT1 design with an in-situ master meter with monthly proving. This is new information to the AOGCC, but a key point worth mentioning because the Coriolis meters will now be proved on a monthly basis utilizing an in-situ master meter. The BLM's approval, along with associated Conditions of Approval (COAs) are attached here for reference. BLM Approval_140ct201E Attachment 1F from our original application has been updated to reflect the current design, inclusive of the master meter, and is attached here. Ed Attachment 1F -Updated Nov201 The meter uncertainty (or error) is only one component of the overall system uncertainty. Please refer to Section 2.0 on page 4 and Table 2 on Attachment 2 in our application. r] Attach 2 GMT1 Flow Measurement and N page 5 of the following attachment, which was Table 2 is a comparison of Stable Fluid (processed, LACT metering) uncertainties to that of Live Fluid (unprocessed, non-LACT conditions) uncertainties. The Live Fluid values represent our proposed GMT1 oil measurement system. The Live Fluid Mass flow rate uncertainty of +/- 0.16% is derived from the Coriolis meter's base accuracy, plus temperature and pressure correction uncertainties. The Observed Volume uncertainty of +/- 0.27% is then derived by including density uncertainty to the calculation. What can be seen from the side-by-side comparison in this Table 2 is that Observed Volume uncertainty is nearly the same as that for a LACT system and the variance only widens when the Observed Volume of Live Fluids is converted to Standard Volumes (i.e., volumes at Standard conditions: 60 °F and 14.7 psi). For stable, processed fluids the calculation applies a Volume Correction Factor (VCF) that has a low uncertainty value and comes from table and calculations created by the American Petroleum Institute (API). For live fluids (like at GMT1), the calculation includes a Shrinkage Factor that has an uncertainty of+/- 2.0% and results in an overall system uncertainty of+/- 2.1%. The volumes that will receive an allocation factor of 1.0 at GMT1 are the Standard Volumes (measured, shrunk volumes). 2. What are the royalty shares at Alpine versus GMTU? This question was posed to the Department of Revenue (DOR). But since DOR is a tax -focused entity with little or no engagement on royalty issues, CPAI has undertaken a response. The royalty rate at GMTU is 1/6 and is split between ASRC and BLM based on land ownership. The mineral ownership division is shown in Slide 5 from ConocoPhillips' testimony during the hearing on May 3, 2016. Attachments 113 and 1C from the GMT1 measurement application shows the conceptual Participating Area (PA) across the same lands and royalty ownership of those lands, respectively. These documents are attached here for reference. AOGCC Hearing Attachment 1B.pdf Attachment 1C.pdf Presentation FINAL. In the CRU, the royalty rate ranges from 1/8 to 1/3. Mineral ownership is divided among BLM, ASRC and the State. The division of ownership within the CRU is also shown in Slide 5 of the attached hearing presentation. 3. Is the metering system at GMTU (Coriolis meter) similar to the allocation meters currently in use at the CRU? GMT1 will use Coriolis meters to measure oil and Orifice meters to measure gas, both operating 24 hours per day, 7 days per week in continuous service on the outlet of a dedicated full -flow production separator. The production separator volume, adjusted by calculation for shrinkage at standard conditions, is the volume that will be reported for GMT1 (i.e., production from the Lookout participating area). All drillsites within the CRU also use Coriolis meters, measuring both gas and oil streams from the outlet of a test separator. Each drillsite has a dedicated test separator that can be used to test one well at a time on that drillsite. Each well is tested twice per month, in accordance with the governing pool rules. The well tests are conducted to determine the rate a well will produce under known operating conditions and then adjusted to standard conditions (shrinkage is applied). Well tests typically last from 6 to 8 hours and vary depending on how long it takes to achieve stable flow. The target is to run a 4 -hour test under stable flow conditions. Based on the well tests, theoretical production is calculated for each well. This is done either directly from well tests or through the use of rate tables that are based on well tests and take into account changes in gas lift rates, changes in well head pressures, and time that the well is not on production. The theoretical volume for each well is summed to calculate a total theoretical volume for all CRU wells. The allocation factor for all wells is the ratio of oil sales from the LACT meter to total theoretical volume. The allocation factor multiplied by the theoretical volume for each well derives the well allocated volume. The allocated volume of wells within a PA are then summed for the total PA production. CRU currently has six PAs. The uncertainty associated with a well test measurement system at the CRU is dependent on flow rates, but has an uncertainty of roughly +/- 4.5%. As mentioned above, the GMT1 measurement system has a +/- 2.1% uncertainty. Of course, all production from both GMT1 and CRU will ultimately be measured to an even higher level of certainty at the LACT meter, downstream of processing and immediately upstream of delivery the Alpine Pipeline. 4. What is the historical range of meter factors of the allocation meters at CRU? The allocation factor at CRU between October 2015 and May 2016 ranged from 0.97 to 1.01, with a median value of 0.99. This factor correlates measured volume at the LACT meter to theoretical volumes based on well tests using test separators at the drillsites, and rate tables. The CRU allocation factors were addressed in a letter were sent to the AOGCC on June 2, 2016 (attached below). Please refer to our response to Question 3 in Attachment 1 of the referenced response letter for more information on this issue. RJE Cover Letter - AOGCC Hearing Foll The Alpine oil measurement system includes three LACT meters with two in service and one in standby at any given time (meter tags FE -31011, FE -31012, and FE -31133). From May 2011 through November 2016, the historical meter factors for these three LACT meters at ACF ranged from 0.994 — 0.99715 for FE 31011, 1.01234 — 1.01717 for FE 31012, and 1.01051 — 1.01704 for FE 31133. The average shift in meter factors between proves is 0.02% for all three meters. S. What will be the leak detection system for the GMTU before it ties in with Alpine or CDS? This question seems out of place in the context of an AOGCC hearing on the allocation factor proposed for a metering system. Nonetheless, the answer follows. ConocoPhillips has a leak detection program that includes the following: • Daily operator AVO (audio, visual and olfactory) inspections, weather permitting, of the drillsite modules, well houses, outdoor piping and pipelines. • Gas detector monitoring of modules and well houses that have local alarms and are monitored remotely in the control room at the Alpine Central Facility (ACF). • Remote monitoring in the ACF control room of pressure, temperature and other variables that have alarms set to indicate a possible leak or significant changes in flowing conditions. • Weekly FUR (Forward Looking Infra -Red) flyovers to monitor pipelines and drillsites for potential leaks. 6. Why is everyone in agreement with an allocation factor of 1? The AOGCC would like to see some technology applied to the answer. While this question appears to have been directed at mineral owners other than CPAI, we submit the following response based on our discussions with DNR, DOR, and ASRC. ConocoPhillips performed analysis on the range of uncertainties associated with a full -flow production separator measurement system as described above, in the GMT1 measurement application, our May hearing presentation materials, and our responses to AOGCC questions posed at the May hearing. The key variable in driving the uncertainty value is the application of a Shrinkage Value, which must be done for the measurement of live fluids (i.e., non-LACT measurement of fluids upstream of processing facilities). The system that has been proposed for GMT1 is a robust design that was reviewed with the mineral owners, including review of associated uncertainties prior to our application. The Flow Measurement and Metering Philosophy document, which was Attachment 2 of our application to the AOGCC, outlines the design and how this system will be operated and maintained. CPAI is not aware of any objection to the proposed design or any concern that the system is not sufficiently accurate and reliable. There is no overriding reason and no request for the application of a factor other than 1.0 to apply to the GMT1 meter. ATTACHMENT 2: APPENDIX B HELD IN CONFIDENTIAL STORAGE Form 3160-5 BLM Approval - 140ct2016 - • / ' j (August 2007) UNITED STATES FORM DEPARTMENT OF THE INTERIOR OMB NAPPROVED %o° 013 / BUREAU OF LAND MANAGEMENT Expires: 7uly 31, 2010 SUNDRY NOTICES AND _ -REPORTS - — -- -- ON WELLS--- 5-LeaseSerial No.- -- - --- - / --- Do not use this form for proposals to drill or to re-enter an AKAAs1796 abandoned well. Use form 3160-3 (APD) for such proposals. 6. If Indian, Allottee or Tribe Name SUBMIT IN TRIPLICATE - Other instructions on reverse side. 7. If Unit or CA/Agreement, Name and/or No. 1. Type of Well 8. Well Name and No. Q Oil Well Q Gas Well ® Other: UNKNOWN 0TH GMT1 62 2. Name of Operator Contact: SAMWIDMER CONOCOPHILLIPS E -Mail: Sam.WidmerCconocophillips.com 9• API Well No. 3a. Address 3b. Phone No. (include area code) 700 G STREET P 10. Field and Pool, or Exploratory h: 907-227-1777 LOOKOUT PROSPECT ANCHORAGE, AK 99510 4. Location of Well (Footage, Sec., T., R., M., or Survey Description) Sec 6 TI ON R3E 11. County or Parish, and State NORTH SLOPE COUNTY, AK 12. CHECK APPROPRIATE BOX(ES) TO INDICATE NATURE OF NOTICE, REPORT, OR OTHER DATA TYPE OF SUBMISSION TYPE OF ACTION I N Notice of Intent Q Acidize Q Deepen Q Production Start/Resume ❑ Alter Casing ) Q Water Shut -Off Q Subsequent Report Q Fracture Treat Q Reclamation Q Well Integrity Q Casing Repair Q New Construction Q Recomplete ® Other Q Final Abandonment Notice ❑ Change Plans Q Plug and Abandon Q Temporarily Abandon Convert to Injection Q Plug Back Q Water Disposal j 13. Describe Proposed or Completed Operation (clearly state all pertinent details, including estimated starting date of any proposed work and approximate duration thereof. j 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 shall 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 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 GMT! 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 MeteringPhilosophy - . (3) October 1, 2014 Whitepaper- GMT1 Comminglin, Alocation, and Measurement Summary.parator, and 14. I hereby certify that the foregoing is true and correct. Electronic Submission #329405 verifi by the BLM Well Information System For CONOCOPHILLIPS sent to the Anchorage Narue(Printe&Typed) BRANDON V T05 --,,Title PROJECT MANAGER ouu=mssJonjl�= Date 01/21/2016 THIS SPACE FR F DERAL OR STATE OFFICE USE Approved iLroved By Conditions of approval, i an , are Approv oft is notice does not warrant or certify that the applican of s legall or or equitable title tot se rights in the subject lease which would entitle the app 'cant to conduct operations t ereon. 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 API 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 AO. 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 be set 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 OO4.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 OO4.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 not 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. Attachment 1F: GMT1 Production Separator Measurement System (Nov 2016) ❑Phase Dynamics Water Cut meter Line List: Orange: Gas ® �U ®Coriolis Meter Green: Oil+water OOrifice Plate Meter Blue: Separated water Black: Oil+water+gas 0 Gas sample station Production to CD5/ ACF Attachment 2 ConocorDihillips Alaska Greater Mooses Tooth 1 Flow Measurement and Metering Philosophy - Three Phase Production Separator Oil and Gas Measurement Revision 1 February 9, 2016 Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl .doc GREATER MOOSES TOOTH I � S FLOW MEASUREMENT AND METERING PHILOSOPHY Coi�ocoPhilli M — THREE PHASE PRODUCTION SEPARATOR OIL Alaska MEASUREMENT REI! I DATE: 2/9/16 PAGE 2 OF 17 TABLE OF CONTENTS 1.0 INTRODUCTION......................................................................................................................3 2.0 VOLUMETRIC CONVERSION .................................................................................................4 2.1 Measurement System Design, Operation and Maintenance.........................................5 3.0 FLOW MEASUREMENT AND METERING SYSTEM DESCRIPTIONS...................................5 3.1 Custody Transfer/Point of Royalty Metering..................................................................6 3. 1.1 Production Separator Oil Metering....................................................................6 3.1.2 Production Separator Gas Metering..................................................................7 3.2 Drillsite Gas Metering...................................................................................................7 3.3 Operation and Maintenance..........................................................................................8 3.3.1 Coriolis Oil Meters.............................................................................................8 3.3.2 Differential Pressure Gas Meters......................................................................8 3.3.3 Secondary Measurement Instruments...............................................................8 3.3.4 Sampling...........................................................................................................8 3.3.5 Shrinkage Factor...............................................................................................9 4.0 ALLOCATION METHODOLOGY ...........................................................................................10 5.0 GENERAL INFORMATION....................................................................................................10 5.1 Industry Standards......................................................................................................10 5.2 Terms and Definitions.................................................................................................12 5.3 Abbreviations and Acronyms......................................................................................13 5.4 Units of Measurement.................................................................................................14 6.0 MEASUREMENT PROJECT ACTIVITIES AND REQUIREMENTS.......................................14 6.1 General.......................................................................................................................14 6.2 Design........................................................................................................................15 6.3 General Installation Requirements..............................................................................15 6.4 Instrument Traceability...............................................................................................16 6.5 Measurement System Fabrication and Testing...........................................................16 6.6 Commissioning...........................................................................................................16 6.7 Handover....................................................................................................................17 6.8 Maintenance...............................................................................................................17 6.9 Test Equipment..........................................................................................................17 6.10 Audit...........................................................................................................................17 Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl .doc 1✓ ConocoPhillips Alaska 1.0 INTRODUCTION GREATER HOOSES TOOTH 1 FLOW MEASUREMENT AND METERING PHILOSOPHY -THREE PHASE PRODUCTION SEPA RA TOR OIL MEASUREMENT REV. I DATE: 2/9/16 PAGE 3 OF 17 The GMT1 project will develop the first drill site in the Greater Moose's Tooth Unit (GMTU) which is in the northeast corner of the National Petroleum Reserve — Alaska (NPR -A). The GMT1 project will develop resources on Arctic Slope Regional Corporation (ASRC) and federal government leases, and ConocoPhillips seeks approval for the measurement system design from both the Bureau of Land Management (BLM) and Alaska Oil and Gas Conservation Commission (AOGCC). This document is part of a submission package for approval of the proposed oil measurement system for GMT1 in accordance with Section E — ("Oil Measurement by Other Methods") of the BLM Onshore Oil and Gas Order No. 4; Measurement of Oil (1989). This document is also in accordance with BLM's December 24, 2014 letter expressing intent to approve a measurement system for GMT1 that uses a continuous separator, and with Alaska Administrative Code 20 AAC 25.228, which addresses AOGCC approval for production measurement prior to custody transfer. The need for this submission stems from the design of GMT1 as a satellite drillsite 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 as per the requirements of the American Petroleum Institute (API) Manual of Petroleum Measurement Standards (MPMS) chapter 6.1 Metering Assemblies - Lease Automatic Custody Transfer (LACT) Systems (2012). Additionally, this submission is requesting an AOGCC approval of off lease measurement of re- iniection and miscible infection gas from Colville River Unit (CRU) at GMT1 per 20 AAC 25.228, which requires custody transfer measurement prior to hydrocarbon production severance from the unit where produced. The off lease gas measurement methodology is proposed to minimize impacts to existing infrastructure in the CRU and overall project cost The metering system is designed for approval under both State of Alaska and Federal regulatory requirements as per Table 1 below. Table 1 — State of Alaska and Federal Regulations 20 AAC 25.228 Production Measurement Equipment for Custody Transfer AOGCC Industry Guidance Bulletin 13- 002 Custody Transfer Meter Application Guidance B'LNI Onshore Orders and Notice to Lessees (NTL) Onshore Order 3 Site Security (Effective Date: March 27, 1989) Onshore Order 4 Measurement of Oil (Effective Date: August 23, 1989) Attach 2 GMT1 Flow Measurement and Metering Philosophy_Rev1.doc GREATER MOOSES TOOTH I n5 FLOW MEASUREMENTAND METERING PHILOSOPHY ConocoPhillips M - THREE PHASE PRODUCTION SEPA RA TOR OIL Alaska MEASUREMENT REV. I DATE: 219116 PAGE 4 OF 17 2.0 VOLUMETRIC CONVERSION The following paragraphs provide an explanation and illustration as to why it is not possible to comply with the BLM onshore order for oil measurement and why we must submit an application to measure oil by other methods to those prescribed in Onshore Order No. 4. The GMT1 project constraints require that we measure live fluids at elevated temperature and pressure. 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 (EOS) modeling based upon detailed compositional analysis. The uncertainty budget for these methods are dependent upon a range of variables which include the representivity of samples, the quality of test equipment and the detail of compositional data obtained. The uncertainty budget associated with Shrinkage Factors is not well documented for either laboratory or EOS modeling; however available industry literature such as the draft API MPMS Chapter 21.4 and experience from field operations elsewhere in ConocoPhillips suggests that +/-2% is a reasonable estimate. Appendix A of this document provides approximately four years of ConocoPhillips United Kingdom J -Block daily mass balance errors as field operations evidence in support of the uncertainty budget estimate. 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. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Rev1.doc 2.1 3.0 'b" ConocoPhillips Alaska GREATER MOOSES TOOTH I FLOW MEASUREMENTAND METERING PHILOSOPHY —THREE PHASE PRODUCTION SEPARATOR OIL MEASUREMENT REV. I Table 2 — Comparable Measurement Uncertainties DATE: 2/9/16 PAGE 5OF17 Stable Fluids Uncertainty (%) Major Contributors Live Fluids ° Uncertainty (/°) Major Contributors Flow Meter Base Flow Meter Base Accuracy plus Accuracy plus Mass 0.15 Pressure and Mass 0.16 Pressure and Temperature Temperature Corrections Corrections Observed Mass Uncertainty Observed Mass Uncertainty Volume 0.25 plus Observed Volume 0.27 plus Observed Density Uncertainty Density Uncertainty Mass Uncertainty, Mass Uncertainty, Observed Density Observed Density Standard 0.35 Uncertainty Plus Standard 2.1 Uncertainty Plus Volume Conversion to Volume Conversion to Standard Volume Standard Volume Uncertainty (VCF) Uncertainty (SF) Measurement System Design, Operation and Maintenance It is very important to note that the differences in performance in determining Standard Volume between the BLM onshore order or AOGCC 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 GMT1 oil production is provided as Appendix B of this document where a maximum value of +/- 2.1% at 95% confidence level has been determined. The calculations required to determine Net Standard Volume are also contained within the uncertainty calculation provided in Appendix B. The operating and maintenance methods contained in section 3.3 of this document will allow us to monitor and verify the performance of the metering system and its components to demonstrate ongoing compliance with agreements reached based upon this submission in accordance with the onshore order. FLOW MEASUREMENT AND METERING SYSTEM DESCRIPTIONS The oil metering system described in this section has been designed to obtain approval under state and federal regulations and incorporates experience from existing installations and previous projects. The GMT1 project is located 14 miles west of the Alpine Central Facility (ACF) in the GMTU within the NPR -A on the North Slope of Alaska. The GMT1 drillsite development scope includes Attach 2 GMT1 Flow Measurement and Metering Philosophy_Rev1.doc GREATER NOOSES TOOTH 7 ✓ FLOW MEASUREMENT AND METERING PHILOSOPHY DATE: 2/9/16 ConocoPhilli - THREE PHASE PROD UCTION SEPARATOR OIL Alaska MEASUREMENT PAGE 6 OF 17 REV. 7 all on -pad production facilities and off -pad infrastructure including a gravel access road and drillsite pad. The GMT1 development will connect to the CD5 drillsite via eight miles of pipelines, power lines, and gravel road; providing the first infrastructure into the GMTU and connecting the project to the existing CD5 and CRU infrastructure. The project scope includes 9 initial wells (4 production wells and 5 injection wells). The GMT1 drillsite gravel pad will accommodate up to 33 wells for possible future development. GMT1 will consist of eight process modules and a well row. The process modules consist of a pig launcher/receiver module, full flow three-phase production separator, production heater, test separator, remote electrical & instrumentation module (REIM), emergency shutdown module (ESD), chemical injection module and fuel gas conditioning module. The drillsite full -flow production separator, elevated to prevent gas breakout, will serve as AOGCC's unit boundary custody transfer measurement and BLM's point of royalty measurement (PRM) for produced oil and gas hydrocarbon streams. After measurement, the well fluids will be recombined and travel to ACF in the production crude pipeline. The ACF separates and processes well bore fluids from the production crude pipeline and delivers sales -quality crude oil. ACF -processed produced water is returned to the drill sites for re-injection into the producing formations to maintain reservoir pressure and provide secondary flood support. ACF -processed gas is returned to the drillsite as miscible injection (MI) or lift gas, or used within the plant as fuel gas. MI is re -injected in the reservoir to maintain reservoir pressure and to enhance oil recovery. Lift gas is used for production well lift and converted to fuel gas for drillsite utilities. 3.1 Custody Transfer/Point of Royalty Metering The custody transfer/PRM system shall 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, weir (three-phase operation), mist extractor on the gas outlet, vortex breaker and sand -jet system. 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 throughout field life 3.1.1 Production Separator Oil Metering The oil metering system shall consist of two Micro Motion Elite Coriolis Flow Meters installed in a parallel configuration, sized to cope with the full range of expected flow rates, and includes strainer, inline mixer, water cut analyzer, pressure and temperature instrumentation and control valves. All flow measurement information shall be fed to a dedicated flow computer in order to calculate Net oil volume at standard conditions. An automatic flow proportional sample system shall be installed in order to permit collection of representative oil samples for laboratory analysis. Process and Instrumentation diagrams (P+ID's) of the GMT1 production separator and oil metering system can be seen at Appendix C of this document. This is a dual redundant metering system configuration which will permit maintenance and operational activities to be performed without interruption to production. Flow calculations shall be performed as per the calculation detail provided in Appendix B of this document and in accordance with API chapter 20.1 Allocation Metering. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl .doc GREATER MOOSES TOOTH 1 \✓ ConocoPhillips FLOW MEASUREMENT AND METERING PHILOSOPHY DATE: 2/9/16 M - THREE PHASE PRODUCTION SEPARATOR OIL Alaska MEASUREMENT PAGE 7 OF 17 REV. I All measurement equipment and sample system hardware shall be installed per suppliers' recommendations. Sufficient pressure head and careful arrangement of piping are critical factors to avoid flashing of gas and for proper metering systems performance. 3.1.2 Production Separator Gas Metering 3.2 The production separator gas outlet metering system shall include two meter runs providinq for the full range of gas flowrates from the drillsite Conceptually this will be accomplished by two similar AGA compliant orifice meter runs of different size Additionally, -the two meter runs provide a level of redundancy, again to help ensure improved drillsite uptime Fully redundant meter runs were deemed not necessary due to the highly reliable orifice metering technology and the relatively minimal maintenance down time to repair the meter. Each meter run will consist of upstream and downstream meter tubes flow conditioner, senior orifice fitting and plate, and control valve. A flow computer and DP Diagnostics a differential Pressure diagnostic system, shall be installed on the gas meter runs to monitor the health of the gas metering systems. All measurement equipment shall be installed per suppliers' recommendations Regulatory required flow meter verification and maintenance will be undertaken when the diagnostic system indicates degradation in measurement performance Drillsite Gas Metering Hydrocarbon gas management at GMT1 will require conformance to the applicable federal and state regulations. Similarly to produced hydrocarbons AOGCC requires custody transfer measurement of hydrocarbon gas streams between units It has been determined that total drillsite MI infection gas and reiniection gas including reinfection gas offtake points for total lift gas and fuel gas measurement, will be required to conform with the applicable standards as they are Included in the gas royalty determination and commercial gas agreements Total drillsite reinfection, artificial lift MI and fuel gas stream metering systems shall consist of AGA compliant orifice meter runs. Each meter run will consist of upstream and downstream meter tubes, flow conditioner (as necessary to minimize installation impacts to the gas conditioning module) senior orifice fitting and plate A flow computer and DP Diagnostics a differential pressure diagnostic system shall be installed on the gas meter runs to monitor the health of the gas metering systems. In order to minimize impacts to existing infrastructure at CRU the custody transfer gas meter stations will be physically located on the GMT1 drillsite This will require an off -lease waiver approval per 20 AAC 25.228 which requires custody transfer measurement prior to hydrocarbon production severance from the unit where produced Regulatory required flow meter verification and maintenance will be undertaken when the diagnostic system indicates degradation in measurement performance Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl .doc GREATER MOOSES TOOTH 1 ✓ lfnS FLOWMEASUREMENTANDMETERING PHILOSOPHY DATE: 2/9/16 ConoCoI'1ltll M - THREE PHASE PRODUCTION SEPARA TOR OIL Alaska MEASUREMENT PAGE 8 OF 17 REV. I 3.3 Operation and Maintenance 3.3.1 Coriolis Oil Meters Flow meter verification is accomplished by monthly checking of meter health utilizing 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. In addition, each flow meter shall be removed from service and calibrated at an accredited facility on an annual basis. This approach to monitoring and calibrating Coriolis flow meters has been implemented elsewhere in ConocoPhillips and has yielded satisfactory results over a number of years. Evidence in support of this practice is provided at Appendix D of this document where we have provided traceable information and certification of historical meter performance. We have also included SMV trending from Coriolis meters installed in test separator service at our existing drill sites in Alaska which demonstrate that the required meter performance can be achieved in this environment and that we have the infrastructure available to perform these checks. Manufacturer's brochures for Micro Motion Elite coriolis flowmeters and SMV are provided in Appendix E. 3.3.2 Differential Pressure Gas Meters Differential pressure gas meter verification is in part accomplished by the continuously running DP Diagnostics system. This advanced diagnostic system can reliably warn of orifice meter problems such as two-phase flow, contamination build-up through the meter, blocked impulse lines, saturated or drifting differential pressure transmitters or buckled backwards or worn plates. Additionally, the orifice plates will be pulled for inspection and the meter tubes inspected with a boroscope annually. Manufacturer's brochures for Daniel meter tubes and DP Diagnostics are provided in Appendix E. 3.3.3 Secondary Measurement Instruments The measurement instruments which are used in the determination of net standard volume shall be verified on a three monthly (quarterly) frequency. Verification frequency is based upon historical performance of this equipment. Manufacturer's brochures for Rosemount pressure and temperature transducers are provided in Appendix E. 3.3.4 Sampling Monthly flow proportional oil samples shall be obtained and occasional analyses performed as events dictate in order to provide operations teams with data to compare against observed online measurement parameters. Where a comparison of data shows a discrepancy between observed online information and sample information this will trigger investigative work to resolve the disparity. Attach 2 GMT1 Flow Measurement and Metering Phil osophy_Rev1.doc GREATER MOOSES TOOTH 1 I" CO'. ocoPh'"' S FLOW MEASUREMENT AND METERING PHILOSOPHY - THREE PHASE PRODUCTION SEPARATOR OIL Alaska MEASUREMENT REV. 1 DATE: 219116 PAGE 9 OF 17 Monthly flow proportional samples shall be made available to perform monthly water content (BS&W) analyses and occasional analyses as needed for the following parameters and retained for one year: Pressure, volume, temperature (PVT) analysis to determine shrinkage Compositional analysis of evolved gaseous hydrocarbons Compositional analysis of liquid hydrocarbons Where it is found that any online data, which has been used in the determination of net standard volume, needs to be corrected then operations teams will raise and submit a mismeasurement report in order to correct the reported volumes. Manufacturer's brochures for Phase Dynamics water content analyzers and JISKOOT CoJetix sampling systems are provided in Appendix E. 3.3.5 Shrinkage Factor Shrinkage factor (SF) shall be developed across a range of operating pressures and temperatures so that any process variances are captured in order to prevent a systematic bias impacting the measurement of oil. Table 3 below, linear interpolation matrix, provides an indication of the method which will be employed to determine SF from operating temperature and pressure. Table 3 — SF Linear Interpolation Matrix Process Adjustment Matra with Two Way Linear Interpolation Oil Shrinkage Factor Temperature Pressure 135 350 Pressure > Temperature v 150 250 350 400 125 0.92176 0.87663 0.84492 0.83209 135 0.93135 1 0.88501 0.85297 0.83990 145 0.94081 0.89355 0.86090 0.84759 Process Adjustment 0.853 Factor Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl.doc 'I' ConocoPhillips Alaska me 5.0 5.1 GREATER MOOSES TOOTH I FLOW MEASUREMENT AND METERING PHILOSOPHY DATE: 2/9/16 — THREE PHASE PRODUCTION SEPARATOR OIL MEASUREMENT PAGE 10 OF 17 REV. I 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 GMT1. Net standard volumes will utilize this metering allocation information for royalty payment data. GENERAL INFORMATION Industry Standards The State and Federal regulations do in some instances mandate compliance with particular industry standards, thus elevating them to a regulatory requirement. The below list of Industry Standards should be considered in discussions pertaining to the GMT1 oil measurement concept. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Rev1.doc GREATER MOOSES TOOTH I )0r FLOW MEASUREMENTAND METERING PHILOSOPHY DATE: 2/9/16 Cot'IoCOi�iiilll s I"h - THREE PHASE PR OD UCTION SEPA RA TOR OIL Alaska MEASUREMENT PAGE 11 OF 17 REV. I Table 4 — Industry Standards API 505 Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified As Class I, Zone 0, Zone1, and Zone 2 API RP551 Process Measurement Instrumentation API RP555 Process Analyzers MPMS 4.X (Chapter 4) Manual of Petroleum Measurement Standards Chapter 4 — Proving Systems MPMS 5.X (Chapter 5 Manual of Petroleum Measurement Standards Chapter 5 - Measurement of Liquid Hydrocarbons MPMS 6.X (Chapter 6 Manual of Petroleum Measurement Standards Chapter 6 - Metering Assemblies MPMS 8.X (Chapter 8 Manual of Petroleum Measurement Standards Chapter 8 - Sampling MPMS 9.X (Chapter 9 Manual of Petroleum Measurement Standards Chapter 9 — Density Determination MPMS 14.X (Chapter 14 Manual of Petroleum Measurement Standards Chapter 14 - Natural Gas Fluids Measurement MPMS 20.1 (Chapter 20.1 Manual of Petroleum Measurement Standards Chapter 20.1 - Allocation Measurement MPMS 21.X (Chapter 21 Manual of Petroleum Measurement Standards Chapter 21 — Flow Measurement Using Electronic Metering Systems MPMS 22.X (Chapter 22) Manual of Petroleum Measurement Standards Chapter 22 - Testing Protocol Section TR 2570 Continuous On -Line Measurement of Water in Petroleum Report No. 3 Orifice Plate Metering of Natural Gas and other Related Hydrocarbon Fluids Report No. 5 Natural Gas Energy Measurement Report No. 8 Compressibility Factors of Natural Gas and Other Related Hydrocarbon Gases Report No. 10 Speed of Sound in Natural Gas and Other Related Hydrocarbon Gases Attach 2 GMT1 Flow Measurement and Metering Philosophy_Rev1.doc ConocoPhillips Alaska GREATER MOOSES TOOTH I FLOW MEASUREMENTAND METERING PHILOSOPHY -THREE PHASE PRODUCTION SEPARATOR OIL MEASUREMENT REV. 1 5.2 Terms and Definitions The following terms and definitions apply to this document. Table 5 — Terms and Definitions DATE: 2/9/16 PAGE 12 OF 17 Construction Company or business that agrees to furnish materials and/or Contractor perform specified construction/fabrication services at a price and/or rate to the Owner Engineering/Design Company or business that agrees to furnish materials and/or Contractor perform specified engineering/design services at a price and/or rate to the Owner Metering System Primary and secondary equipment used together to establish flow characteristics for a given process stream. Owner ConocoPhillips Company or a designated affiliate. Operator ConocoPhillips Company or a designated affiliate assigned with the operation and maintenance of equipment. Philosophy A presentation of the guiding principles based upon qualitative characterization, experience, policy, and company culture. Point of Royalty The meter or measurement facility used to measure the volume and Measurement quality of oil and gas on which royalty is reported as due. At quote stage: any entity invited to supply a quotation for the equipment and/or any Subcontractors thereto At Purchase stage: any entity contracted for the supply of the Supplier equipment and/or any Subcontractors thereto. In all cases, the Supplier is responsible for performance of all Work and will be the single point of contact for all Work-related issues. The Company will not receive information from, nor respond directly to Subsuppliers. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl .doc ConocoPhillips Alaska GREATER MOOSES TOOTH I FLOW MEASUREMENTAND METERING PHILOSOPHY -THREE PHASE PRODUCTION SEPARATOR OIL MEASUREMENT REV. I 5.3 Abbreviations and Acronyms The following abbreviations and acronyms apply to this document. Table 6 — Abbreviations and Acronyms 7AA Alaska Administrative Code ACF Alpine Central Facility AGA American Gas Association AOGCC Alaska Oil and Gas Conservation Commission API American Petroleum Institute BLM Bureau of Land Management BOD Basis of Design BU Business Unit CRU Colville River Unit FAT Factory Acceptance Test GMT1 Greater Mooses Tooth 1 GMTU Greater Mooses Tooth Unit HSE Health, Safety and Environmental IM Instruction Memorandum (BLM) MPFM Multi -Phase Flow Meter MPMS Manual of Petroleum Measurement Standards — American Petroleum Institute (API) NPR -A National Petroleum Reserve —Alaska NTL Notice to Lessees (BLM) PRM Point of Royalty Measurement (BLM) SAT Site Acceptance Test TA Technical Authority WLR Water Liquid Ratio WNS Western North Slope DATE: 2/9/16 PAGE 13 OF 17 Attach 2 GMT1 Flow Measurement and Metering Philosophy_Rev1.doc ME$ 6.1 GREATER MOOSES TOOTH I ConocoPhilli S FLOW MEASUREMENT AND METERING PHILOSOPHY I� - THREE PHASE PRODUCTION SEPARA TOR OIL Alaska MEASUREMENT REV. I DATE: 2/9/16 PAGE 14 OF 17 Customary U.S. Oilfield units of measure shall be used. These units are listed below: Table 7 — Units of Measure Liquid Volume bbl (barrel = 42 U.S. gallons) or STB (stock tank barrel) Liquid Volume Other gal (U.S. gallon) Gas Volume ft3 (cubic feet) or scf (standard cubic feet) Pressure psi (pounds per square inch) or inches of water Temperature °F (degree Fahrenheit) Gas Flow Rate MMscfd (million standard cubic feet per day) Sales Oil Flow Rates STB/d (stock tank barrel per day) Water Flow Rate bpd (barrel per day) Chemical Flow Rate gph (gallon per hour) Viscosity cP (centipoise) Vessel and Tank Levels % (percent) Mass Ib (pound) Rotational Speed rpm (revolutions per minute) Current A (ampere) Voltage V (volt) Power HP (horsepower) or kW (kilowatt) Gas Gravity SG (specific gravity) Oil Gravity °API (API gravity) Standard Conditions 60°F and 14.67 psia (pounds per square inch absolute) MEASUREMENT PROJECT ACTIVITIES AND REQUIREMENTS General This document describes the oil metering system that will be installed for the new GMT1 drillsite development. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Rev1.doc 6.2 6.3 ConocoPhillips Alaska GREATER MOOSES TOOTH 1 FLOW MEASUREMENT AND METERING PHILOSOPHY DATE: 2/9/16 — THREE PHASE PRODUCTION SEPARATOR OIL MEASUREMENT PAGE 15 OF 17 REV. 1 Metering station design shall be according to all relevant specifications with respect to vessels, piping, pipe supports, valves, materials, surface protection, insulation, heat tracing, weather protection etc. and the metering stations shall be manufactured such that they are suitable for the climatic conditions at the field location. Design Measurement system design as well as operational and maintenance activities will be based upon state and federal regulatory requirements and agreements as well as the ConocoPhillips standards. This GMT1 Metering Philosophy supports the operating goals, so metering systems must allow for scalable throughput, occasional turndown, minimally disruptive maintenance, and periodic verification as dictated by regulations and commercial agreements. Single point of failure outages that significantly affect throughput or increased measurement uncertainty are to be avoided, and critical devices and equipment must be installed with redundancy. Meter runs shall be installed using practices that reduce or eliminate uncertainty that may occur due to the effects of piping arrangements, and will facilitate maintenance while minimizing requirements for excessive disassembly, associated labor costs and HSE risks. Bypasses around custody transfer/ PRM are generally not allowed. Bypasses built into the design for operational flexibility shall be car sealed closed. For accurate product measurement, it is necessary to provide means of fluid measurement and calculation, as well as determination of fluid quality at appropriate points throughout the process. Pressure and temperature compensation shall be applied to all applicable volumetric measurements. Fluid quality measurement instruments or sampling systems shall be installed for each significant fiscal measurement. Measurement verification dictated by commercial agreements and regulatory requirements may be accomplished in part via application of advanced electronics and systems diagnostics. Communication links to smart instrumentation shall be installed to collect data, maintain and verify devices, support record keeping, report and document failures and malfunctions, and assist with overall reporting and compliance. General Installation Requirements All instruments, including meters and analyzers, shall be located so as to be readily accessible for repair or adjustment from operating level. Maintenance access shall normally be accomplished by mounting of instruments and manifold valves on stands such that they are accessible from grade. Where measurement accuracy or other physical conditions require close—coupled instruments in a location not accessible from grade, an access platform shall be provided. Instruments shall be installed and mounted rigidly and normal to the vertical or horizontal plane and in such a manner that they may be removed without disturbing adjacent equipment, piping or tubing. All instruments, equipment and components shall be suitable for the maximum extreme environmental and climatic conditions in which they are installed. Protective housings or Attach 2 GMT1 Flow Measurement and Metering Phil osophy_Rev1.doc GREATER MOOSES TOOTH I )6"' ConocoPhilli S FLOW MEASUREMENT AND METERING PHILOSOPHY DATE: 2/9/16 — THREE PHASE PROD UCTION SEPA RA TOR OIL Alaska MEASUREMENT PAGE 16 OF 17 REV. I weather—hoods may be required. Instruments and sense lines containing process fluids shall have insulation, heat tracing, and/or seals where process fluids may undergo a change in phase due to exposure to ambient temperatures. All instruments, tubing, piping, fittings, instrument tags, instrument dials, etc., must be protected from physical damage, contamination by dirt, sand, or other foreign material during transport, storage, fabrication, painting, insulation and other assembly and construction activities. Dials, glasses, nameplates, etc. must be free of paint, insulation, protection residue and other defacing. 6.4 Instrument Traceability The intent of instrument traceability is to obtain a permanent record and to verify that the instruments will measure, indicate and operate within tolerances guaranteed by the Supplier in accordance with the Instrument Specification and Data Sheets. Meter station transmitters and indicators shall be factory calibrated whenever possible and calibration sheets provided. All instrumentation with factory calibration will be subjected to functional checking. Shop verification check of instruments that cannot be field -checked shall be witnessed. Instruments shall meet the Supplier's published specifications, unless a prior written agreement has been made. All instruments supplied on package systems shall be calibrated and properly tagged. Calibration sheets for these package instrumentation systems shall be turned over prior to system checkout. 6.5 Measurement System Fabrication and Testing Checks carried out during fabrication at vendor factories or facilities shall ensure that the delivered system will meet design performance targets and that all required documentation is available. The metering system's fabrication shall be ensured to meet the approved design and that all design and fabrication documentation is available. Performance targets shall be verified by calibration/factory acceptance test (FAT), and the tests shall be witnessed by appropriate stakeholders. All performance related documentation such as calibration certificates and verification check reports shall be available for review by stakeholders. 6.6 Commissioning Commissioning activities ensure that performance targets achieved during fabrication are still achievable after equipment has been transported, installed and electrically connected. The performance targets shall be confirmed by instrument verification checks and site acceptance test (SAT) and appropriately witnessed by stakeholders. All installation/commissioning/verification/SAT documentation shall be available and properly retained. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl Aoc GREATER MOOSES TOOTH I 'b DATE: 2/9/16 ConocoPhtll1 S FLOW MEASUREMENT AND METERING PHILOSOPHY - THREE PHASE PRODUCTION SEPARATOR OIL Alaska MEASUREMENT PAGE 17 OF 17 REV. I 6.7 Handover Handover requires close coordination. During this activity, punch list items are resolved and verified. For measurement systems, the Operator shall participate in the handover by reviewing and approving punch list items and ensure any rework is identified for corrective action. 6.8 Maintenance Operator shall ensure that all components of the measurement system are maintained in accordance with regulatory and/or contractual obligations. All instruments, flow computers, samplers, analyzers, and supporting equipment shall have a maintenance frequency for each piece of equipment that is agreeable to partners and regulators as appropriate. Calibration certificates shall be properly retained. 6.9 Test Equipment The calibration of all test equipment shall be checked before being used for any verification activity. If the test equipment is visibly damaged or the calibration certificate is over one year old, the equipment shall be sent to a qualified independent testing laboratory for certification. Test equipment recertification records shall be properly retained. The test instrument calibration check shall be recorded on a label, showing the date and the person or agency performing the check, and the label should be attached to the equipment in such a place that it is easily visible and not easily removed. All calibrations shall be performed using test equipment with accuracies at least one order of magnitude lower than the instrument being calibrated. 6.10 Audit Regular auditing of measurement systems will ensure compliance with regulatory and contractual requirements. The audit shall include checks of the measurement system's performance at current production rates and an assessment of activities required to maintain metering system performance at target levels. After conducting an audit, the audit findings/recommendations shall addressed/implemented within required time scales. The uncertainty calculations shall reflect current production rates and fluid properties. Revised uncertainty calculations shall be analyzed to identify any system modifications that may be required to maintain the target/contractual performance targets. The Operator shall support the auditing of measurement systems by third parties such as regulatory bodies and contractual partners, if required. Attach 2 GMT1 Flow Measurement and Metering Phil osophy_Rev1.doc ConocoPhillips GMT1 Measurement Application AOGCC Hearina May 3, 2016 • ConocoPhillips seeks AOGCC approval • Proposed GMT1 measurement system • 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 • Background /Overview • Metering Application Highlights • Regulations • Economic Analysis Status & Summary • First development in Greater Mooses Tooth Unit • Key to continued NPR -A growth Utilizes Alpine infrastructure & CD5 design work • 11.8 -acre gravel pad • Up to 33 horizontal well MWAG development • Estimated peak NS employment: —700 positions 4May 3, 2016 • Key Permits Received: • CPAI Project Sanction: ' 1St Construction Season: • 2nd Construction Season: • Start Drilling: • First Oil: Jan/Feb 2015 November 2015 4Q2016 - 2Q2017 4Q2017 - 4Q2018 2Q 2018 December 2018 Background /Overview: Land Ownership CRU Working Interest Owners Surface Owners ConocoPhillips (Operator) Kuukpik Anadarko State of Alaska Petro -Hunt (CD3 only) BLM GMTU / GMT1 Working Interest Owners Surface Owners ConocoPhillips (Operator) Kuukpik Anadarko BLM Subsurface ASRC State of Ala BLM Subsurface Owners ASRC BLM r May 3, 2016 r;;;,riF;;;�! • The proposed measurement design has evolved through multiple discussions with stakeholders, including state and federal agencies • The 3-phase production separator and associated metering achieve a high level of hydrocarbon measurement accuracy (2.1% uncertainty in oil stream) within a cost that allows the GMT1 project to remain viable • The GMT1 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 GMT1 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 development in order to minimize project footprint Greater Mooses Tooth Unit (GMT1) ColviIIP Rivar ] ]nit (CRI Il • Oil, Gas and Water are measured at the GMT1 3 -Phase Separator, recombined and sent to Alpine Central Facility (ACF) at CRU for processing • Gas (Lift Gas + Fuel Gas and Miscible Injection Gas) and Injection Water sent to GMT1 from CRU • Gas streams measured at GMT1 • Water measured at the wellhead at GMT1 LEGEND Ane ine (::::) Measurement MI — Miscible Injection gas LG — Lift Gas FG — Fuel Gas Drive Gas to Pigging module oPhase Dynamics Water Line List: Cut meter Orange: Gas ® E3 ® Coriolis Meter Green: OII+Water Orifice Plate Meter Blue: Separated Water Black: Oil+water+gas Magmeter 0 Gas sample station Production to CD5/ ACF *Proposed PA Sea Water Alpine Central Facility (ACF) Lift Gas Common Gas Fuel & Flare Processing Dry Gas Gas Injection Condensate Gas Crude Inlet Enrichment Se arator Oil Stabilizer Enriched Processing Gas Injection Condensate .......................... — — Oil Sales Water Injection 1 � — Alpine Qanni Al ine anu 1 1 NK FN FK j anuq NK Lookout* 'Reference table showing which PA's are associated with each drillsite is available in back-up material 9 May 3, 2016 % P .'s FN 110 • 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 favored alternative to LACT metering is to measure live fluids and convert observed volumes to standard volumes through the application of a Shrinkage Factor (SF) • No processing facility is required • The use of a SF applied to live fluids measurement increases the uncertainty N 2% versus the use of a VCF applied to stable fluids Mass Output Observed Volume 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 • Shrinkage Factor (SF) Matrix • Developed across a range of operating pressures & temperatures (example below) Process Adjustment Matrix with Two Way Linear Interpolation - Oil Shrinkage Factor Temperature Pressure 250 350 400 135 350 Pressure > 150 Temperature v 0.87663 0.84492 0.83209 0.88501 0.85297 0.83990 0.89355 1 0.86090 0.84759 125 0.92176 135 0.93135 145 0.94081 Process Adjustment 0.853 Factor Conoco'Phillips • The proposed measurement system, along with robust operation and maintenance plans enable CPAI to achieve a high measurement certainty • Oil Measurement - Coriolis Meters • Monthly meter verification checks using Smart Meter Verification • Annual calibration at off-site testing facility • Gas Measurement - Differential Pressure Orifice Gas Meters • Continuous DP Diagnostics system • Annual orifice plate and meter tube boroscope inspection • Watercut Analyzer and Secondary Instruments • Quarterly calibrations • Monthly watercut cross verification with proportional sample lab results Oil Sampling Fast -loop flow proportional 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 water content analyses and occasional samples as needed for compositional and pressure, volume and temperature (PVT) analyses • Gas Sampling • Flow through spot sampling stations at each regulatory gas meter • Monthly sample for compositional and BTU analyses • 20 AAC 25.228 Production Measurement Equipment for Custody Transfer Pb) Measured before severance from unit Fabricate, install and maintained in conformance with API MPMS 'v`c) Microprocessor -based totalizer must be equipped with (1) and (2) y/d) If microprocessor used, reports must show... ,%) Fluid samplers must be a probe or slipstream type. f) Functional bypasses may not be connected g Oil meters must be periodically proved; Gas meters periodically calibrated h Provers used for certification... 1 24 hours notice needed before (1) calibration of provers, (2) crude oil sample collection, handling, analysis, (3) oil meter proving, and (4) gas meter calibration j) Upon request, commission will approve variance if equal or improved accuracy k) "relevant parts of API MPMS" means... • Produced oil & gas streams measured prior to leaving GMT1. • Gas stream leaving CRU, returning to GMTU is measured off -lease at GMTU. • Use of shrinkage factors is necessary for live fluids and complies with API Chapter 20.1 as a valid method for allocation metering. • Have proposed for oil meters to use advanced monthly verification, supported by annual meter calibration. • In compliance with gas meter calibration requirements. • CPAI is requesting approval for commission discretion in regards to off - lease measurement (gas measurement at GMTU instead of CRU) and custody transfer metering. • AOGCC Industry Guidance Bulletin 13-002 General Information Y • Description of project• design and roduction rate p, Fluid Analysis temperature and pressure Ownership and Physical location Flow Diagram • Meter prove / calibration frequency Planned date for installation of meter system Will be installed during 2018 and started up in 4Q 2018. Exact installation date not defined at this time. (DAPI Manual of Petroleum Measurement Standards (MPMS) (DMeter Run Details to be supplied once OlFlow Computer available (DInstrument / Meter Calibrations • Other than the items noted above, the remaining details required by Guidance Bulletin 13-002 are not available at this time • Production Facility (PF) analysis showing relative impacts if CPAI were to comply with the AOGCC rules strictly as stated in regulations 150% 100% 50% 0% -50% o � -100% Ji z � -150% -200% -250% -300% -350% Current Value Facility Capital Operating Cost Four Year Delay Revised Value (No PF) (PF) CPAI would not be able to proceed with further investment in the GMT1 project if LACT metering were required. ECONOMIC PREMISES • 10% Discount Rate • 1/1/2016 Present Value Date (Point Forward) • Alaska Department of Revenue Fall 2015 Price Forecast • 100% Working Interest CAPITAL • Incremental facility capital of —$500 MM EXPENSE • Additional operating costs of —$45 M M /year PRODUCTION • Four year project delay; 2022 first production • The GMT1 project is completing detailed engineering and currently engaged in the procurement process that will enable CPAI to order necessary equipment for the project and for metering • Requesting both BLM and AOGCC approvals now for CPAI's measurement concept so project team can finalize measurement design and initiate procurement process for the necessary equipment • Design concept and metering philosophy for GMT1 production • Off -lease measurement for CRU gas flowing to GMT1 Back -Up 2Q Second Quarter • MI Miscible Injection 4Q Fourth Quarter MM Million AAC Alaska Administrative Code • IVIPMS 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 ASRC 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 H2O Water CD2 Reference Alpine, Qannik information for IAP Integrated Activity Plan CD 3 Fiord-Kuparuk (FK), Fiord-Nechelik (FN) Attachment 1G: LACT Lease Automatic Custody Transfer CD4 ACF Simple Nanuq, Nanuq-Kuparuk (NK), Alpine Process Flow LG Lift Gas CD 5 Nanuq-Kuparuk (NK), Alpine Diagram GMT 1 Lookout ATTACHMENT 113: GMT1 CONCEPTUAL PA, WELLS AND LEASES HELD IN CONFIDENTIAL STORAGE Attachment 1C: GMT1 lease ownership, royalty rate, and allocation factor List of Leases for Potential Lookout Participating Area 1'-n #nr AN r.n..c T,.wiM 1 1..:3 Unit Proposed I Tract Serial Number PA Description v�Number Basic Royalty Working Ownership Tract GMTV No. Tobin Number Lookout 2 AA -081743 of Lands T11N-R2E, UM of Acres Ro al Owner Interest Owners Percentage Allocation 953086 Section 13: SE1/4NE1/4, SEI/4, NE114SW1/4, S1/2SW1/4 16.6667% U.S. ConocoPhillips 78.00 TBD Anadarko 320.00 22.00 Total 320.00 100.00 GMTU Lookout 3B AA -092340 T11N-R3E, UM 16.6667% ASRC ConocoPhillips 78.00 TBD 340759 Section 18: SWI/4SE1/4, SW1/4, SW1/4NW1/4 223.50 Total 223.50 Anadarko 22_00 100.00 GMTU Lookout 9A AA -081819 T11N-R2E, UM 16.6667% U.S. ConocoPhillips 78.00 TBD 932554 Section 23: NE1/4NE1/4, S1/2NE1/4, SE114, SE1/4SW1/4 319.50 Total 319.50 Anadarko 22.00 100.00 GMTU Lookout 98 AA -092346 T11N-R2E, UM 16.6667% ASRC ConocoPhillips 78.00 TBD 340760 Section 24: All 640.00 Section 25: All 640.00 Anadarko 22.00 Section 26: E1/2, E1/2W1/2, W1/2SWI/4, SW1/4NW1/4 599.06 100.00 Section 35: E1/2, NE1/4SW1/4, E1/2NW1/4, NW1/4NW1/4 479.25 Section 36: All 640.00 Total 2,998.31 GMTU Lookout 10A AA -081818 T1iN-R3E, UM 16.6667% U.S. 932553 Section 30: W1/2, Wt/2E1/2, E1/2NE1/4, NE1/4SE1/4 565.31 ConocoPhillips 78.00 TBD Section 31: W1/2, W1/2E1/2 453.75 Anadarko 22.00 Total 1,019.06 100.00 GMTU Lookout 108 AA -092345 T11N-R3E, UM 16.6667% ASRC ConocoPhillips 78.00 340761 Section 19: W1/2, W1/2E1/2, SE1/4NE1/4, E1/2SE1/4 562.50 TBD Anadarko 22_00 Total 562.50 100.00 GMTU Lookout 166 AA -092342 T10N-R2E, UM 16.6667% ASRC 340763 Section 1: N1/2, SE1/4, N1/2SW1/4 559.13 ConocoPhillips 78.00 TBD Section 2: E1/2NE1/4, NW1/4NE1/4 119.81 Anadarko 22.00 Total 678.94 100.00 GMTU Lookout 17 AA -081798 T10N-R3E, UM 16.6667% U.S. 932533 Section 6: NW1/4, W1/2NE1/4, N1/2SW1/4, SWI/4SW1/4 341.44 ConocoPhillips 78.00 TBD Anadarko 22.00 Total 341.44 100.00 TOTAL PA ACREAGE 6,463.250 Key: Anadarko - Anadarko E&P Onshore LLC ASRC - Arctic Slope Regional Corporation ConocoPhillips - ConocoPhillips Alaska, Inc. U.S. - United States of America 101-1, ConocoPhillips June 2, 2016 Commissioner Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue Anchorage, AK 99501 RE: Greater Mooses Tooth Unit Measurement Application Follow -Up Responses to May 3, 2016 Hearing Docket Number OTH-16-005 Dear Commissioner Foerster: Brandon Viator Project Integration Manager, GMTU ConocoPhillips Alaska 700 G Street Anchorage, AK 99501-3439 907.263.4653 ConocoPhillips Alaska, Inc. (CPAI), as Unit Operator of the Greater Mooses Tooth Unit (GMTU) and Colville River Unit (CRU), and on behalf of itself and the other working interest owners presents the information in this letter and its attachment to address questions posed by the Commissioners at the May 3, 2016 hearing on GMTU and CRU measurement (Docket Number 0TH -16-005). CPAI would first like to clarify for the Commissioners that we have cast our application as a request for an order under AS 31.05.030(c) and 20 AAC 25.505, which do not require an "equal or better" standard. CPAI strongly believes that our proposed measurement system provides a level of accuracy in standard volume units that could be substantially improved upon only by measurement and conversion to standard volume downstream of full processing facilities, which is cost prohibitive. CPAI would also like to address one of the statements made during the hearing on the need to prove equal or better accuracy variance for Coriolis meters. The regulation on custody transfer measurement, 20 AAC 25.228, does not directly require a particular type of meter or an accuracy standard. Instead, the regulation adopts by reference the 1998 version of the API Manual of Petroleum Measurement Standards (MPMS), which addresses Coriolis meters for allocation metering in Chapter 20.1, but does not address Coriolis meters for custody transfer or LACT metering service. In LACT measurement (stable fluids) service, Coriolis meters do provide equal to or better measurement accuracy when compared to turbine or positive displacement meters. As was described during the hearing, the main element of measurement uncertainty in the system we have proposed — which we believe overall to be a robust and accurate system — comes not from use of the Coriolis meter, but from the conversion of measured volumes to standard volumes for live fluids through the application of a shrinkage factor. Coriolis technology has been proven within the industry, as is evident by API's adoption of Chapter 5.6 in 2002 addressing Coriolis meters for custody transfer. While the AOGCC regulations have not been updated to adopt by reference post -1998 versions of the MPMS, the AOGCC can take note of the industry acceptance of Coriolis meters in liquid hydrocarbon service for custody transfer. Attachment 1 included with this letter covers the non -confidential questions raised by the Commission. Additionally, we plan to meet with AOGCC staff to provide additional confidential economic information to address the Commissioners' request for more detail on the economic rationale underlying our request. CPAI will provide the more detailed information in reliance on the AOGGC's assurance that the information will be held confidential under AS 31.05.035, 20 AAC 25.537 and other applicable law. If you have questions or need additional information, please contact me at 907-263-4653. Sincerely, Brandon Viator Project Integration Manager - Greater Mooses Tooth Unit ConocoPhillips Alaska Attachment 