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Home My WebLink AboutO 0840 0 Image Project o Order Cover P • i XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. ©� Order File Identifier Organizing (done) 7co,,lor AN Items: yscale Items: ❑ Poor Quality Originals: ❑ Other: /Two-sided Illlllllllllllillll DIGITAL DATA ❑ Diskettes, No. ❑ Other, No/Type: a„vnNaedea 1111111111111111111 OVERSIZED (Scannable) ❑ Maps: ❑ Other Items Scannable by a Large Scanner OVERSIZED (Non -Scannable) ❑ Logs of various kinds: NOTES: ❑ Other:: BY: Maria Date: q s /s/ Project Proofing II I II'III I I III II III BY: Maria Date: CA / 3 /s/ Mr Scanning Preparation x 30 = + = TOTAL PAGES f o� /- (Count does not include cover sheet) �n BY: Maria Date: � Ilo / 3 /s/ / r t Production Scanning Stage 1 Page Count from Scanned File: I a 7 (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: _ZYES NO BY: Maria Date: Gll W) /,3 /s/ M P Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. II I III II I II II I I III ReScanned IIIIIIIIIIIIII IIIII BY: Maria Date: /s/ Comments about this file: Quality Checked III IIIIIIIIIII�I III 1/17/2012 Orders File Cover Page.doc • • INDEX OTHER ORDER NO. 84 Case No. 3AN-06-8446CI 1. January 18, 2008 Testimony before Legislative body by Commissioner Foerster 2. November 18, 2010 Subpoena to Commissioner Foerster 3. December 15, 2010 BPXA's Re -Notice of Taking Deposition Duces Tecum of Commissioner Foerster 4. July 6, 2011 Email regarding pressure data public records 5. July 7, 2011 Dr. Aubert Correction of Deposition testimony INDEX OTHER ORDER NO. 84 Case No. 3AN-06-8446CI m u 13 14 15 16 17 18 19 20 21 22 23 24 25 1 2 3 4 5 6 7 8 9 10 11 12 13 NL11-176 - SoA v BP - W Aubert - 77unll (2).txt Northern Lights Realtime & Reporting, Inc. (907) 337-2221 WITNESS CERTIFICATE winton Aubert taken Tune 7, 2011 The State of Alaska V. BPXA; Case No. 3AN-09-6181 CI I hereby certify that I have read the foregoing deposition and accept it as true and correct, with the following exceptions: Page Line Description/Reason 75 1 Ito Loci- 'o w r'K. eo _ 2 2 Mete camwc w a f',r7 ,ie��m•ev(.T< 5 14 m o bL' (e ; of we o fi. /e Page 71 • M NL11-176 - SoA v IF W Augert - 77unll 2).txt 14 _� O0. K i a &.d 0 le- I a, 15 16 17 18 19 20 21 22 0107 toll vi(z 23 DATE WINTON AUBERT 24 (use additional paper to note corrections as 25 needed, dating and signing each one.) (SMM) Northern Lights Realtime & Reporting, Inc. (907) 337-2221 1 CERTIFICATE 2 I, SANDRA M. MIEROP, Notary Public 3 for the State of Alaska, and Certified Shorthand 4 Reporter, do hereby certify that the foregoing 5 proceedings were taken before me at the time and 6 place herein set forth; that the witness was sworn 7 to tell the truth; that the proceedings were 8 reported stenographically by me and later 9 transcribed by computer transcription; that the 10 witness requested signature; that the foregoing is 11 a true record of the proceedings taken at that 12 time; and that I am not a party to, nor do I have 13 any interest in, the outcome of the action herein 14 contained. 15 IN WITNESS WHEREOF, I have hereunto set Page 72 STWI LLi • • McMains, Stephen E (DOA) From: McMains, Stephen E (DOA) Sent: Wednesday, July 06, 2011 3:11 PM To: Ballantine, Tab A (LAW) Cc: Seamount, Dan T (DOA); Foerster, Catherine P (DOA); Diemer, Kenneth J (LAW); John K Norman Subject: RE: Inquiry re AOGCC data Attachments: Ballantine Pool Pressure.xls This excel sheet has all pool pressure data that we have in RBDMS. Confidential wells are not included, Steve Davies and I doubled checked. I have been importing these pressures into our computer database for years. Some data for 2011 is included in the table. If you don't want 2011 data do a reverse data sort in date column and delete 2011 data. From: Ballantine, Tab A (LAW) Sent: Wednesday, July 06, 2011 2:10 PM To: McMains, Stephen E (DOA) Cc: Seamount, Dan T (DOA); Foerster, Catherine P (DOA); Norman, John K (DOA); Diemer, Kenneth J (LAW) Subject: Inquiry