1. GMT1 AOGCC Hearing Follow -Up Responses a. Well test flow rate uncertainty estimate b. Improving proof test WP c. NSFMW 2014 Attachment 1 GMT1 AOGCC Hearing Follow -Up Responses The following information is based on questions raised by the AOGCC Commissioners during the May 3, 2016 hearing on ConocoPhillips Alaska, Inc.'s measurement application for the GMT1 development. Question 1: What is the expected API gravity for GMT1 oil? Answer: 430 Question 2: What is the expected GOR for GMT1 production? Answer: 1,385 scf/stb Question 3: What is the uncertainty value associated with the Colville River Unit (CRU) measurement? Answer: Since bringing the CD5 project online in late October 2015, the CRU uncertainty has a mean allocation factor of 0.99 with P10 and P90 ranges of 0.97 and 1.01, respectively. The median value over this time period is 0.99. Since November 2000, the CRU uncertainty has a mean allocation factor of 1.01 with P10 and P90 ranges of 0.95 to 1.08, respectively. The median value over this time period is 0.99. The following document provides uncertainty calculations for the CRU well test and allocation meters, which applies to all drillsites in CRU. liki Well Test Flow Rate Uncertainty Estimatc Question 4: Can ConocoPhillips provide a summary of the history and considerations for not combining the Greater Mooses Tooth and Colville River Units into one large unit? If CPAI were to combine the units, would it remove the need for an AOGCC variance? Answer: The CRU was approved in 1998 by the State of Alaska (State) and the Arctic Slope Regional Corporation (ASRC). The CRU is comprised primarily of lands owned by the State and ASRC. Regular production from the CRU began in 2000. The Greater Mooses Tooth Unit (GMTU) was approved in 2008 by the Bureau of Land Management (BLM), and is comprised mostly of lands owned by the United States and administered by BLM. GMTU is not yet producing oil and gas on a sustained basis. The oil pools defined and approved by the AOGCC in connection with the CRU do not cover lands within the GMTU. Given the distinctions between the two existing units -- including their different history, land ownership, unit administrators, and regulatory regimes -- it is natural that they would be separate units. Additionally, each unit has been separately established, and attempting to combine the units at this late date, would be exceedingly difficult, if not impossible. The contractual obligations established by the two different unit agreements reflect the specific intentions and requirements of the State, ASRC, and BLM. Reaching alignment between the federal and state requirements could require various concessions that would be very difficult to obtain and could have significant impacts on existing infrastructure. In addition, the restructuring of these two large units into one unit would be time consuming, would present high chance of failure based on regulatory obstacles, would divert focus away from current major development projects, and would have a high manpower cost impact to the operator, other working interest owners, landowners, and regulatory agencies — all costs and impacts that are unnecessary to impose here. While it is theoretically possible that the units could be combined into one very large, diverse unit, CPAI is not aware of any precedent for such a combination. The question of whether combination of the units would remove the need for a variance from 20 AAC 25.228 presumes that a variance is required under present circumstances. As noted in the cover letter, CPAI has not asked for a variance, rather we have cast our application for an order under AS 31.05.030(c) and 20 AAC 25.505 instead, in part to avoid confusion about whether the "equal or better" standard for a variance under 20 AAC 25.228(j) applies. In our view, no variance is necessary because whether a "variance" is needed depends on whether the proposed system' complies with the 1998 version of the API Manual of Petroleum Measurement Standards (MPMS), which is ' To be clear, the system proposed by CPAI is for on -unit (GMTU) measurement using an industry -accepted meter type, but at elevated temperature and pressure, upstream of processing facilities. The key question, in our view, is whether conversion of the metered volume to standard volume using a shrinkage factor is deemed acceptable to the AOGCC. CPAI submits that it should be acceptable because it provides for accurate measurement — indeed, the most accurate level that could reasonably be obtained at GMTU — even though it does not provide a level of accuracy that is equal to or better than converting metered volume to standard volume using a volume correction factor that would apply downstream of processing facilities. adopted by reference in 20 AAC 25.228(a). We acknowledge some uncertainty on this point, however, because the 1998 version of MPMS addresses Coriolis meters only as allocation meters, not as custody transfer meters. If a variance were necessary, combination of units could avoid the need for a variance because in that case AOGCC may deem the GMT1 meter to be an allocation meter that is referenced to the combined unit's LACT meter, which clearly complies with the 1998 MPMS. Note, however, that BLM's position has been that the GMT1 meter must be the sole determination of GMT1 volumes, without any adjustments, so even if the units were hypothetically combined and the Coriolis meter was deemed to be an acceptable allocation meter, the actual measurement system would be no different than the system currently proposed. Comment 5: The commission may request or require 3rd party review and sign -off on Shrinkage Factor matrix to ensure no CPAI bias. Response: CPAI is proposing the following protocol that can later be translated into a documented procedure to ensure no CPAI bias with the Shrinkage Factor matrix: The Shrinkage Factor matrix will be updated as oil composition and/or operational conditions warrant. The matrix will be verified and amended by CPAI based on the following: • Operating pressure is outside of matrix range • Operating temperature is outside of matrix range • Dry oil density deviates by more than 10% from the process simulator conditions. Compositional sample analysis will be triggered by the following: • New production well brought online • Monthly composite samples show a dry oil density change of greater than 10% • Once per year during annual Preventative Maintenance (PM) Following receipt of a compositional analysis and update of the Shrinkage Factor matrix (if required), the new Shrinkage Factor matrix will be reviewed with an independent 3rd party, whom will be given access to both the HYSYS model and historical sampling results to verify that there is no CPAI bias with the matrix. Question 6: Can ConocoPhillips provide more detail on smart meter diagnostics technology? Answer: The following video link provides a high level overview of how MicroMotion Smart Meter Verification (SMV) works to identify potential measurement issues in a Coriolis meter. (https://www.youtube.com/watch?v=DKINaUrckw8) Additionally, the attached MicroMotion white paper titled "Allow Smart Meter Verification to Reduce your Proving and Proof -Test Costs" describes how the SMV technology provides robust in-situ verification of Coriolis performance. r Improving -Proof -Te st-W P-001540. p d f The gas orifice meter advanced DP Diagnostic system was developed in a coordinated effort with Swinton Technology, headquartered in the United Kingdom. The linked Swinton Technology Prognosis video provides a high level overview of how the jointly developed diagnostic application works. (https://www.youtube.com/watch?v=Y2ZSzSye2cw) We have also provided a white paper presented at the North Sea Flow Measurement Workshop in October 2014 that provides additional details of the advanced DP meter diagnostics technology. Ei NSFMW_2014.pdf Discussion 7: A question was raised by the Commissioners as to whether having oil in water and oil in gas analyses on the water and gas legs, respectively, is a prudent requirement or not. Response: CPAI would like to clarify some of the responses that were given during the hearing regarding oil in gas and oil in water measurement. Neither AOGCC regulations nor any governing industry standard require any particular approach or result. The approach proposed by CPAI is based on a system that is expected to separate oil and water to the extent that we are reasonably confident any carryover would be minimal and not require additional measurement. However, CPAI is prepared to take additional steps to address any potential AOGCC concerns. Liquid in Water Stream The production separator vessel is specified to produce a water outlet with less than 0.1% oil in water and currently includes a nucleonic level measurement device that will detect and control the oil -water interface in the vessel, further minimizing any potential oil leaving with the water stream. CPAI does not anticipate any significant amounts of oil in the water stream, but if measurement of oil content in the water stream is requested by AOGCC, we propose the following alternative water measurement technology compared to what was discussed during the hearing. Rather than include an oil -in -water analyzer with the previously proposed magnetic flowmeter, CPAI would propose installing a Coriolis flow meter on the water outlet of the production separator. This would allow the Operator to monitor changes in density that would indicate potential separation issues and oil in the water outlet. Additionally, CPAI would propose the addition of a spot sampling quill on the water outlet for any necessary sampling and analysis of the production separator water outlet stream. Liquid in Gas Stream For potential liquid carryover in the gas stream, the production separator vessel is being specified for less than 1 gallon of liquid carryover per MMSCF of gas. The DP Diagnostic system on the gas orifice meters will detect and alarm on liquid carryover. Operator alarms on density changes in the gas outlet would trigger operation or maintenance corrective actions as necessary. Anchorage Office • 3900 C Street, Suite 801 • Anchorage, Alaska 99503-5963 • 907.339.6000 • FAX 907.339.6028 • 1.800.770.2772 3 9® arctic 31 _ p@ regional corporation November 30, 2016 RECEIVED Commissioners Foerster, Seamount and French 01. Alaska Oil and Gas Conservation Commission DEC 0 1 2016 333 W. 7th Avenue Anchorage, Alaska 99501 AOGCC RE: Docket OTH-16-025 ASRC Comments to AOGCC Regarding the Allocation Factor at Greater Moose's Tooth #1 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 #1 (GMT1), the first drillsite within the Greater Mooses Tooth Unit (GMTV), located in the National Petroleum Reserve - Alaska (NPRA). ASRC is the majority mineral owner of the proposed Lookout Participating Area, the initial development from the GMT1 drillsite, and therefore has a significant economic interest in the GMT1 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 GMT1. ASRC's reasons to justify approval for the allocation factor are as follows: ASRC has been actively involved in the technical discussions to meet the BLM metering requirements for GMT1 and we feel 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). Fluids produced at GMT1 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 GMT1 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 GMT1. With recombination of GMT1 fluids prior to reaching the ACF, the GMT1 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 o COP will continuously meter the GMT1 production with a three phase production separator with the oil being measured by two Micro Motion Elite Coriolis Flow Meter utilizing Smart Meter Verification to permit automated verification of the meter accuracy. The flow measurements will be corrected to standard conditions using temperature and pressure correlations. This technology allows for +/- 2.1% uncertainty. ■ Monthly proportional oil samples will be taken and analyzed and compared against measurement parameters to insure accuracy. ■ The master meter requirement in the BLM approval further improves the reliability of the oil metered at GMT1. • 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 has no objection to the proposal for off -unit measurement of CRU gas at GMTU. • 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 GMT1 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 GMT1. The State of Alaska currently receives royalty from production from the CRU and is entitled to receive 50% of the federal royalty from GMT1. ASRC feels that COP has a metering design that protects all royalty interests in both units. Thank you for your time and attention. Very 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 In Reply Refer To: 2361 (930) United States Department of the Interior BUREAU OF LAND MANAGEMENT Alaska State Office 222 West Seventh Avenue, #13 Anchorage, Alaska 99513-7504 http://www.bim.p_,ov NOV 25 2016 Cathy P. Foerster Chair, Commissioner Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Dear Commissioner Foerster: RECEIVED NOV 282016 During the hearing on November 17, 2016, the Alaska Oil and Gas Conservation Commission requested a letter from the Bureau of Land Management (BLM) further supporting why the production allocation factor of 1.0 should be used for future development of Greater Mooses Tooth (GMT) #1. The BLM supports the usage of this allocation factor of 1.0, as it meets the federal requirements in 43 CFR § 3162.7-2, as well as the requirements under BLM Onshore Oil and Gas Order No. 4 (43 CFR 3174). Based on information provided by ConocoPhillips Alaska, it was determined that installing a Lease Automatic Custody Transfer (LACT) meter for each participating area in the GMT Unit would render the project uneconomic. As such, a sundry was approved by the BLM to allow the use of a three-phase separator with Coriolis meters on the oil leg for continuous measurement of fluids. The accuracy of the Coriolis meter is +/- 0.5% and will be verified according to 43 CFR 3174.11. Coriolis meters are approved by the BLM as they meet accuracy requirements and do not have "statistically significant" bias to read high or low in error. Further, a shrinkage factor will be applied to the oil leaving the GMT Unit. If further discussion is warranted, you may contact Wayne Svejnoha from my staff at wsvejnoh@blm.gov or (907) 271-4407. Sincerely, / Bud C. Cribley .tj,/ State Director 1 ALASKA OIL AND GAS CONSERVATION COMMISSION 2 3 Before Commissioners: Cathy Foerster, Chair 4 Daniel T. Seamount 5 Hollis French 6 7 In the Matter of the Application of ) 8 ConocoPhillips Alaska, Inc., for a Meter ) 9 Allocation Factor of One to be Applied at ) 10 the Fiscal Allocation Meter to be Used at ) 11 Greater Mooses Tooth Number 1 Development ) 12 to Allocate Production between the Greater ) 13 Mooses Tooth and the Colville River Units. ) 14 ) 15 Docket No.: OTH 16-025 16 17 ALASKA OIL and GAS CONSERVATION COMMISSION 18 Anchorage, Alaska 19 20 PUBLIC HEARING 21 November 17, 2016 22 9:00 o'clock a.m. 23 24 BEFORE: Daniel T. Seamount 25 Hollis French 1 TABLE OF CONTENTS 2 Opening remarks by Commissioner Seamount 03 3 Remarks by Mr. Viator 4 Remarks by Ms. Larsen 2 08 12 1 P R O C E E D I N G S 2 (On record - 9:07 a.m.) 3 COMMISSIONER SEAMOUNT: I'd like to call this 4 hearing to order. Today is November 17, 2016, it is 5 9:07 in the morning. This hearing is being held at the 6 Alaska Oil and Gas Conservation Commission, known as 7 the AOGCC. The AOGCC is located at 333 West Seventh 8 Avenue, Anchorage, Alaska. My name is Dan Seamount, 9 I'm one of the Commissioners for the AOGCC and to my 10 right is Hollis French, another Commissioner for the 11 AOGCC. It takes two Commissioners to make a quorum to 12 have enough to make a decision in this matter, so we 13 will be able to make a decision eventually in this 14 matter. 15 This hearing is regarding docket number OTH 16- 16 025, ConocoPhillips Alaska, Incorporated, who has 17 requested a meter allocation factor of one to be 18 applied at the fiscal allocation meter to be used at 19 Greater Mooses Tooth Number 1 development to allocate 20 production between the Greater Mooses Tooth and the 21 Colville River units. 22 On October 31st, 2016 the Department of Revenue 23 requested that the AOGCC hold this hearing today. The 24 AOGCC has determined that the potentially affected 25 landowners should be provided the opportunity to weigh 3 1 in on this request. 2 Computer Matrix will be recording the 3 proceedings, you can get a copy of the transcript from 4 Computer Matrix Reporting. 5 DOR has also requested that the comment period 6 be extended to allow time to review and understand 7 comments made at the hearing today. We will discuss 8 this request at the end of the hearing. 9 Also in an email that the AOGCC received on 10 November 16th, 2016, Bud Cribley, the State Director 11 for the U.S. Bureau of Land Management said that BLM 12 supports the allocation factor of one. 13 We also just received an email from Mr. Ken 14 Alper of Alaska Department of Revenue on the 16th 15 regarding tax implications and shrinkage. And in the 16 email he stated that John would have more to say about 17 this today. I assume he's talking about John Larsen, 18 is that true? 19 MR. LARSEN: I'm here. 20 COMMISSIONER SEAMOUNT: And you plan to 21 testify; is that correct? 22 MR. LARSEN: Yes. 23 COMMISSIONER SEAMOUNT: Okay. Good. Good. 24 Then you can explain the email to me because I just 25 read it or perused it. E 1 Let's see, who else do we have to -- it looks 2 like Brandon Viator of ConocoPhillips plans to testify. 3 So I only see two people on the list who plan to 4 testify. Is there anybody else that plans to testify 5 today? As I've stated we are going to extend the 6 comment period so testimony can be in writing and 7 doesn't have to be today. 8 The Commissioners may have questions during the 9 testimony. After the testimony of the two witnesses we 10 will also take a recess to consult with staff to 11 determine whether additional information or clarifying 12 questions are necessary. If a member of the audience 13 has a question that he or she feels should be asked 14 please submit the question to Jody Colombie or Samantha 15 Carlisle who are raising their hand and are way in the 16 back by the big map on the wall. They will provide the 17 question to the Commissioners and if we feel that 18 asking the question will assist us in making our 19 determinations we will ask it. 20 For those testifying please keep in mind that 21 you must speak into the microphone so that those in the 22 audience and the court reporter can hear your 23 testimony. 24 Now if you're going to use slides please 25 reference your slides before you discuss them as far as E 1 page number. If there's no page number on it, 2 reference the slides by their titles. 3 Additionally the testimony may not take the 4 form of cross examination. As I said before that Jody 5 or Samantha will take the questions and we'll decide 6 whether the questions are relevant to the issue at 7 hand. 8 So before we start, Commissioner French, do you 9 have anything to add? 10 COMMISSIONER FRENCH: No, but thank you. 11 COMMISSIONER SEAMOUNT: Okay. Why don't we 12 start. Who should testify first, ConocoPhillips or 13 Department of Revenue or does it matter? Well, it 14 looks like ConocoPhillips got here first so let's hear 15 what ConocoPhillips has to say. 16 I guess I better swear you in. In fact, both 17 people who are going to testify please raise your right 18 hand. 19 (Oath administered) 20 MR. VIATOR: Yes. 21 MR. LARSEN: Yes. 22 COMMISSIONER SEAMOUNT: And both testifiers 23 have said they did. 24 So does the ConocoPhillips person want to be 25 considered an expert witness? on 1 MR. VIATOR: Yes. 2 COMMISSIONER SEAMOUNT: Okay. If that's the 3 fact, please state your name, your qualifications and 4 how you would like to be considered, what kind of 5 expert testifier are you -- what you would like to be 6 the expert -- what practice you would like to be the 7 expert in. 8 MR. VIATOR: My name is Brandon Viator and I 9 would like to be recognized as an expert in oil and gas 10 developments. I've been with ConocoPhillips for 15 11 years, I have a degree in chemical engineering from 12 Texas A&M University. I've worked in a number of oil 13 and gas development projects over the last 10 years 14 both domestic and international, serving in roles as 15 project manager, project engineer, project integration 16 manager and my current role is the project integration 17 manager for the Greater Mooses Tooth unit. 18 COMMISSIONER SEAMOUNT: Thank you, Mr. Viator. 19 Commissioner Hollis, do you have any questions or 20 comments? 21 COMMISSIONER FRENCH: And the area of expertise 22 you want to be -- the area of expertise you're asking 23 to be granted expert status in is exactly oil and gas 24 development, anything related to flow measurement? 25 MR. VIATOR: Yes. 1 COMMISSIONER FRENCH: That's fine. 2 COMMISSIONER SEAMOUNT: Do you have any 3 objections? 4 COMMISSIONER FRENCH: No. 5 COMMISSIONER SEAMOUNT: You're in luck today, 6 Mr. Viator, because our other Commissioner, Cathy 7 Foerster, went to UT. And I have no prob -- no 8 questions and other than that no comments. And I will 9 -- we will consider you as an expert witness in oil and 10 gas development. So please proceed. 11 BRANDON VIATOR 12 previously sworn, called as a witness on behalf of 13 ConocoPhillips Alaska, Inc., stated as follows on: 14 DIRECT EXAMINATION 15 MR. VIATOR: Thank you. So thank you for the 16 opportunity to speak this morning. I just wanted to 17 point out that up until yesterday we weren't expected 18 or anticipating to provide testimony, but we were asked 19 by the AOGCC to give some brief discussion on why a 20 fixed meter factor was chosen. 21 So prior to submitting our application to the 22 AOGCC ConocoPhillips met with each of the mineral right 23 owners associated with the Colville River unit and the 24 Greater Mooses Tooth unit. Those owners include the 25 Arctic Slope Regional Corporation, the Alaska t 1 Department of Natural Resources and the Bureau of Land 2 Management. The measurement application that we 3 submitted for regulatory approval evolved through 4 multiple discussions with various stakeholders and is 5 technically reasonable -- a technically reasonable 6 measurement system. The BLM stated use of an 7 allocation factor of one would meet their regulatory 8 requirements on the measurement system which we then 9 built into our applications. 10 During our meetings with the mineral right 11 owners we reviewed our proposed metering system and the 12 allocation factor requirements. We are not aware of 13 any objections from any of the mineral right owners or 14 other stakeholders regarding our proposed system or the 15 allocation factor. 16 And that's all the testimony that we had 17 planned to submit today so we thank you. 18 COMMISSIONER SEAMOUNT: Commissioner Hollis, do 19 you have any questions? 20 COMMISSIONER FRENCH: Is it a question or is it 21 a statement. I guess I'm trying to think if I have a 22 question for you. Have you used these Coriolis meters 23 in other installations that you've supervised or you've 24 worked on? 25 M 1 MR. VIATOR: Me personally, no. 2 COMMISSIONER FRENCH: Right. Right. 3 MR. VIATOR: No. 4 COMMISSIONER FRENCH: Right. That's my only 5 question. Thank you. 6 COMMISSIONER SEAMOUNT: Mr. Viator, what's the 7 range in error of using this type of meter or can you 8 tell, I mean, is it plus or minus? 9 MR. VIATOR: The meters themselves, I believe 10 we discussed this in the original hearing. So we 11 weren't really planning to discuss, you know, detailed 12 technical stuff so we didn't bring our technical 13 experts with us today and I don't have the exact 14 numbers so I don't want to speculate on what it was. 15 COMMISSIONER SEAMOUNT: This comment period, is 16 it possible that we could get that information during 17 the comment period. 18 MR. VIATOR: Certainly. 19 COMMISSIONER SEAMOUNT: Okay. I had one other 20 question, but I'm going to wait until we hear from 21 Department of Revenue. But do you have a question, 22 Commissioner Hollis? 23 COMMISSIONER FRENCH: I've got an easier 24 question than that. what do you expect the flow rate 25 to be out of the Greater Mooses Tooth unit? 10 1 MR. VIATOR: So the -- you know, it varies over 2 time, but the peak, I want to say it's 20 to 24,000 3 barrels a day. 4 COMMISSIONER FRENCH: Thank you. And I guess 5 I'll just say, you know, something that we discussed 6 yesterday as we were getting ready for the hearing was 7 the -- you know, not this unit because this -- I think 8 everybody sees that this is, you know, it's too small a 9 development to demand a LACI metering system. So, you 10 know, we all want to see this unit go forward and this 11 seems to make sense, but as we do need to push further 12 west in the NPRA, you know, you can see where we could 13 string together, you know, four or five more of these 14 10 to 20,000 barrel a day units and none of them 15 standing alone can justify a, you know, full blown 16 three phase separation with a LACT meter at the 17 outflow. And yet, you know, in the aggregate it 18 obviously would justify that. So that's -- I guess 19 that's at least one of the concerns I have and I think 20 it's shared here in the building, you know, how far out 21 do we go before we say that's too far. This is -- you 22 know, this is not that case, but you can see that 23 potentially coming. 24 Just a comment. Thanks. 25 COMMISSIONER SEAMOUNT: Okay. Let's hear from 11 1 our next testifier. Would you like to be considered an 2 expert witness? 3 MR. LARSEN: No, sir. 4 COMMISSIONER SEAMOUNT: Okay. Please state 5 your name and who you work for and I guess you could 6 say something about title, qualifications, whatever you 7 do. 8 JOHN LARSEN 9 previously sworn, called as a witness on behalf of 10 Alaska Department of Revenue stated as follows on: 11 DIRECT EXAMINATION 12 MR. LARSEN: Sure. First I want to thank the 13 AOGCC for granting DOR's request to hold the hearing 14 today. My name is John Larsen, I'm an audit master 15 with the Department of Revenue. I'm a 1985 graduate of 16 the University of Alaska Anchorage. I spent 18 years 17 as an auditor with the Department of Natural Resources 18 and I've been with the Department of Revenue since 19 2007. 20 Next as I said I'm certainly not an expert in 21 these matters and I'd like to clarify that DOR's 22 request to hold the public hearing was made not in 23 order to provide any public testimony on metering 24 because that's not the function of the Department of 25 Revenue and the Department does not have this expertise 12 1 in-house, but rather to gain a better understanding of 2 any fiscal impact to the state as a sovereign as well 3 as any potential implications for the DOR with respect 4 to tax allocations with respect to each of the 5 respective units. As the Commission may or may not be 6 aware production from the Greater Mooses Tooth appears 7 to be eligible to receive the benefit of the gross 8 value reduction in the reporting and payment of 9 production tax liabilities. The GVR allows that 10 qualifying production may receive the benefit of a 11 reduction in the gross value at the point of production 12 of 20 percent depending on the lease and royalty terms 13 whereas production from the Colville River unit will 14 not. While the DOR as I'm sure the entire state is 15 encouraged by the prospects of new and continuing 16 developments from Alaska North Slope, it is also the 17 responsibility of the Department to ensure that the 18 state and its citizens receive the full amount of tax 19 revenues to which the state is entitled especially in 20 these challenging fiscal environments that we are all 21 operating within. 22 Therefore the Department requested this hearing 23 as an opportunity to perhaps gather information on 24 volumes, other additional PAs or expansions that may 25 occur within the unit to better understand the unique 13 1 aspects of the proposed metering and perhaps also to 2 help inform the Department in the identification of any 3 specific issues that may be pertinent and of relevance 4 to the Department in its role as tax collector for the 5 sovereign. 6 The requested meter allocation factor of 1.0 7 means essentially that there are not any fiscal impacts 8 to the Greater Mooses Tooth for shrinkage in the 9 transportation and processing of fluids from the GMT 10 and that all of these impacts will be attributed to 11 production from the Colville River unit. 12 That's all I have for this morning. I 13 appreciate the opportunity to appear before you here 14 today. 15 COMMISSIONER SEAMOUNT: Thank you, Mr. Larsen. 16 Commissioner Hollis, do you have any questions? 17 COMMISSIONER FRENCH: I guess my concern or at 18 least I have a concern outside of the production tax 19 side on the royalty side. It strikes me that that's 20 just as likely a place where the state could receive 21 either more or less depending on how that balance is 22 struck, depending on how accurate the Coriolis meter 23 is. And I don't know what the -- what the royalty 24 shares are for the state at, I'll call it Alpine and 25 versus the Greater Mooses Tooth and do you know? 14 1 MR. LARSEN: No, sir, I cannot tell you what 2 those royalty percentages are here today. Would -- if 3 you would like I could probably try and find that 4 information for you. 5 COMMISSIONER FRENCH: I would. Yeah, I'd be 6 interested. 7 MR. LARSEN: Okay. 8 COMMISSIONER FRENCH: Yeah. 9 MR. LARSEN: All right. 10 COMMISSIONER FRENCH: That's my only question. 11 Thank you, Commissioner. 12 MR. LARSEN: And just to clarify that's the 13 royalty rates in both the Greater Mooses Tooth and 14 Alpine? 15 COMMISSIONER FRENCH: Right. 16 MR. LARSEN: Okay. 17 COMMISSIONER FRENCH: Right. 18 MR. LARSEN: Yes, sir. All right. Thanks. 19 COMMISSIONER FRENCH: If the state -- I mean, 20 if the state owns the exact same royalty someone's 21 taking a hit. 22 MR. LARSEN: Well, and maybe -- I don't know if 23 I can anticipate the question that maybe they're seeing 24 there. The Greater Mooses Tooth is in the NPRA and so 25 those will be federal leases at the federal royalty 15 1 rate. The state does receive..... 2 COMMISSIONER FRENCH: We share..... 3 MR. LARSEN: .....a share of the royalties..... 4 COMMISSIONER FRENCH: Right. 5 MR. LARSEN: .....but I will confirm when I 6 send in the royalty rates, but I do not believe there 7 are any state leases or state royalty within the 8 Greater Mooses Tooth unit itself, that they will all 9 either exist within the federal leases or ASRC. 10 COMMISSIONER FRENCH: So if -- just for the 11 purposes of discussion, if we're getting half of the 20 12 percent federal royalty out of NPRA that's 10..... 13 MR. LARSEN: Yes, sir. 14 COMMISSIONER FRENCH: .....versus the normal 15 one-eighth I'm going to assume we get out of Alpine? 16 MR. LARSEN: Let me check on the Alpine to see 17 if that is..... 18 COMMISSIONER FRENCH: Okay. 19 MR. LARSEN: .....12 and a half percent. 20 COMMISSIONER FRENCH: Okay. 21 MR. LARSEN: Uh-huh. 22 COMMISSIONER FRENCH: Okay. Fair enough. I 23 see quizzical looks out there so I -- we're all a 24 little puzzled and we'll get the answer, yeah. Great. 25 16 1 MR. LARSEN: That's right, I..... 2 COMMISSIONER FRENCH: There's no one number. 3 MR. LARSEN: .....there's not one number..... 4 COMMISSIONER FRENCH: Okay. 5 MR. LARSEN: .....there's a mix of leases..... 6 COMMISSIONER FRENCH: Okay. 7 MR. LARSEN: .....so we'll give you kind of the 8 blended rate there. And it will depend on 9 production..... 10 COMMISSIONER FRENCH: Sure. 11 MR. LARSEN: .....from each of those 12 leases..... 13 COMMISSIONER FRENCH: Sure. 14 MR. LARSEN: .....of how they're impacted. 15 COMMISSIONER FRENCH: Thank you. 16 MR. LARSEN: Yes, sir. 17 COMMISSIONER FRENCH: But I guess the greater 18 point is that the state's looked at this, you know the 19 Tax Division's looked at this, and the Department of 20 Revenue and the Tax Division are satisfied that this is 21 a good idea. 22 MR. LARSEN: We think the Greater Mooses Tooth 23 is a -- very encouraging as I said. I can certainly 24 understand why the BLM supports a factor of 1.0. 25 Essentially there's no shrinkage factor attributed to 17 1 any of the BLM royalties of which like -- as you 2 indicated the state would receive a share of those, but 3 it's a smaller share of that. 4 COMMISSIONER FRENCH: But to the larger 5 question is the state thinks this is a good idea? 6 MR. LARSEN: Yes, the state supports the 7 Greater Mooses Tooth development. 8 COMMISSIONER FRENCH: The state thinks that 9 it's a good idea to apply a factor of 1.0 to the 10 Coriolis meter? 11 MR. LARSEN: As I said I am not the metering 12 expert. 13 COMMISSIONER FRENCH: Okay. I'm not going to 14 make you say it so if you don't want to say it that's 15 fine. Thank you. 16 MR. LARSEN: Uh-huh. 17 COMMISSIONER FRENCH: I get it. 18 COMMISSIONER SEAMOUNT: Okay. Mr. Larsen, I 19 understand that DOR has requested that the comment 20 period be extended to allow time to review and I assume 21 that the other parties involved would like to provide 22 written comments. Right now it looks like it's 23 ConocoPhillips, ASRC, BLM, Department of Natural 24 Resources, Department of Revenue, did I miss anybody, 25 are all those institutes going to provide comments? 1 I see heads nodding. 2 MR. LARSEN: Yes, sir, we will. The Department 3 of Revenue will provide comments. 4 COMMISSIONER SEAMOUNT: It looks like everybody 5 I mentioned has nodded their head yes. How much time 6 would we need -- well, actually before we do that why 7 don't we take a recess and see if our staff has any 8 additional questions or comments to make. And so with 9 that we're going to go off the record at 9:29 and we 10 will be back in 15 minutes at 9:45. 11 (Off record) 12 (On record) 13 COMMISSIONER SEAMOUNT: Okay. This hearing is 14 back in session at 8:45. Commissioner Hollis, do you 15 have any questions or comments? 16 COMMISSIONER FRENCH: After consulting with 17 staff we have a couple questions for you and we'd like 18 you to follow-up and let us know. First, is the 19 metering system at the Greater Mooses Tooth, the 20 Coriolis meter, is that similar to the allocation 21 meters currently in use at the Colville unit. That's 22 question one, are they similar systems. Two, what the 23 historical range of meter factors of the allocation 24 meters at Colville. Just so -- that'll give us some 25 idea of what the range of meter factors is. And the 19 1 third question, this is not directly related, but it's 2 just a matter of curiosity is what will be the leak 3 detection system for the Greater Mooses Tooth pipe line 4 before it ties in with Alpine or CD5. 5 Those are my only questions. 6 COMMISSIONER SEAMOUNT: Okay. Those are three 7 questions out there. I guess our -- part of our 8 mission is to protect the public's interest in oil and 9 gas development and I assume that the Department of 10 Revenue and Department of Natural Resources have the 11 same -- and of course the BLM have the same -- the same 12 issue, what they want to do. My question which I would 13 like answered and I'm proposing that we get these 14 questions, Hollis' question -- Senator French -- 15 Commissioner French's questions answered by the end of 16 work day Monday, November 28th. Is that -- do all 17 parties agree that that's a reasonable date? And what 18 we would like to know, I mean, the simple question to 19 answer is why is everyone in agreement with an 20 allocation factor of one and we would like to see some 21 technology applied to the answer. 22 Is that understood, Mr. Cribley? Okay. And 23 Ms. Templeton? 24 MS. TEMPLETON: Yes. 25 COMMISSIONER SEAMOUNT: Okay. Do you have 20 1 anything to add, Commissioner Hollis..... 2 COMMISSIONER FRENCH: No, thank you. 3 COMMISSIONER SEAMOUNT: .....Commissioner 4 French? Okay. We will adjourn this meeting and wait 5 for your replies on close of business, Monday, November 6 28th. 7 And this hearing is adjourned for now. 8 (Hearing adjourned 9:53 a.m.) 9 (END OF REQUESTED PORTION) 21 1 TRANSCRIBER'S CERTIFICATE 2 I, Salena A. Hile, hereby certify that the 3 foregoing pages numbered 02 through 22 are a true, 4 accurate, and complete transcript of proceedings in re: 5 Docket No.: OTH 16-025 public hearing, transcribed 6 under my direction from a copy of an electronic sound 7 recording to the best of our knowledge and ability. 8 9 Date Salena A. Hile, Transcriber 10 22 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Docket No. OTH 16-025 ConocoPhillips Alaska, Inc. November 17, 2016 NAME AFFILIATION Testify (yes or no) V e �o N o LT Gc`1 o Z -.r r S 4e �-�. ,,Q y A,VtA+JD � S F.S5 s� cul s 1= L.(�t c�Sk l3zwvt N ISIN Mmts+-N(i /A DNrZ- � Ghr c L ly To: Commissioners of the AOGCC First, I would like to thank the AOGCC for granting DOR's request to hold the public hearing here today. Second, I would like to clarify that the DOR's request to hold the public hearing was made, not in order to provide any public testimony on metering, because that is not the function of the DOR and the department does not have this metering expertise in house, but rather to gain a better understanding of any fiscal impacts to the State as sovereign, as well as any potential implications for the DOR with respect to tax collections from each of the respective units. As the Commission may or may not be aware, production from the GMT appears to be eligible to receive the benefit of the `gross value reduction' in the reporting and payment of any production tax liabilities. The GVR allows that qualifying production may receive the benefit of a reduction in the gross value at the point of production of 20--W% depending on the lease and royalty terms. Whereas, production from the Colville River Unit, will not. While the DOR, as I'm sure the entire State, is encouraged by the prospects of new and continuing developments from Alaska's North Slope, it is also the responsibility of the department to ensure that the State and its citizens receive the full amount of tax revenues to which the State is entitled, especially in these challenging fiscal environments that we are all operating within. Therefore, the DOR requested the hearing as an opportunity to perhaps gather information on volumes, other additional PAs or expansions that may occur within the unit, to better understand the unique aspects of the proposed metering, and perhaps also, to help inform the department in the identification of any specific issues that may be pertinent and of relevance to the department in its role as tax collector for the sovereign. STATE OF ALASKA ADVERTISING ORDER NOTICE TO PUBLISHER SUBMIT INVOICE SHOWING ADVERTISING ORDER NO., CERTIFIED AFFIDAVIT OF PUBLICATION WITH ATIACHED COPY OFADVERTISMENT. ADVERTISING ORDER NUMBER AO-17-011 FROM: Alaska Oil and Gas Conservation Commission AGENCY CONTACT: Jody Colombie/Samantha Carlisle DATE OF A.O. 10/12/16 AGENCY PHONE: 1(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: Alaska Dispatch News SPECIAL INSTRUCTIONS: PO Box 149001 Anchorage, Alaska 99514 TYPE OF ADVERTISEMENT: :'`';'LEGAL DISPLAY CLASSIFIED ; OTHER (Specify below) DESCRIPTION PRICE Docket No Other-16-025 Initials of who prepared AO: Alaska Non -Taxable 92-600185 sgprylyT uvvocE sTlow�lvG ADvFgxSRv: ':ORDER NO,,; CERTIFIED AFFIDAVIT OF_:; - PUBLICATION'WITH; .T.TACHED COTYOE AiiVERTISNIE vT TO . Department of Administration Division of AOGCC 333 West 7th AvengeTOtal Anchorage, Alaska 99501 Page 1 of 1 Of All Pa,es $ REF Type Number Amount Date Comments I PvN ADN89311 2 Ao AO-17-011 3 4 FIN AMOUNT SY Appr Unit PGM LGR Object FY DIST LIQ 1 17 021147717 3046 17 2 3 S Purchas' g' u or ty e: itl . Purchasing Authority's Signature Telephone Number 1. .O.# a, n n name must appear on all invoices and documents relating to this purchase. 2. h state is register for tax free transactions under Chapter 32, IRS code. Registration number 92-73-0006 K. Items are for the exclusive use of the state and not for res llISTRIBVTION .: Dlvislon Fiscal/OrignalOComptes ::.Publisher (faxei3), Dlvtson Fiscal; ReceJ�^ing Form: 02-901 Revised: 10/12/2016 Notice of Public Hearing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Re: Docket No. OTH 16-25 ConocoPhillips Alaska, Inc. (CPAI) has requested a meter allocation factor of 1.0 be applied to the fiscal allocation meter to be used at the Greater Moose's Tooth 1 development to allocate production between the Greater Moose's Tooth and Colville River Units. The Alaska Oil and Gas Conservation Commission (AOGCC) has determined that the potentially affected landowners should be provided the opportunity to weigh in on this request. The non -confidential portions of CPAI's application may be reviewed at the offices of the AOGCC, 333 West 7th Avenue, Anchorage, Alaska, or a copy of the non -confidential portions may be obtained by phoning the AOGCC at (907) 793-1221. The AOGCC has tentatively scheduled a public hearing on this application for November 17, 2016 at 9:00 a.m. at 333 West 7th 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 October 31, 2016. 