re AOGCC data Hi Steve, Ken Diemer, one of the lawyers here that represents Revenue, is litigating the TAPS appeal. Demands for documents made to the state include this: "Please provide a copy of the Alaska Oil and Gas Conservation Commission (AOGCC) reservoir pressure data spreadsheet table(s) that contain public data extracted from Form 10-412 through year end 2010." When I saw that the reference to reservoir data, I called Winton who thought you might be able to help. Do we have this information? Thanks, Tab 0 0 1-Tw,M GQM SW=" Ora & Twomm. UZ ATDPANEYS AT LAW 39W C STREET 5tM Uol Mn V4-7= (9 m "scram Mx IN THE SUPERIOR COURT FOR THE STATE OF ALASKA THIRD JUDICIAL DISTRICT AT ANCHORAGE BP PIPELINES (ALASKA) INC., EXXONMOBIL PIPELINE COMPANY, UNOCAL PIPELINE COMPANY, CONOCOPHILLIPS TRANSPORTATION ALASKA, INC. and KOCH ALASKA PIPELINE COMPANY, LLC, Owners, and ALYESKA PIPELINE SERVICE COMPANY, as Agent for the Owners, FAIRBANKS NORTH STAR BOROUGH and CITY OF VALDEZ, Appellants/Cross-Appellants, vs. STATE OF ALASKA DEPARTMENT OF REVENUE, STATE ASSESSMENT REVIEW BOARD, and NORTH SLOPE BOROUGH, Appellees. Case No. 3AN-06-08446 CI (Consolidated 2007, 2008, 200 RE -NOTICE OF TAKING DEPOSITION DUCES TECUM OF CATHY FOERSTER, AOGCC To: Ken Dicmer, Asst. Attorney General State of Alaska Attorney General's Office YOU ARE HEREBY NOTIFIED that the deposition daces tecum of Cathy F oerster of the Alaska OR & Gas Conservation Commission, previously set on for December 16, 2010, will be taken on behalf of ExxonMobil Pipeline Company, Re -Notice of Taking Deposition of Cathy Fomter, AOGCC BP Pipelines (Alaska) Inc. v. State of Alaska, et al. Case No. 3AN-06-08446 CI Page 1 of 3 0 0 oDmN & TwAnm, LLC ATTORNEYS AT LAM' 3900 C STAM Stx'1'8 IGM Ai CcwaAce. ALAsrA "SW (OM Z74.7522 (907) 2e3-a32o PAX ConocoPhillips Transportation Alaska, Inc., BP Pipelines (Alaska) Inc., Unocal Pipeline Company, and Koch Alaska Pipeline Company, LLC, as owners and. taxpayers [the "TAPS Owners"], and Alyeska Pipeline Service Company as agent for the Owners/Taxpayers, before a court reporter duly authorized to take depositions in the State of Alaska at the offices of Hughes Gorski Seedorf Odsen & Tervooren, LLC, located at 3900 "C" Street, Suite 1001, Anchorage, Alaska 99503, on the 22nd day of December, 2010, commencing at the hour of 9:00 a.m. The deponent is required to bring with her accurate and complete copies of the items as listed in the attached Exhibit A, also attached to the subpoena issued to Ms. Foerster, which subpoena remains in full force and effect. You are invited to attend and put forth such interrogatories as you may elect. The oral examination will continue from day to day until completed. DATED at Anchorage, Alaska this 15th day of December, 2010. Associated Counsel: F. Steven Mahoney, Esq. MANLEY & BRAUTIGAM, PC Ralph H. Palumbo, Esq. SUMMIT LAW GROUP Michael Garatoni, Esq. GARATONI, BREEN & MALONE, INC. Dawn R. Gabel, Esq. STEPTOE & JOHNSON, LLP HUGHES GORSKI SEEDORF ODSEN & TERVOOREN, LLC Attorneys for ConocoPhillips Transportation Alaska, Inc., BP Pipelines (Alaska) Inc., ExxonMobil Pipeline Company, Unocal Pipeline Company, and Koch Alaska Pipeline Company, LLC, and Alyeska Pipeline Service Company as their Agent By; tt L9 .4 es M. Seedorf Alaska Bat No. 7710164 Re-Noticc of Taking Deposition of Cathy Foerster, AOGCC 6p pipelines (Alaska) Inc. v. State of Alaska, et al. Case No. 3AN-0"8446 CI Page 2 of 3 • liummCkAwastgow +Onsw & TEdnoaa 4, LLC A1K7+:AIaYs AT 4AW 3900 C STREET Sims IWI ANCN0RAC16 ALAS[A 99503 (M 276-7= t9QT176 4MO VAX CERTIFICATE OF SERVICE AND FONT I hereby certify that on the date below a true and correct copy of the foregoing document, prepared in font Times New Roman 13, was delivered via US Mail, as well as electronically by e-mail, to. Kenneth Diemer, Asst. Attorney General Steve D. DeVries, Asst. Attorney General Martin Schultz, Sr. Asst. Attorney General State of Alaska Department of Law Office of the Attorney General 1031 West 4'h Avenuc, Suite 200 Anchorage, AK 99501 William M. Walker, Esq. Craig Richards, Esq. Walker & Levesque, LLC 731 "N" Street Anchorage, AK 99501 Mauri Long, Esq. Jessica Dillon, Esq. Dillon & Findley 1049 W. 5th Avenue, Suite 100 Anchorage, AK 99501 A. Rene Broker, Borough Attorney Fairbanks north Star Borough, Law Department Administrative Center, 3rd floor Post Office Box 71267 Fairbanks, AK 99707-1267 Robin O. Brenna, Esq. Kevin Clarkson, Esq. Laura Gould, Esq. Brenna, Bell & Clarkson, PC 910 "N" Street, Suite 100 Anchorage, AK 99501 Robert M. Johnson, Esq. Wohlforth Johnson Brecht Cartledge & Brooking 900 Wcst 5 Avenue, Suite 600 Anchorage, AK 99501 Courtesy copy to: Tab Ballentine, Esq. via e-mail Re -Notice of Taking Deposition of Cathy Foerster, AOGCC BP Pipelines (Alaska) Inc. v. Slate of Alaska, et al. Case No. 3AN-06-08446 CI Page 3 of 3 0 • EXHIBIT A to Re- Notice of Taking Deposition Duces Tecum of Catby Foerster, AOGCC l , Any and all documents, to include reports, notes, telephone conference records, electronic memoranda, letters, e-mails, correspondence (to include inter -office and inter -departmental correspondence or memoranda), that refer, reflect, relate or pertain to the negotiation, drafting, meaning, approval, current tariffs requested or approved for transportation of crude oil through the Trans Alaska Pipeline. 2: Any and all documents, to include reports, notes, telephone conference records, electronic memoranda, letters, e-mails, correspondence (to include inter -office and inter -departmental correspondence or memoranda), that refer, reflect, relate or pertain to future or projected tariffs for transportation of crude oil through the Trans Alaska Pipeline. 3 Documents sufficient to show the AOGCC (or "Commission") estimates of the projections of oil and gas production from the Prudhoe Bay Unit, the Kuparuk River Unit and the Colville River Unit (by field or pool as that data is collected and maintained by the Commission) as reported or utilized by the Commission in decision making for each of the year ends 2005, 2006, 2007, 2008, and 2009. 4.,, All communications and other documents generated or received by the Commission showing or containing comments, calculations, estimates, or notes 4elated ii , or comments on, estimates of ANS crude oil production included in the Revenue Sources Book containing Alaska Fall Forecasts for the 2005, 2006, 2007, 2008, 2009 and 2010 years.' 5. Documents sufficient to show the production estimates used by the AOGCC or if provided to the AOGCC those used by any State of Alaska Agency or Department, which show decline curve analysis used to support the production estimates for the Prudhoe Bay Unit, the Kuparuk River Unit and the Colville River Unit (by field or pool as that data is collected and maintained by the Commission) for the years ended 2005, 2006, 2007, 2008, and 2009 years. 6. Documents sufficient to show and referencing or relating to, or memorializing discussions with field operators of the Prudhoe Bay Unit, the Kuparuk River Unit and the Colville River Unit showing reserve estimates or production forecasts for each of the years ended 2005, 2006,.2007, 2008, and 2009. 7. Documents sufficient to show expected reservoir performance and the production estimates for the Prudhoe Bay Unit, the Kuparuk River Unit and the Colville River Unit (by field or pool as that data is collected and maintained by the Commission) for each of the years ended 2005, 2006, 2007, 2008, and 2009. 