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 279-1433 after November 4, 2016. In addition, written comments regarding this application may be submitted to the AOGCC at 333 West 7th Avenue, Anchorage, Alaska 99501. Comments must be received no later than 4:30 p.m. on November 14, 2016, except that, if a hearing is held, comments must be received no later than the conclusion of the November 17, 2016 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 November 12, 2016. Cathy . Foerster Chair, Commissioner 270227 RECEIVED 0001394336 $199.22 OCT 19 2016 AFFIDAVIT OF PUBLICATION AOGCC STATE OF ALASKA THIRD JUDICIAL DISTRICT Emma Dunlap being first duly sworn on oath deposes and says that he/she is a representative of the Notice of OF AL Hearing Y P STATE OF ALASKA Alaska Dispatch News, a daily newspaper. ALASKA OIL AND GAS CONSERVATION COMMISSION That said newspaper has been approved Re: Docket No. OTH 16-25 ConocoPhillips Alaska, Inc. (CPAI has by the Third Judicial Court, Anchorage, requested a meter allocation factor of 1.0 be applied t' the fiscal allocation meter to be used at the Greater Moose's Tooth 1 Alaska, and it now and has been published development to allocate production between the Greater Moose's Tooth and Colville River units. The Alaska oil and Gas Conservation in the English language continually as a Commission (AOGCC) has determined that the poweighl . affected daily newspaper in Anchorage, Alaska, and landowners should be provided the ns Ration may be Y9 request. The non -confidential portions of CPAY's app it is now and during all said time was reviewed at the offices of the AOGCC nfide 333 West 7th Avenue, Anchorage, g Alaska, or a copy of the non -confidential portions may be obtained by printed in an office maintained at the phoning the AOGCC at (907) 793-1221. aforesaid place of publication of said The AOGCC has tentatively scheduled a public hearing on this application for November 17 2016 at 9:00 a.m. at 333 West. 7th newspaper. That the annexed is a copy of Avenue, Anchorage, Alaska 49501. To request that the tentatively an advertisement as it was published in ao�cc n h earithan 4:30Ip.m. on Octobep 31S 2016 t be filed with the regular issues (and not in supplemental y If a request for a hearing is not time) filed, the AOGCC may consider form) of said newspaper on the issuance of an order without a hearing. To learn if the AOGCC will hold the hearing, call 279-1433 after November 4, 201p6. y submitted to thettAOGCC at 333 regarding gAvenue pAnchorage, Alaska October 14, 2016 0 99501. Comments must be received no g$later than 4:3 p.m. o November received no later than theaconclusionriof is held, 2016 and that such newspaper was regularly hearing. distributed to its subscribers during all of If because attenidathe eanncgiacontacctthedAOGCC at (907) needed 79 1433 said period. That the full amount of the fee no later than November 12, 20 f6. charged for the foregoing publication is not /sCathy P Foerst r in excess of the rate charged private chair, Commissioner individuals. Published: October 14, 2016 Signed Subscribed and sworn to before me �!oi�ry �sbiic t is 14th day of October, 2016 BRITIlEy L. i HOi��PSOF3 ' S ion of A a. • �,, ssn Expire.' Fb 23, 2111 Notary Publi n and for The State of Alaska. Third Division Anchorage, Alaska MY COMMISSION VXPIRES Doi 7 Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Wednesday, October 12, 2016 3:17 PM To: Ballantine, Tab A (LAW); Bender, Makana K (DOA); Bettis, Patricia K (DOA); Bixby, Brian D (DOA); Brooks, Phoebe L (DOA); Carlisle, Samantha J (DOA); Colombie, Jody J (DOA); Cook, Guy D (DOA); Davies, Stephen F (DOA); Eaton, Loraine E (DOA); Foerster, Catherine P (DOA); French, Hollis (DOA); Frystacky, Michal (DOA); Grimaldi, Louis R (DOA); Guhl, Meredith D (DOA); Herrera, Matthew F (DOA); Hill, Johnnie W (DOA); Jones, Jeffery B (DOA); Kair, Michael N (DOA); Link, Liz M (DOA); Loepp, Victoria T (DOA); Mumm, Joseph (DOA sponsored); Noble, Robert C (DOA); Paladijczuk, Tracie L (DOA); Pasqual, Maria (DOA); Quick, Michael J (DOA); Regg, James B (DOA); Roby, David S (DOA); Scheve, Charles M (DOA); Schwartz, Guy L (DOA); Seamount, Dan T (DOA); Singh, Angela K (DOA); Wallace, Chris D (DOA); AK, GWO Projects Well Integrity; AKDCWellIntegrityCoordinator; Alan Bailey; Alex Demarban; Alexander Bridge; Allen Huckabay; Andrew VanderJack; Ann Danielson; Anna Raff; Barbara F Fullmer; bbritch; bbohrer@ap.org; Bill Bredar; Bob Shavelson; Brian Havelock; Bruce Webb; Caleb Conrad; Candi English; Cocklan-Vendl, Mary E; Colleen Miller; Crandall, Krissell; D Lawrence; Dale Hoffman; Dave Harbour; David Boelens; David Duffy; David House; David McCaleb; David Tetta; ddonkel@cfl.rr.com; DNROG Units (DNR sponsored); Donna Ambruz; Ed Jones; Elizabeth Harball; Elowe, Kristin; Evan Osborne; Evans, John R (LDZX); Gary Oskolkosf; George Pollock; Gordon Pospisil; Greeley, Destin M (DOR); Gretchen Stoddard; gspfoff; Hyun, James J (DNR); Jacki Rose; Jdarlington Oarlington@gmail.com); Jeanne McPherren; Jerry Hodgden; Jim Watt; Jim White; Joe Lastufka; Radio Kenai; Burdick, John D (DNR); Easton, John R (DNR); Jon Goltz; Juanita Lovett; Judy Stanek; Julie Little; Kari Moriarty; Kasper Kowalewski; Kazeem Adegbola; Keith Torrance; Keith Wiles; Kelly Sperback; Frank, Kevin (DNR sponsored); Kruse, Rebecca D (DNR); Gregersen, Laura S (DNR); Leslie Smith; Lori Nelson; Louisiana Cutler; Luke Keller; Marc Kovak; Dalton, Mark (DOT sponsored); Mark Hanley (mark.hanley@anadarko.com); Mark Landt; Mark Wedman; Kremer, Marguerite C (DNR); Mealear Tauch; Michael Bill; Michael Calkins; Michael Moora; MJ Loveland; mkm7200; Munisteri, Islin W M (DNR); knelson@petroleumnews.com; Nichole Saunders; Nikki Martin; NSK Problem Well Supv; Patty Alfaro; Paul Craig; Decker, Paul L (DNR); Paul Mazzolini; Pike, Kevin W (DNR); Randall Kanady; Delbridge, Rena E (LAS); Renan Yanish; Richard Cool; Robert Brelsford; Ryan Tunseth; Sara Leverette; Scott Griffith; Shannon Donnelly; Sharmaine Copeland; Sharon Yarawsky; Shellenbaum, Diane P (DNR); Skutca, Joseph E (DNR); Smart Energy Universe; Smith, Kyle S (DNR); Stephanie Klemmer; Stephen Hennigan; Sternicki, Oliver R; Moothart, Steve R (DNR); Steve Quinn; Suzanne Gibson; sheffield@aoga.org; Ted Kramer; Davidson, Temple (DNR); Teresa Imm; Thor Cutler; Tim Jones; Tim Mayers; Todd Durkee; trmjrl; Tyler Senden; Umekwe, Maduabuchi P (DNR); Vinnie Catalano; Weston Nash; Whitney Pettus; Aaron Gluzman; Aaron Sorrell; Ajibola Adeyeye; Alan Dennis; Assmann, Aaron A; Bajsarowicz, Caroline J; Bruce Williams; Bruno, Jeff J (DNR); Casey Sullivan; Catie Quinn; Don Shaw; Eric Lidji; Garrett Haag; Smith, Graham O (DNR); Dickenson, Hak K (DNR); Heusser, Heather A (DNR); Holly Pearen; Jamie M. Long; Jason Bergerson; Jim Magill; Joe Longo; John Martineck; Josh Kindred; Laney Vazquez; Lois Epstein; Longan, Sara W (DNR); Marc Kuck; Marcia Hobson; Steele, Marie C (DNR); Matt Armstrong; Franger, James M (DNR); Morgan, Kirk A (DNR); Umekwe, Maduabuchi P (DNR); Pat Galvin; Pete Dickinson; Peter Contreras; Richard Garrard; Richmond, Diane M; Robert Province; Ryan Daniel; Sandra Lemke; Pollard, Susan R (LAW); Talib Syed; Tina Grovier (tmgrovier@stoel.com); Tostevin, Breck C (LAW); Wayne Wooster, William Van Dyke Subject: Public Notice Attachments: GMT1 allocation factor Public Hearing Notice Otherl6-025.docx Please see attached. Re: Docket No. OTH 16-25 ConocoPhillips Alaska, Inc. (CPAI) has requested a meter allocation factor of 1.0 be applied to the fiscal allocation meter to be used at the Greater Moose's Tooth 1 development to allocate production between the Greater Moose's Tooth and Colville River Units. Jody J. Colombie .AOGCC Specia(.Assistant .Alaska Oi(and Gas Conservation Commission 333 ''Vest 7" .Avenue .Anchorage, .Alaska 99501 Office: (907) 793-1221 Fax: (907) 276-7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jody Colombie at 907.793.1221 or iodv.colombie@alaska.aov. Jack Hakkila Bernie Karl K&K Recycling Inc. Gordon Severson P.O. Box 190083 P.O. Box 58055 3201 Westmar Cir. Anchorage, AK 94519 Fairbanks, AK 99711 Anchorage, AK 99508-4336 Penny Vadla George Vaught, Jr. Darwin Waldsmith 399 W. Riverview Ave. P.O. Box 13557 P.O. Box 39309 Soldotna, AK 99669-7714 Denver, CO 80201-3557 Ninilchik, AK 99639 Richard Wagner Misty Alexa Stephen Thatcher P.O. Box 60868 ConocoPhillips Alaska, Inc. ConocoPhillips Alaska, Inc. Fairbanks, AK 99706 P.O. Box 100360 P.O. Box 100360 Anchorage, AK 99510 Anchorage, AK 99510 rA-6-4 t�o ConocoPhillips p February 26, 2016 Commissioner Cathy Foerster Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue Anchorage, AK 99501 Misty Alexa Manager, WNS Development ConocoPhillips Alaska 700 G Street Anchorage, AK 99501-3439 Phone 907.265.6822 RE: Greater Mooses Tooth Unit Request for Approval of Production Measurement Dear Commissioner Foerster: REECE lvhu Stephen Thatcher Manager, WNS Operations ConocoPhillips Alaska 700 G Street Anchorage, AK 99501-3439 907.670.4024 ConocoPhillips Alaska, Inc. (ConocoPhillips), as Unit Operator of the Greater Mooses Tooth Unit (GMTU) and Colville River Unit (CRU), and on behalf of itself and the other working interest owner in the GMTU and CRU, Anadarko E&P Onshore LLC, requests approval for a proposed hydrocarbon production measurement and allocation system for the first GMTU development GMT1. As described in detail in Attachment 1 to this letter, GMT1 is designed as a satellite drillsite in the National Petroleum Reserve - Alaska (NPR -A) west of the existing CD -5 drillsite in the Colville River Unit (CRU). GMT1 construction is scheduled to begin in fourth quarter 2016, and first oil is planned to begin in the fourth quarter of 2018. ConocoPhillips has not yet submitted an application for a conservation order for the oil pools to be developed by GMT1. However, AOGCC Industry Guidance Bulletin 13-002 specifies that AOGCC approval of custody transfer measurement is required before installation of the meter system, which as a practical matter means approval is required at the engineering and procurement stage of development. Thus, ConocoPhillips is seeking AOGCC approval in advance of the application for pool rules. 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 for which equipment will soon be purchased. ConocoPhillips thus seeks approval now, with the understanding that the AOGCC might later require specific information that is not presently available. ConocoPhillips is also seeking approval now because of the unique nature of the GMTU, which includes in part oil and gas leases conveyed by the federal Bureau of Land Management, and which is administered by the BLM. ConocoPhillips has discussed measurement issues with BLM at length, and most recently submitted an application for BLM approval of a proposed measurement system on January 21, 2016. Attachments 1— 4 to this cover letter, which provide details, technical specifications, and context for the proposed measurement system, are substantially the same attachments that have been provided to the BLM. In some particulars, the attachments are directed at BLM-specific issues, but overall they address issues of interest to both the AOGCC and the BLM. ConocoPhillips is seeking concurrent regulatory approval from both the AOGCC and the BLM for the proposed measurement system. The proposed GMT1 measurement system includes a 3-phase production separator providing continuous measurement of GMT1 oil production using a Coriolis meter and water cut analyzer. It also includes American Gas Association (AGA) compliant orifice meter runs for produced gas. After separation and measurement at the GMT1 drillsite, the produced fluids will be recombined and flow to the CD5 drillsite in the CRU, where production from the two drillsites will be combined and flow to Alpine production facilities. At the Alpine production facilities, commingled production from GMT1 and all of the CRU drillsites will be separated, processed, and delivered to the Alpine Pipeline, through a Lease Automatic Custody Transfer (LACT) meter, for transportation to market. The proposed system for GMT1 differs from the existing well test allocation system in effect at CRU. GMT1 production will be measured continuously within the GMTU prior to being commingled with CRU production, and will in effect have an allocation factor of 1.0 at the CRU LACT meter. The measurement system proposed for GMT1 also includes AGA -compliant orifice meter runs at GMT1 for re-injection gas and miscible injection gas that will flow from the Alpine production facilities back to GMT1. To the extent the system involves measurement of gas produced from CRU, ConocoPhillips seeks approval for off -unit measurement of the gas at GMT1. As AOGCC staff is already aware through informal discussions, the proposed GMT1 measurement system is designed to provide a high degree of accuracy, to gain approval of both AOGCC and the BLM, and to be economically reasonable. 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). Documentation in Attachment 1 — 4 supporting this application includes a complete description of the proposed equipment and a detailed uncertainty analysis including the uncertainty associated with shrinkage. If you have questions or need additional information, please contact Brandon Viator, Project Integration Manager —GMTU, at 907-263-4653. Sincerely, Misty a Manager, WNS Development ConocoPhillips Alaska GMTU Representative Stephen Thatcher Manager, WNS Operations ConocoPhillips Alaska CRU Representative Attachments 1. GMT1 Development and Measurement Approval Request Overview 2. GMT1 Flow Measurement and Metering Philosophy—Three Phase Production Separator 3. October 1, 2014 Whitepaper - GMT1 Commingling, Allocation, and Measurement Summary 4. Production Facility Analysis Attachment 1: GMT1 Development and Measurement Approval Request Overview Oil Measurement by Other Methods / Beneficial Use Off -lease Gas Contents A. Requested Approvals........................................................................................................................... 2 B. GMT1 Project Description....................................................................................................................2 C. Maps and Schematics Depicting Units and Facilities..........................................................................4 Figures: • Attachment 1A — GMT1 and CRU Map (Gathering System) • Attachment 113 — GMT1 leases, preliminary PA, and proposed wells • Attachment 1C — GMT1 lease ownership, royalty rate, and allocation factor • Attachment 1D — GMT1 drillsite diagram • Attachment 1E — GMT1 drillsite process flow diagram • Attachment IF — GMT1 production separator measurement system • Attachment 1G — ACF simple process flow diagram A. Requested Approvals ConocoPhillips requests Bureau of Land Management (BLM) and Alaska Oil and Gas Conservation Commission (AOGCC) approval for the Greater Mooses Tooth #1 (GMT1) measurement system design, described in Attachment 2, GMT1 Flow Measurement and Metering Philosophy — Three Phase Production Separator. This document constitutes a submission for approval of the proposed oil measurement concepts for GMT1 in accordance with section "E — Oil Measurement by Other Methods" of the BLM onshore order number four; Measurement of Oil (1989) and BLM's December 24, 2014 letter expressing intent to approve a measurement system with a continuous separator for GMT1. This document is also in accordance with Alaska Administrative Code 20 AAC 25.228 covering the application for AOGCC approval of production measurement equipment for custody transfer. The need for this submission stems from the operational scenario for GMT1 and is associated with the measurement of hydrocarbon liquids at elevated temperature and pressure (which are not stable) as per the requirements of the American Petroleum Institute (API) Manual of Petroleum Measurement Standards (MPMS) chapter 6.1 Metering Assemblies - Lease Automatic Custody Transfer (LACT) Systems (2012) ConocoPhillips also requests BLM approve royalty free beneficial use of fuel gas on the GMT1 drillsite. GMT1 fuel gas will be used in participating area (PA) specific operations (like the drillsite produced fluids heater) as depicted in Attachments 1E, 1F and 1G. A production heater will be located at GMT1 to provide heat prior to measurement and transportation of produced fluids via pipeline back to the Alpine Central Facility (ACF) for processing. After processing at the ACF, gas for fuel, injection and artificial lift are sent back to GMT1 via pipeline connections at CD5. As shown in Attachment 1E, total gas will be measured at GMT1 before being sent to the ACF for processing. The conditioned GMT1 gas will then be sent back to GMT1 for use as fuel, injection and artificial lift. Any excess gas not used at GMT1 can be utilized in the CRU as fuel, injection or artificial lift and appropriately measured. AOGCC approval is also requested for the custody transfer measurement of the gas used at GMTU for fuel, injection, and artificial lift, to be located at GMT1 rather than in the Colville River Unit (CRU). B. GIVITI Project Description The GMT1 project will develop the first drill site in the Greater Moose's Tooth Unit (GMTU) which is in the northeast corner of the National Petroleum Reserve — Alaska (NPR -A). The GMT1 project is planned to construct a drillsite, access road, pipelines, power lines, bridges, and ancillary facilities for recovery of petroleum resources within the GMTU. The GMT1 drillsite will be located 14 miles west of the CRU CD1 drillsite and the ACF. The GMT1 project will develop Arctic Slope Regional Corporation (ASRC) and 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 GMT1 satellite was discovered in 2000 by the Lookout #1 well; was delineated in 2002 by the Lookout #2, Mitre 1, and Mitre 1A wells; and is covered by 1999 and 2015 3D Seismic datasets. The GMT1 project will provide sufficient infrastructure to support development of up to 33 wells. The proposed GMT1 infrastructure will tie back to the CRU at the CD5 drillsite and will be the fifth satellite developed through the ACF following development of the Qannik CD2, Fiord CD3, Nanuq CD4, and Alpine West CD5 satellites (see Attachment 1A). The project will produce 3-phase fluids (oil, gas, and water) which 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 from CD1 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 GMT1 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 GMT1 development is expected to employ up to 700 people during the peak of construction and result in new full time positions upon startup. 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 GMT1 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. Executive Order 13212 directs federal agencies to give priority to energy- related projects: "For energy-related projects, agencies shall expedite their review of permits or take other actions as necessary to accelerate the completion of such projects, while maintaining safety, public health, and environmental protections." The current GMT1 Development Project seeks to minimize environmental impacts by leveraging existing infrastructure where available and avoid redundancy and waste. One of the key aspects of this approach is the utilization of the existing installed processing capacity at the ACF. The use of this facility greatly reduces the environmental footprint of GMT1 by eliminating the need for a standalone GMT1 processing facility capable of producing sales -quality crude oil. Without approval of an alternative 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. The estimated incremental environmental and cost impacts associated with such a processing facility are discussed beginning on page 6 of Attachment 3, October 1, 2014 Whitepaper — GMT1 Commingling, Allocation, and Measurement Summary. Note that the measurement system submitted for approval here differs in some ways from the system originally proposed and discussed in the October 1, 2014 whitepaper. Attachment 4, Production Facility Analysis, has also been included to demonstrate the project value impact if GMT1 was required to install a processing facilitV in order to meet metering requirements. 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 GMT1 project, designed as a satellite drill site that relies on existing ACF infrastructure for processing, has been approved by the United States Army Corps of Engineers as the Least Environmentally Damaging Practicable Alternative (LEDPA). C. Maps and Schematics Depicting Units and Facilities The map and figures included as Attachments 1B and 1C, show the GMTU leases, proposed development wells and conceptual unit participating area (PA). The map and figures illustrate how GMT1 pipelines tie back to the CRU. The GMT1 development drillsite consists of eight process modules and a well row. The process modules consist of a pig launcher/receiver module, production heater, test separator, 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), and a production separator system which will be used as the GMT1 point of royalty. Attachment 1D, the proposed GMT1 site plan, displays the layout of the drillsite infrastructure. Attachment 1E provides a GMT1 drillsite process flow diagram and Attachment 1F provides additional detail on the GIVITI 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. ACF processed produced water is returned to the drillsites for re-injection into the producing formations to maintain reservoir pressure and provide secondary flood support. ACF processed gas is: (i) used to fuel plant and drillsite facility equipment, (ii) provided to the Village of Nuiqsut in accordance with the terms and conditions of the Surface Use Agreement between ConocoPhillips and Kuukpik Corporation, (iii) re -injected in the Alpine reservoir to maintain reservoir pressure for increased recovery, and (iv) used for gas lift. Attachment 1A: GIViT1 and CRU Pipelines `%,.H4afr i son Bey d' CD3 River (C National Petroleum Unit Reserve - .Alaska � 4 Q CD2 CD1 CD5 'CD4 3 reater g MOOSesw � Tooth � GMT1 1;4 NUIQSUT Unit ' Legend E Exploration Well ...