8. Documents sufficient to show presentations or reports provided during, or memorializing or summarizing briefings provided to the Governor regarding oil reserves and or production Exhibit A to Re -Notice of Deposition of Cathy Foerster, AOGCC BP Pipelines (Alaska) Inc. v. State of Alaska, et al. Case No. 3AN-05-08446 CI Page 1 of 2 7' forecasts for the Prudhoe Bay Unit, the Kuparuk River Unit and the Colville River Unit (by field or pool as that data is collected and maintained by the Commission) for each of the years ended 2005, 2006, 2007, 2008, and 2009, 9. Documents sufficient to show presentations or reports provided, or memorializing or summarizing briefings provided to, the Alaska Legislature regarding oil reserves and or production forecasts for the Prudhoe Bay Unit, 1&e'Xti*uk River Unit and the Colville River Unit (by field or pool as that data is collected and maintained by the Commission) for each of the years ended 2005, 2006, 2007, 2008, and 2009. 10. Documents sufficient to show (after 2005) presentations or reports provided, or memorializing or summarizing briefings provided to, the Governor and or the Alaska Legislature regarding the definitions commonly used by the AOGCC, the State of Alaska, the Petroleum Industry, Petroleum Engineers, and the Department of Revenue in its Revenue Sources Book as "potential relate to the terms "reserves", "proved reserves", "proven reserves", ' ten reserves, 1"developed reserves", "undeveloped reserves" or any combination of the preceding. 11. Documents sufficient to show (after 2005) presentations or reports provided, or memorializing or summarizing briefings provided to, the Governor and or the Alaska Legislature regarding estimates and impacts on ANS crude oil production and crude oil reserves as a result of the potential construction and operation of a major sales gas pipeline from the North Slope of Alaska to market- 12. Documents sufficient to show calculations and or estimates that reflect o bfa—t8 to the economic life of the ANS crude oil reserves that feed the TAPS pipeline from 200=gh the cite of the response to this request. 13. Reports prepared by any State-C,ontractor for ANS showing crude oil reserve estimates or forecasts for the Prudhoe Bay Unit, the Kuparuk River Iiiiit and the Colville River Unit (by field or pool as that data is collected and maintained by the Commission) for the years ended 2005, 2006, 2007, 2008, and 2009 years. 14. All annual plan of development reports filed by ANS oil producers for the Prudhoe Bay Unit, the Kuparuk River Unit and the Colville River Unit (by field or pool as that data is collected and maintained by the Commission) for the years ended 2005, 2006, 2007, 2008, and 2009 years.. 15. All well -head production data,!, maintained by the AOGCC for the ANS for the years 2005-2010. 16, Documents" sufficient to show-A�QGCC reports and analysis _relating to the volume and recoverability of ANSI crude oil reserves for the Prudhoe Bay Unit, the Kuparuk River Unit and the Colville River Unit (by field or pool as that data is collected and maintained by the Commission) for the years ended 2005, 2006, 2007, 2008, and 2009 years. ( - - 17. Documents sufficient to show any analysis or conclusions or findings of the AOGCC as \Telates to altemative methods of transportation of crude oil produced from the ANS.. Exhibit A to Re -Notice of Deposition of Cathy Foerster, AOGCC BP Pipelines (Mask o Inc. v. State of Alaska, et al. Case No. 3AN-06-08446 Cl Page 2 of 2 # 2 0 AECEIVED MEMORANDUM,.�63S cons.'OV192010 II UGIIES CORSKI SEEDtistjif ORF ODSEN & TE�RVOORES, LLC AnOo age E.i. 1939 j� To: Cathy Foerster, Alaska Oil & Gas Conservation Commission From: Linda Vinson, Legal Assistant to James M. Seedorf Hughes Gorski Seedorf Odsen & Tervooren, LLC Date: November 19, 2010 Re: TAPS Ad Valorem Tax Matter Case No. 3AN-06-8446 Cl Attached for reference is a copy of a subpoena served upon you November 18, 2010. The witness fee check was inadvertently omitted from the service copy. Therefore the witness fee check in the amount of $25 is attached. Please call 263-8272 should you have any questions. NORTHRIM BANK ANCHORAGE.ALASKA 89 - 93 / 1252 **Twenty five and Oi TO 'rHE Cathy Foerster HUGHES GORSKI SEEDORF Check Number Date ODSEN & TERVOOREN, LLC • 182387 11/17/2010 ATTORNEYS AT LAW --� 3900 "C" STREET, STE. 1001 • ANCHORAGE AK PHONE (907) 274-7522 • FAX (907) 263-8320 FED. ID #92-0041193 _CARS*** Amount\� V \� $25.00 �� I �� I��III lul!��` t ��i�illliiluliuilwiidullu�Uia . 0 I. r GENERAL ACCOUNT V L8 238?0 is L 25 20093Lo: 0160L,00206111 HUGHES GORSKI SEEDORF ODSEN & TERVOOREN, LLC Paid to: Cathy Foerster Check # 182387 Invoice Payment Offsets Vendor ID Invoice Number Description Payment Amt 805788 9149CM2 Witness fee re: Subpoena for taking depostion of 25.00 Cathy Foerster, AOGCC 25.00 0 • IN THE SUPERIOR COURT FOR THE STATE OF ALASKA FIRST JUDICIAL DISTRICT AT KETCHIKAN BP PIPELINES (ALASKA) INC, et al., Appellants/ Cross -Appellants, VS. STATE OF ALASKA DEPARTMENT OF REVENUE, et al. Appellees. Case No. 3AN-06-8446 Cl SUBPOENA DUCES TECUM To: Cathy Foerster, Alaska Oil & Gas Conservation Commission ("AOGCC'°) Address: Anchorage, AK 99501 You are commanded to appear and testify under oath in the above case at: Date and Time: December 16, 2010, at 9:00 am. Offices of: Hughes Gorski Seedorf Odsen & Tervooren, LLC Address: 3900 "C" Street, Suite 1001; Anchorage, AK 99503 Notice, as required by Civil Rule 45(d), has been served upon All Counsel of Record, on Novemb 2010. You are ordered to bring with you: All documents / items as outlined and listed in Exhibit A. /� _ - i / .4`.••••••,••'p� Date �— Subpoena issued at request of: James M. Seedorf/ Hughes Gorski et. al. Attorney for TAPS Owners Address:. 3900 C St Ste 1001 Anch AK 99503 Telephone: (907) 263-8228 If you have any questions, contact the person named above. Before this subpoena may be issu s information must be filled in and p presented to the clerk that a notice to take has been served upon opposing counsel. RETURN I certify that on the date stated below, I served this subpoena on the person to whom it is addressed, , in Anchorage, Alaska. I left a copy of the subpoena with the person named and also tendered mileage and witness fees for one day's court attendance. Date and Time of Service Service Fees: Service Mileage $ TOTAL $ If served by other than a peace officer, this return must be notarized. Subscribed and sworn to or affirmed before me at Signature Print or Type Name Title Alaska on Clerk of Court, Notary Public or other person authorized to administer oaths. My commission expires CIV-115 (8/96) (st.3) SUBPOENA FOR TAKING DEPOSITION Civil Rule 45(d) 0 EXHIBIT A to Notice of Taking Demotion Duces Tecurn of Cathy Foerster, AOGCC 1. Any and all documents, to include reports, notes, telephone conference records, electronic memoranda, letters, a -mails, correspondence (to include inter -office and inter -departmental correspondence or memoranda), that refer, reflect, relate or pertain to the negotiation, drafting, meaning, approval, current tariffs requested or approved for transportation of dude oil through the Trans Alaska Pipeline. 2. Any and all documents, to include reports, notes, telephone conference records, electronic memoranda, letters, a -mails, correspondence (to include inter -office and inter -departmental correspondence or memoranda), that refer, reflect, relate or pertain to future or projected tariffs for transportation of crude oil through the Trans Alaska Pipeline. 3. All documents that are collected and used to generate projections of oil and gas production by field (or pool) as reported in the Alaska Fall Forecast for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 4. All documents collected for or created for the decline curve analysis used to support the production estimates in the Alaska Fall Forecast for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 5. All notes of, or documents referencing or relating to, or memorializing discussions with field operators as reported in the Alaska Fall Forecast for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 6. All documents containing the public and private information developed by, provided to or obtained by the engineering consultant or any other person who assembled the long range production forecast as reported in the Alaska Fall Forecast for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 7. All documents reflecting reservoir perfomlance to support the production estimates in the Alaska Fall Forecast for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 8. All documents used to determine the production currently under development as reported in the Alaska Fall Forecast for the 2005, 20061,2007, 2008, 2009 and 2010 years. 