�►` Roads and Pads ®CPAI Unit Boundary e Pipeline t tt L:;NPR-A Boundary 0 1 2 3 4 5 " Miles A Attachment 1C: GMT1 lease ownership, royalty rate, and allocation factor List of Ceases for Potential Lookout Participating Area Proposed Tract Serial Number uuill ulij[ Description Unit PA No. Tobin Number of Lands Number Basic Royalty Working Ownership Tract GMTU Lookout 2 AA 081743 T11N-R2E, UM of Acres Ro a Owner interest Owners Percentage Allocation 953086 Section 13: SE1/4NE1/4, SE1/4, NEI/4SW1/4, S1/2SW1/4 18.6667% U.S. ConocoPhillips 78.00 TBD Anadarko Total 320.00 320.O0 22_00100.00 GMTU Lookout 3B AA -092340 T11N-R3E, UM 340759 Section 18: SWIMSE1/4, SWIM, SWt/4NW1/4 223.50 16.6667% ASRC ConocoPhillips 78.00 TBD Total 223.50 Anadarko 22_00 100.00 GMTU Lookout 9A AA -081819 T11N-R2E, UM 932554 Section 23: NE114NE1/4, S112NEI/4, SE1/4, SE1/4SW1l4 319.50 16.8667% U.S. ConocoPhiAips 78.00 TBD Total 319.50 Anadarko 2200 _ 100.00 GMTU Lookout 98 AA -092346 T11N-R2E, UM 340760 Section 24: All 16.6667% ASRC ConocoPhillips 78.00 TBD Section 25: All 640.00 Anadarko 22.00 Section 28: E12, E1/2W1/2, W12SW114, SW1/4NW1/4 640.0 599.06 6 100.00 Section 35: E112, NEI/4SW1/4, E112NW1/4, NWI/4NWI/4 Section 38: All 479.25640.00 Total 2,998.31 GMTU Lookout 10A AA -081818 T1IN-R3E, UM 932553 Section 30: W1/2, W1/2E1/2, E112NE1/4, NE114SE114 585.31 16.8667% U.S. ConocoPhillips 78.00 TBD Section 31: W1/2, W1/2E1/2 453.75 Anadarko 22_00 Total 1,019.06 100.00 GMTU Lookout 10B AA -092345 T11N-R3E, UM 340761 Section 19: W112, WI/2EI2. SE1/4NE1/4, E112SE114 562.50 16.6667% ASRC ConocoPhilfips 78.00 TBD Total 562.50 Anadarko 2200 _ GMTU Lookout 168 AA -092342 T10N R2E, UM 100.00 340763 Section 1: N112, SEI/4, N12SW1/4 16.8667% ASRC ConocoPhillips 78,00 TBD Section 2: E12NE114, NW174NE114 559.13 Anadarko 2222 00 Total 119.81 678.94 + 100.00 GMTU Lookout 17 AA -081798 T10N-R3E, UM 932533 Section 6: NW114, W12NE1/4, N1/2SW1/4, SWI/4SW1/4 341.44 16.6667°/ U.S. ConocoPhillips 78.00 TBD Total 341.44 Anadarko 22_00 100.00 TOTAL PA ACREAGE 6,463.250 Key: Anadarko - Anadarko E&P Onshore LLC ASRC - Arctic Slope Regional Corporation ConocoPhillips - ConocoPhillips Alaska, Inc. U.S. - United States of America Attachment 1E: GMT1 Drillsite Flow Diagram Rev 1) Additional Utilities Required-, Nitrogen Plant Air Fuel Gas Line list: Purple: Chemical Orange: Gas Green_ON+water Blue: Separated water Black: Oil+water+gas ESD Module i I 1 I — — — --1 it I — 41 Production Neater Anti -[nam Test Mod. r-- — — — t i I I I I =Pi Li � 1 i I 1 nWater Cut Meter Coriolis Meth 0 Orifice Plate Meter Fuel Gas Mod corrosion Inhibitor Scale t— — ———— — —— — —— t I .. _i. __. r' - Inhibitor Emulsion Fuel Gas. _ Breaker Anti -[nam Test Mod. r-- — — — t i I I I I =Pi Li � 1 i I 1 nWater Cut Meter Coriolis Meth 0 Orifice Plate Meter Pig Launcher From CD5/AGF TO CDSIACF Fuel Gas Mod Lift Gas ......- t— — ———— — —— — —— t I .. _i. __. r' - I GI Fuel Gas. _ _ t _ I To Injector I I I I Wells� _ _, l _ -.. 1-- _. MI ° t I f I (------- Metering Mod, 1------------I F 1 Full flow 3 phase l I separator I t00 1 � I 3 ?� r I l Pig Launcher From CD5/AGF TO CDSIACF Attachment 1F: GMT1 Production Separator Measurement System f"wr Cas to piling, n '41F.I(a F01 flow 3 chase separate, 401 Water Cut Meter k,re s!s!. 0l3nge: Gas Cors:lis %letw G.een- Oil+water Blue: Sepa•attd watef Btack: CS'7+watrNgac d=:Lce Prate motet f.:, I Static Mixef C1 Strainer -•�--^W I°roducklon to c%,,fACt Attachment 1G: ACF simple process flow diagram e Alpine Production Facility Gas Common Furl & Rare Processing Gas condensate Gas Enrichment oil Pr Processing Alpine I. anu -`;.i.crt�ICOut* _.�- 111#{ FN FK *Proposer! PA Stabile Enriched Gas Injection Condensate i Oil Sales Water Injection Lift Gas Dry Gas Injection IV Nanulq ..Looitout* ."-- N Sea Water PN FK Attachment 2 ConocoPhillips Alaska PhilosophyFlow Measurement and Metering SeparatorThree Phase Production Measurement Revision 1 February 9, 2016 GREATER MOOSES TOOTH 1 Attach 2 GMT1 Flow Measurement and Metering Philosophy_Rev1.doc V—'�, COnocoP illi S FLOWMEASUREMENTANDMETERING PHILOSOPHY - THREE PHASE PROD UCTION SEPARA TOR OIL Alaska MEASUREMENT REV. 1 DATE: 2/9/I6 PAGE 2 OF 17 TABLE OF CONTENTS 1.0 INTRODUCTION......................................................................................................................3 2.0 VOLUMETRIC CONVERSION.................................................................................................4 2.1 Measurement System Design, Operation and Maintenance.........................................5 3.0 FLOW MEASUREMENT AND METERING SYSTEM DESCRIPTIONS...................................5 3.1 Custody Transfer/Point of Royalty Metering..................................................................6 3.1.1 Production Separator Oil Metering....................................................................6 3.1.2 Production Separator Gas Metering..................................................................7 3.2 Drillsite Gas Metering...................................................................................................7 3.3 Operation and Maintenance..........................................................................................8 3.3.1 Coriolis Oil Meters.............................................................................................8 3.3.2 Differential Pressure Gas Meters......................................................................8 3.3.3 Secondary Measurement Instruments...............................................................8 3.3.4 Sampling...........................................................................................................8 3.3.5 Shrinkage Factor...............................................................................................9 4.0 ALLOCATION METHODOLOGY...........................................................................................10 5.0 GENERAL INFORMATION....................................................................................................10 5.1 Industry Standards......................................................................................................10 5.2 Terms and Definitions.................................................................................................12 5.3 Abbreviations and Acronyms......................................................................................13 5.4 Units of Measurement.................................................................................................14 6.0 MEASUREMENT PROJECT ACTIVITIES AND REQUIREMENTS.......................................14 6.1 General.......................................................................................................................14 6.2 Design........................................................................................................................15 6.3 General Installation Requirements..............................................................................15 6.4 Instrument Traceability...............................................................................................16 6.5 Measurement System Fabrication and Testing...........................................................16 6.6 Commissioning ......................................... 6.7 Handover....................................................................................................................17 6.8 Maintenance...............................................................................................................17 6.9 Test Equipment..........................................................................................................17 6.10 Audit...........................................................................................................................17 Attach 2 GMT1 Flow Measurement and Metering Philosophy_Rev1.doc ConocoPhillips Alaska 1.0 INTRODUCTION GREATER MOOSES TOOTH 1 FLOW MEASUREMENTAND METERING PHILOSOPHY - THREE PHASE PRODUCTION SEPARA TOR OIL MEASUREMENT REV. 1 DATE: 219116 PAGE 3 OF 17 The GMT1 project will develop the first drill site in the Greater Moose's Tooth Unit (GMTV) which is in the northeast corner of the National Petroleum Reserve — Alaska (NPR -A). The GMT1 project will develop resources on Arctic Slope Regional Corporation (ASRC) and federal government leases, and ConocoPhillips seeks approval for the measurement system design from both the Bureau of Land Management (BLM) and Alaska Oil and Gas Conservation Commission (AOGCC). This document is part of a submission package for approval of the proposed oil measurement system for GMT1 in accordance with Section E — ("Oil Measurement by Other Methods") of the BLM Onshore Oil and Gas Order No. 4; Measurement of Oil (1989). This document is also in accordance with BLM's December 24, 2014 letter expressing intent to approve a measurement system for GMT1 that uses a continuous separator, and with Alaska Administrative Code 20 AAC 25.228, which addresses AOGCC approval for production measurement prior to custody transfer. The need for this submission stems from the design of GMT1 as a satellite drillsite 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 as per the requirements of the American Petroleum Institute (API) Manual of Petroleum Measurement Standards (MPMS) chapter 6.1 Metering Assemblies - Lease Automatic Custody Transfer (LACT) Systems (2012). Additionally, this submission is requesting an AOGCC approval of off lease measurement of re- injection and miscible injection gas from Colville River Unit (CRU) at GMT1 per 20 AAC 25.228. which requires custody transfer measurement prior to hydrocarbon production severance from the unit where produced. The off lease gas measurement methodology is proposed to minimize impacts to existing infrastructure in the CRU and overall Proiect cost The metering system is designed for approval under both State of Alaska and Federal regulatory requirements as per Table 1 below. Table 1 — State of Alaska and Federal Regulations Std sof Alaska — Ata"a Admitimt atllve Code (AAC) and, AOGCC Gu4once ftl etth 20 AAC 25.228 Production Measurement Equipment for Custody Transfer AOGCC Industry Guidance Bulletin 13- 002 Custody Transfer Meter Application Guidance BLM Onsholre Orders and NoWe to s Q4%), t Onshore Order 3 Site Security (Effective Date: March 27, 1989) Onshore Order 4 Measurement of Oil (Effective Date: August 23, 1989) Attach 2 GMT1 Flow Measurement and Metering Philosophy_Rev1.doc GREATER MOOSES TOOTH 1 Conoco�r, p�h FLOW MEASUREMENT AND METERING PHILOSOPHY ��'��5- THREE PHASE PRODUCTION SEPARATOR OIL Alaska MEASUREMENT REV. I DATE: 2/9116 PAGE 4 OF 17 2.0 VOLUMETRIC CONVERSION The following paragraphs provide an explanation and illustration as to why it is not possible to comply with the BLM onshore order for oil measurement and why we must submit an application to measure oil by other methods to those prescribed in Onshore Order No. 4. The GMT1 project constraints require that we measure live fluids at elevated temperature and pressure. 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 (EOS) modeling based upon detailed compositional analysis. The uncertainty budget for these methods are dependent upon a range of variables which include the representivity of samples, the quality of test equipment and the detail of compositional data obtained. The uncertainty budget associated with Shrinkage Factors is not well documented for either laboratory or EOS modeling; however available industry literature such as the draft API MPMS Chapter 21.4 and experience from field operations elsewhere in ConocoPhillips suggests that +/-2% is a reasonable estimate. Appendix A of this document provides approximately four years of ConocoPhillips United Kingdom J -Block daily mass balance errors as field operations evidence in support of the uncertainty budget estimate. 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. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl .doc Onshore Order 5 Measurement of Gas (Effective Date: March 27 1989) Alaska State Office NTL 2009-1 Standards for the Use of Electronic Flow Computers Used On Differential Type Flow Meter for Gas Measurement 2.0 VOLUMETRIC CONVERSION The following paragraphs provide an explanation and illustration as to why it is not possible to comply with the BLM onshore order for oil measurement and why we must submit an application to measure oil by other methods to those prescribed in Onshore Order No. 4. The GMT1 project constraints require that we measure live fluids at elevated temperature and pressure. 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 (EOS) modeling based upon detailed compositional analysis. The uncertainty budget for these methods are dependent upon a range of variables which include the representivity of samples, the quality of test equipment and the detail of compositional data obtained. The uncertainty budget associated with Shrinkage Factors is not well documented for either laboratory or EOS modeling; however available industry literature such as the draft API MPMS Chapter 21.4 and experience from field operations elsewhere in ConocoPhillips suggests that +/-2% is a reasonable estimate. Appendix A of this document provides approximately four years of ConocoPhillips United Kingdom J -Block daily mass balance errors as field operations evidence in support of the uncertainty budget estimate. 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. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl .doc 2.1 GREATER MOOSES TOOTH 1 ConocoPhillips FLOW MEASUREMENTAND METERING PHILOSOPHY O Jn��® II'fll - THREE PHASE PRODUCTION SEPA RA TOR OIL Alaskaa MEASUREMENT REV 1 Table 2 — Comparable Measurement Uncertainties DATE. 219116 PAGE 5 OF 17 bl* F i r moi =�l►#x € r mors Flow Meter Base Flow Meter Base Accuracy plus Accuracy plus Mass 0.15 Pressure and Mass 0.16 Pressure and Temperature Temperature Corrections Corrections Observed 0.25 Mass Uncertainty Observed Mass Uncertainty Volume plus Observed Volume 0.27 plus Observed Density Uncertainty Density Uncertainty Mass Uncertainty, Mass Uncertainty, Observed Density Observed Density Standard 0.35 Uncertainty Plus Standard 2.1 Uncertainty Plus Volume Conversion to Volume Conversion to Standard Volume Standard Volume Uncertainty (VCF) Uncertainty (SF) Measurement System Design, Operation and Maintenance It is very important to note that the differences in performance in determining Standard Volume between the BLM onshore order or AOGCC 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 GMT1 oil production is provided as Appendix B of this document where a maximum value of +/- 2.1% at 95% confidence level has been determined. The calculations required to determine Net Standard Volume are also contained within the uncertainty calculation provided in Appendix B. The operating and maintenance methods contained in section 3.3 of this document will allow us to monitor and verify the performance of the metering system and its components to demonstrate ongoing compliance with agreements reached based upon this submission in accordance with the onshore order. 3.0 FLOW MEASUREMENT AND METERING SYSTEM DESCRIPTIONS The oil metering system described in this section has been designed to obtain approval under state and federal regulations and incorporates experience from existing installations and previous projects. The GMT1 project is located 14 miles west of the Alpine Central Facility (ACF) in the GMTU within the NPR -A on the North Slope of Alaska. The GMT1 drillsite development scope includes Attach 2 GMT1 Flow Measurement and Metering Philosophy_Rev1.doc GREATER MOOSES TOOTH I �'' Conocc'Philh S FLOWMEASUREMENTANDMETERINGPHILOSOPHY DATE: 2/9/16 M - THREE PHASE PR OD UCTION SEPA RA TOR OIL Alaska MEASUREMENT PAGE 6 OF 17 REV. l all on -pad production facilities and off -pad infrastructure including a gravel access road and drillsite pad. The GMT1 development will connect to the CD5 drillsite via eight miles of pipelines, power lines, and gravel road; providing the first infrastructure into the GMTU and connecting the project to the existing CD5 and CRU infrastructure. The project scope includes 9 initial wells (4 production wells and 5 injection wells). The GMT1 drillsite gravel pad will accommodate up to 33 wells for possible future development. GMT1 will consist of eight process modules and a well row. The process modules consist of a pig launcher/receiver module, full flow three-phase production separator, production heater, test separator, remote electrical & instrumentation module (REIM), emergency shutdown module (ESD), chemical injection module and fuel gas conditioning module. The drillsite full -flow production separator, elevated to prevent gas breakout, will serve as AOGCC's unit boundary custody transfer measurement and BLM's point of royalty measurement (PRM) for produced oil and gas hydrocarbon streams. After measurement, the well fluids will be recombined and travel to ACF in the production crude pipeline. The ACF separates and processes well bore fluids from the production crude pipeline and delivers sales -quality crude oil. ACF -processed produced water is returned to the drill sites for re-injection into the producing formations to maintain reservoir pressure and provide secondary flood support. ACF -processed gas is returned to the drillsite as miscible injection (MI) or lift gas, or used within the plant as fuel gas. MI is re -injected in the reservoir to maintain reservoir pressure and to enhance oil recovery. Lift gas is used for production well lift and converted to fuel gas for drillsite utilities. 3.1 Custody Transfer/Point of Royalty Metering The custody transfer/PRM system shall 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, weir (three-phase operation), mist extractor on the gas outlet, vortex breaker and sand -jet system. 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 throughout field life 3.1.1 Production Separator Oil Metering The oil metering system shall consist of two Micro Motion Elite Coriolis Flow Meters installed in a parallel configuration, sized to cope with the full range of expected flow rates, and includes strainer, inline mixer, water cut analyzer, pressure and temperature instrumentation and control valves. All flow measurement information shall be fed to a dedicated flow computer in order to calculate Net oil volume at standard conditions. An automatic flow proportional sample system shall be installed in order to permit collection of representative oil samples for laboratory analysis. Process and Instrumentation diagrams (P+ID's) of the GMT1 production separator and oil metering system can be seen at Appendix C of this document. This is a dual redundant metering system configuration which will permit maintenance and operational activities to be performed without interruption to production. Flow calculations shall be performed as per the calculation detail provided in Appendix B of this document and in accordance with API chapter 20.1 Allocation Metering. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl.doc 3.2 GREATER MOOSES TOOTH 1 ��®i"� FLOW MEASUREMENTAND METERING PHILOSOPHY DATE: 2/9/16 — THREE PHASE PRODUCTION SEPARA TOR OIL Alaska MEASUREMENT PAGE 7 OF 17 REV I All measurement equipment and sample system hardware shall be installed per suppliers' recommendations. Sufficient pressure head and careful arrangement of piping are critical factors to avoid flashing of gas and for proper metering systems performance. • �. ;1j"- 3.2 _ The production separator gas outlet metering system shall include two meter runs providing for the full range of gas flowrates from the drillsite Conceptually this will be accomplished by two similar AGA compliant orifice meter runs of different size Additionally, the two meter runs provide a level of redundancy, again to help ensure improved drillsite uptime Fully redundant meter runs were deemed not necessary due to the highly reliable orifice metering technology and the relatively minimal maintenance down time to repair the meter. Each meter run will consist of upstream and downstream meter tubes flow conditioner, senior orifice fittinq and plate, and control valve A flow computer and DP Diagnostics a differential pressure diagnostic system shall be installed on the gas meter runs to monitor the health of the gas metering systems. All measurement equipment shall be installed per suppliers' recommendations Regulatory required flow meter verification and maintenance will be undertaken when the diagnostic system Indicates degradation in measurement performance Drillsite Gas frl'leterirnp Hydrocarbon gas management at GMT1 will require conformance to the applicable federal and state regulations. Similarly to produced hydrocarbons AOGCC requires custody transfer measurement of hydrocarbon gas streams between units It has been determined that total drillsite Ml Injection gas and reinjection gas including reinjection gas offtake points for total lift gas and fuel gas measurement will be reguired to conform with the applicable standards as they are Included in the qas royalty determination and commercial gas agreements Total drillsite reiniection artificial lift MI and fuel gas stream meterinq systems shall consist of AGA compliant orifice meter runs. Each meter run will consist of upstream and downstream meter tubes, flow conditioner (as necessary to minimize installation impacts to the qas conditioning module), senior orifice fitting and plate A flow computer and DP Diagnostics a differential pressure diagnostic system shall be installed on the gas meter runs to monitor the health of the gas metering systems. In order to minimize impacts to existing infrastructure at CRU the custody transfer gas meter stations will be physically located on the GMT1 drillsite This will require an off lease waiver approval per 20 AAC 25.22$ which requires custody transfer measurement prior to hydrocarbon production severance from the unit where produced Regulatory required flow meter verification and maintenance will be undertaken when the diagnostic system indicates degradation in measurement performance Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl.doc GREATER MOOSES TOOTH I FLOW MEASUREMENT AND METERING PHILOSOPHY DATE: 219116 CtJnocoPhIll i ps - THREE PHASE PRODUCTION SEPA RA TOR OIL Alaska MEASUREMENT PAGE 8 OF 17 REV. I 3.3 Operation and Maintenance 3.3.1 Coriolis Oil Meters Flow meter verification is accomplished by monthly checking of meter health utilizing 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. In addition, each flow meter shall be removed from service and calibrated at an accredited facility on an annual basis. This approach to monitoring and calibrating Coriolis flow meters has been implemented elsewhere in ConocoPhillips and has yielded satisfactory results over a number of years. Evidence in support of this practice is provided at Appendix D of this document where we have provided traceable information and certification of historical meter performance. We have also included SMV trending from Coriolis meters installed in test separator service at our existing drill sites in Alaska which demonstrate that the required meter performance can be achieved in this environment and that we have the infrastructure available to perform these checks. Manufacturer's brochures for Micro Motion Elite coriolis flowmeters and SMV are provided in Appendix E. 3.3.2 Differential Pressure Gas Meters Differential pressure aas meter verification is in part accomplished by the continuously running DP Diagnostics system. This advanced diagnostic system can reliably warn of orifice meter problems such as two-phase flow, contamination build-up through the meter, blocked impulse lines, saturated or drifting differential pressure transmitters or buckled backwards or worn plates. Additionally the orifice plates will be pulled for inspection and the meter tubes inspected with a boroscope annually. Manufacturer's brochures for Daniel meter tubes and DP Dia nostics are rovided in Appendix E. 3.3.3 Secondary Measurement Instruments The measurement instruments which are used in the determination of net standard volume shall be verified on a three monthly (quarterly) frequency. Verification frequency is based upon historical performance of this equipment. Manufacturer's brochures for Rosemount pressure and temperature transducers are provided in Appendix E. 3.3.4 Sampling Monthly flow proportional oil samples shall be obtained and occasional analyses performed as events dictate in order to provide operations teams with data to compare against observed online measurement parameters. Where a comparison of data shows a discrepancy between observed online information and sample information this will trigger investigative work to resolve the disparity. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl.doc COnocOPhillips Alaska GREATER MOOSES TOOTH 1 FLOW MEASUREMENT AND METERING PHILOSOPHY - THREE PHASE PRODUCTION SEPARATOR OIL MEASUREMENT REV. 1 DATE: 219116 PAGE 9OF17 Monthly flow proportional samples shall be made available to perform monthly water content (BS&W) analyses and occasional analyses as needed for the following parameters and retained for one year: Pressure, volume, temperature (PVT) analysis to determine shrinkage Compositional analysis of evolved gaseous hydrocarbons Compositional analysis of liquid hydrocarbons Where it is found that any online data, which has been used in the determination of net standard volume, needs to be corrected then operations teams will raise and submit a mismeasurement report in order to correct the reported volumes. Manufacturer's brochures for Phase Dynamics water content analyzers and JISKOOT CoJetix sampling systems are provided in Appendix E. 3.3.5 Shrinkage Factor Shrinkage factor (SF) shall be developed across a range of operating pressures and temperatures so that any process variances are captured in order to prevent a systematic bias impacting the measurement of oil. Table 3 below, linear interpolation matrix, provides an indication of the method which will be employed to determine SF from operating temperature and pressure. Table 3 — SF Linear Interpolation Matrix Process Adjustment Matra with Two Way Linear Interpolation Oil Shrinkage Factor Temperature Pressure 135 350 Pressure > Temperature v 150 250 350 400 125 0.176 0.873 0.$4192 0,83209 135 0.93135 0.$8501 0.8=7 145 0.94081 0.83355 X0,90 0:84759 Process Adjustment 0.853 Factor Attach 2 GMT1 Flow Measurement and Metering Philosophy—Revl.doc GREATER MOOSES TOOTH I Q Oil®CO—� FLOW MEASUREMENT AND METERING PHILOSOPHY DATE: 2/9/16 11th - THREE PHASE PRODUCTION SEPARATOR OIL Alaska MEASUREMENT REV 1 PAGE 10 OF 17 4.0 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 GMT1. Net standard volumes will utilize this metering allocation information for royalty payment data. 5.0 GENERAL INFORMATION 5.1 Industry Standards The State and Federal regulations do in some instances mandate compliance with particular industry standards, thus elevating them to a regulatory requirement. The below list of Industry Standards should be considered in discussions pertaining to the GMT1 oil measurement concept. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Rev1.doc Con®e®Phillips Alaska GREATER MOOSES TOOTH 1 FLOW MEASUREMENT AND METERING PHILOSOPHY -THREE PHASE PRODUCTION SEPARATOR OIL MEASUREMENT REV. I Table 4 — Industry Standards DATE: 219/16 PAGE 11 OF 17 American Petraieum Institute (API} API 505 Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified As Class I, Zone 0, Zone1, and Zone 2 API RP551 Process Measurement Instrumentation API RP555 Process Analyzers MPMS 4.X (Chapter 4) Manual of Petroleum Measurement Standards Chapter 4 — Proving Systems MPMS 5.X (Chapter 5 Manual of Petroleum Measurement Standards Chapter 5 - Measurement of Liquid Hydrocarbons MPMS 6.X (Chapter 6 Manual of Petroleum Measurement Standards Chapter 6 - Metering Assemblies MPMS 8.X (Chapter 8 Manual of Petroleum Measurement Standards Chapter 8 - Sampling MPMS 9.X (Chapter 9 Manual of Petroleum Measurement Standards Chapter 9 — Density Determination MPMS 14.X (Chapter 14 Manual of Petroleum Measurement Standards Chapter 14 - Natural Gas Fluids Measurement MPMS 20.1 (Chapter 20.1 Manual of Petroleum Measurement Standards Chapter 20.1 - Allocation Measurement MPMS 21.X (Chapter 21 Manual of Petroleum Measurement Standards Chapter 21 — Flow Measurement Using Electronic Metering Systems MPMS 22.X (Chapter 22 Manual of Petroleum Measurement Standards Chapter 22 - Testing Protocol Section TR 2570 Continuous On -Line Measurement of Water in Petroleum l�kttt f 1{ ft $ AssocAtIon �A) Report No. 3 Orifice Plate Metering of Natural Gas and other Related Hydrocarbon Fluids Report No. 5 Natural Gas Energy Measurement Report No. 8 Compressibility Factors of Natural Gas and Other Related Hydrocarbon Gases Report No. 10 Speed of Sound in Natural Gas and Other Related Hydrocarbon Gases Attach 2 GMT1 Flow Measurement and Metering Phil os; ophy_Rev1.doc GREATER MOOSES TOOTH I ConocoPhillips FLOW MEASUREMENTAND METERING PHILOSOPHY DATE: 219116 -THREE PHASE PRODUCTION SEPARA TOR OIL Alaska MEASUREMENT PAGE 12 OF 17 REI! I 5.2 Terms and Definitions The following terms and definitions apply to this document. Table 5 — Terms and Definitions Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl.doc Defittgn rCToerrn nstruction ontractor Company or business that agrees to furnish materials and/or perform specified construction/fabrication services at a price and/or rate to the Owner Engineering/Design Contractor Company or business that agrees to furnish materials and/or perform specified engineering/design services at a price and/or rate to the Owner Metering System Primary and secondary equipment used together to establish flow characteristics for a given process stream. Owner ConocoPhillips Company or a designated affiliate. Operator ConocoPhillips Company or a designated affiliate assigned with the operation and maintenance of equipment. Philosophy A presentation of the guiding principles based upon qualitative characterization, experience, policy, and company culture. Point of Royalty The meter or measurement facility used to measure the volume and Measurement quality of oil and gas on which royalty is reported as due. At quote stage: any entity invited to supply a quotation for the equipment and/or any Subcontractors thereto At Purchase stage: any entity contracted for the supply of the Supplier equipment and/or any Subcontractors thereto. In all cases, the Supplier is responsible for performance of all Work and will be the single point of contact for all Work-related issues. The Company will not receive information from, nor respond directly to Subsuppliers. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl.doc GREATER MOOSES TOOTH I C 10coPh1'IiS FL0W MEASUREMENT AND METERING PHILOSOPHY DATE: 219116 - THREE PHASE PROD UCTION SEPA RA TOR OIL Alaska MEASUREMENT PAGE 13 OF 17 REV. I 5.3 Abbreviations and Acronyms The following abbreviations and acronyms apply to this document. Table 6 — Abbreviations and Acronyms Abbr4)dst { + rf tfc AAC Alaska Administrative Code ACF Alpine Central Facility AGA American Gas Association AOGCC Alaska Oil and Gas Conservation Commission API American Petroleum Institute BLM Bureau of Land Management BOD Basis of Design Attach 2 GMT1 Flow Measurement and Metering Philosophy_Revl .doc GREATER MOOSES TOOTH I FL 0W MEASUREMENT AND METERING PHILOSOPHY �OiiOCOP�h tll�llp5 - THREE PHASE PROD UCTION SEPARA TOR OIL Alaska MEASUREMENT REV. 1 DATE: 2/9116 PAGE 14 OF 17 Customary U.S. Oilfield units of measure shall be used. These units are listed below: Table 7 — Units of Measure Parameter unit Liquid Volume bbl (barrel = 42 U.S. gallons) or STB (stock tank barrel) Liquid Volume Other gal (U.S. gallon) Gas Volume W (cubic feet) or scf (standard cubic feet) Pressure psi (pounds per square inch) or inches of water Temperature °F (degree Fahrenheit) Gas Flow Rate MMscfd (million standard cubic feet per day) Sales Oil Flow Rates STB/d (stock tank barrel per day) Water Flow Rate bpd (barrel per day) Chemical Flow Rate gph (gallon per hour) Viscosity cP (centipoise) Vessel and Tank Levels % (percent) Mass Ib (pound) Rotational Speed rpm (revolutions per minute) Current A (ampere) Voltage V (volt) Power HP (horsepower) or kW (kilowatt) Gas Gravity SG (specific gravity) Oil Gravity 'API (API gravity) Standard Conditions 60°F and 14.67 psis (pounds per square inch absolute) 6.0 MEASUREMENT PROJECT ACTIVITIES AND REQUIREMENTS 6.1 General This document describes the oil metering system that will be installed for the new GMT1 drillsite development. Attach 2 GMT1 Flow Measurement and Metering Phil osophy_Rev1.doc W 6.3 GREATER MOOSES TOOTH 1 'tom' ConocoP III' $ FLOW MEASUREMENTAND METERING PHILOSOPHY DATE: 219116 P - THREE PHA SEPRODUCTIONSEPARATOR OIL Alaska MEASUREMENT RE!! I PAGE 15 OF 17 Metering station design shall be according to all relevant specifications with respect to vessels, piping, pipe supports, valves, materials, surface protection, insulation, heat tracing, weather protection etc. and the metering stations shall be manufactured such that they are suitable for the climatic conditions at the field location. Design Measurement system design as well as operational and maintenance activities will be based upon state and federal regulatory requirements and agreements as well as the ConocoPhillips standards. This GMT1 Metering Philosophy supports the operating goals, so metering systems must allow for scalable throughput, occasional turndown, minimally disruptive maintenance, and periodic verification as dictated by regulations and commercial agreements. Single point of failure outages that significantly affect throughput or increased measurement uncertainty are to be avoided, and critical devices and equipment must be installed with redundancy. Meter runs shall be installed using practices that reduce or eliminate uncertainty that may occur due to the effects of piping arrangements, and will facilitate maintenance while minimizing requirements for excessive disassembly, associated labor costs and HSE risks. Bypasses around custody transfer/ PRM are generally not allowed. Bypasses built into the design for operational flexibility shall be car sealed closed. For accurate product measurement, it is necessary to provide means of fluid measurement and calculation, as well as determination of fluid quality at appropriate points throughout the process. Pressure and temperature compensation shall be applied to all applicable volumetric measurements. Fluid quality measurement instruments or sampling systems shall be installed for each significant fiscal measurement. Measurement verification dictated by commercial agreements and regulatory requirements may be accomplished in part via application of advanced electronics and systems diagnostics. Communication links to smart instrumentation shall be installed to collect data, maintain and verify devices, support record keeping, report and document failures and malfunctions, and assist with overall reporting and compliance. General Installation Requirements All instruments, including meters and analyzers, shall be located so as to be readily accessible for repair, or adjustment from operating level. Maintenance access shall normally be accomplished by mounting of instruments and manifold valves on stands such that they are accessible from grade. Where measurement accuracy or other physical conditions require close—coupled instruments in a location not accessible from grade, an access platform shall be provided. Instruments shall be installed and mounted rigidly and normal to the vertical or horizontal plane and in such a manner that they may be removed without disturbing adjacent equipment, piping or tubing. All instruments, equipment and components shall be suitable for the maximum extreme environmental and climatic conditions in which they are installed. Protective housings or Attach 2 GMT1 Flow Measurement and Metering Phil osophy_Rev1.doc C:V! W lw�' ConocoPhillips Alaska GREATER MOOSES TOOTH I FLOW MEASUREMENTAND METERING PHILOSOPHY DATE: 2/9/16 — THREE PHASE PRODUCTION SEPARATOR OIL MEASUREMENT PAGE 16 OF 17 REV. I weather—hoods may be required. Instruments and sense lines containing process fluids shall have insulation, heat tracing, and/or seals where process fluids may undergo a change in phase due to exposure to ambient temperatures. All instruments, tubing, piping, fittings, instrument tags, instrument dials, etc., must be protected from physical damage, contamination by dirt, sand, or other foreign material during transport, storage, fabrication, painting, insulation and other assembly and construction activities. Dials, glasses, nameplates, etc. must be free of paint, insulation, protection residue and other defacing. Instrument Traceability The intent of instrument traceability is to obtain a permanent record and to verify that the instruments will measure, indicate and operate within tolerances guaranteed by the Supplier in accordance with the Instrument Specification and Data Sheets. Meter station transmitters and indicators shall be factory calibrated whenever possible and calibration sheets provided. All instrumentation with factory calibration will be subjected to functional checking. Shop verification check of instruments that cannot be field -checked shall be witnessed. Instruments shall meet the Supplier's published specifications, unless a prior written agreement has been made. All instruments supplied on package systems shall be calibrated and properly tagged. Calibration sheets for these package instrumentation systems shall be turned over prior to system checkout. Measurement System Fabrication and Testing Checks carried out during fabrication at vendor factories or facilities shall ensure that the delivered system will meet design performance targets and that all required documentation is available. The metering system's fabrication shall be ensured to meet the approved design and that all design and fabrication documentation is available. Performance targets shall be verified by calibration/factory acceptance test (FAT), and the tests shall be witnessed by appropriate stakeholders. All performance related documentation such as calibration certificates and verification check reports shall be available for review by stakeholders. Commissioning Commissioning activities ensure that performance targets achieved during fabrication are still achievable after equipment has been transported, installed and electrically connected. The performance targets shall be confirmed by instrument verification checks and site acceptance test (SAT) and appropriately witnessed by stakeholders. All installation/commissioning/verification/SAT documentation shall be available and properly retained. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Rev1.doc GREATER MOOSES TOOTH I *"` DATE: 2/9/16 COn+ocaPhll II s FLOW MEASUREMENT AND METERING PHILOSOPHY — THREE PHASE PROD UCTION SEPA RA TOR OIL Alaska MEASUREMENT PAGE 17 OF 17 REV. 1 6.7 Handover Handover requires close coordination. During this activity, punch list items are resolved and verified. For measurement systems, the Operator shall participate in the handover by reviewing and approving punch list items and ensure any rework is identified for corrective action. 6.8 Maintenance Operator shall ensure that all components of the measurement system are maintained in accordance with regulatory and/or contractual obligations. All instruments, flow computers, samplers, analyzers, and supporting equipment shall have a maintenance frequency for each piece of equipment that is agreeable to partners and regulators as appropriate. Calibration certificates shall be properly retained. 6.9 Test Equipment The calibration of all test equipment shall be checked before being used for any verification activity. If the test equipment is visibly damaged or the calibration certificate is over one year old, the equipment shall be sent to a qualified independent testing laboratory for certification. Test equipment recertification records shall be properly retained. The test instrument calibration check shall be recorded on a label, showing the date and the person or agency performing the check, and the label should be attached to the equipment in such a place that it is easily visible and not easily removed. All calibrations shall be performed using test equipment with accuracies at least one order of magnitude lower than the instrument being calibrated. 6.10 Audit Regular auditing of measurement systems will ensure compliance with regulatory and contractual requirements. The audit shall include checks of the measurement system's performance at current production rates and an assessment of activities required to maintain metering system performance at target levels. After conducting an audit, the audit findings/recommendations shall addressed/implemented within required time scales. The uncertainty calculations shall reflect current production rates and fluid properties. Revised uncertainty calculations shall be analyzed to identify any system modifications that may be required to maintain the target/contractual performance targets. The Operator shall support the auditing of measurement systems by third parties such as regulatory bodies and contractual partners, if required. Attach 2 GMT1 Flow Measurement and Metering Philosophy_Rev1.doc