9. All documents provided during, or memorializing or summarizing briefings provided to the Governor regarding oil reserves and or production forecasts from 2005 through the date of the response to this request. Exhibit A to Notice of Deposition of Cathy Foerster, AOGCC BP Pipelines (Alaska) Inc. v State of Alaska, et al. Case No. 3AN-06-09446 CI Page 1 of 2 0 • 10. All documents provided during or memorializing or summarizing briefings provided to the legislature from 2005 through the date of the response to this request. 11. All documents provided during or memorializing or summarizing briefings provided to professional societies from 2005 through the date of the response to this request. 12. All documents provided during or memorializing or summarizing briefings provided to business organizations from 2005 through the date of the response to this request. 13. All documents provided during or memorializing or summarizing briefings provided to bond rating agencies from 2005 through the date of the response to this request. 14. All documents that reflect or relate to the economic life of the reserves that feed the pipeline from 2005 through the date of the response to this request. 15. Reports prepared by the State Contractor for Reserves Forecasting for 2005 through 2010. 16. All presentations made by State Contractor for Reserves Forecasting to the Department of Revenue for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 17. All reports filed by ANS oil producers regarding lease development for years 2005-2010. 18. All well -head data maintained by the AOGCC for the ANS for the years 2005-2010. 19. All AOGCC reports and analysis relating to the volume and recoverability of ANS reserves from 2005 through the date of the response to this request. 20. All other documents in your possession related to the amount, recoverability, economic feasibility, or transportation of ANS reserves from 2005 through the date of the response to this request. 21. All other documents in your possession that relate to oil field economics as relate to ANS reserves and/or the operation of TAPS from 2005 through the date of the response to this request. 22. Any and all documents in your possession related to Plan of Development reports. Exhibit A to Notice of Deposition of Cathy Foerster, AOGCC BP Pipelines (Alaska) Inc. v. State of Alaska, et al. Case No. 3AN-06-08446 CI Page 2 of 2 I 0 0 IN THE SUPERIOR COURT FOR THE STATE OF ALASKA FIRST JUDICIAL DISTRICT AT KETCHIKAN BP PIPELINES (ALASKA) INC, et al., Appellants/ Cross -Appellants, VS. STATE OF ALASKA DEPARTMENT OF REVENUE, et al. Appellees. Case No. 3AN-06-8446 CI SUBPOENA DUCES TECUM To: Cathy Foerster, Alaska Oil & Gas Conservation Commission ("AOGCC") Address: Anchorage, AK 99501 You are commanded to appear and testify under oath in the above case at: Date and Time: December 16, 2010, at 9:00 a.m. Offices of: Hughes Gorski Seedorf Odsen & Tervooren, LLC Address: 3900 "C" Street, Suite 1001; Anchorage, AK 99503 Notice, as required by Civil Rule 45(d), has been served upon All Counsel of Record, on N 2010. You are ordered to bring with you: All documents / items as outlined and listed in Exhibit A. _ lI �� 1/YV N/ % , r� All f V Date Subpoena issued at request of - James M. Seedorf/ Hughes Gorski et. al. Attorney for TAPS Owners Address: 3900 C St Ste 1001 Anch AK 99503 Telephone: (907) 263-8228 If you have any questions, contact the person named above. Before this subpoena may be issue'G�y information must be filled in and pr presented to the clerk that a notice to take has been served upon opposing counsel. RETURN I certify that on the date stated below, I served this subpoena on the person to whom it is addressed, , in Anchorage, Alaska. I left a copy of the subpoena with the person named and also tendered mileage and witness fees for one day's court attendance. Date and Time of Service Service Fees: Service Mileage $ TOTAL $ If served by other than a peace officer, this return must be notarized. Subscribed and swom to or affirmed before me at Signature Print or Type Name Title Alaska on Clerk of Court, Notary Public or other person authorized to administer oaths. My commission expires CIV-115 (8/96) (st.3) SUBPOENA FOR TAKING DEPOSITION Civil Rule 45(d) EXHIBIT A to Notice of Taking Deposition Duces Tecum of Cathy Foerster, AOGCC 1. Any and all documents, to include reports, notes, telephone conference records, electronic memoranda, letters, e-mails, correspondence (to include inter -office and inter -departmental correspondence or memoranda), that refer, reflect, relate or pertain to the negotiation, drafting, meaning, approval, current tariffs requested or approved for transportation of crude oil through the Trans Alaska Pipeline. 2. Any and all documents, to include reports, notes, telephone conference records, electronic memoranda, letters, e-mails, correspondence (to include inter -office and inter -departmental correspondence or memoranda), that refer, reflect, relate or pertain to future or projected tariffs for transportation of crude oil through the Trans Alaska Pipeline. 3. All documents that are collected and used to generate projections of oil and gas production by field (or pool) as reported in the Alaska Fall Forecast for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 4. All documents collected for or created for the decline curve analysis used to support the production estimates in the Alaska Fall Forecast for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 5. All notes of, or documents referencing or relating to, or memorializing discussions with field operators as reported in the Alaska Fall Forecast for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 6. All documents containing the public and private information developed by, provided to or obtained by the engineering consultant or any other person who assembled the long range production forecast as reported in the Alaska Fall Forecast for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 7. All documents reflecting reservoir performance to support the production estimates in the Alaska Fall Forecast for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 8. All documents used to determine the production currently under development as reported in the Alaska Fall Forecast for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 9. All documents provided during, or memorializing or summarizing briefings provided to the Governor regarding oil reserves and or production forecasts from 2005 through the date of the response to this request. Exhibit A to Notice of Deposition of Cathy Foerster, AOGCC BP Pipelines (Alaska) Inc. v. State of Alaska, et al. Case No. 3AN-06-08446 CI Page 1 of 2 10. All documents provided during or memorializing or summarizing briefings provided to the legislature from 2005 through the date of the response to this request. 11. All documents provided during or memorializing or summarizing briefings provided to professional societies from 2005 through the date of the response to this request. 12. All documents provided during or memorializing or summarizing briefings provided to business organizations from 2005 through the date of the response to this request. 13. All documents provided during or memorializing or summarizing briefings provided to bond rating agencies from 2005 through the date of the response to this request. 14. All documents that reflect or relate to the economic life of the reserves that feed the pipeline from 2005 through the date of the response to this request. 15. Reports prepared by the State Contractor for Reserves Forecasting for 2005 through 2010. 16. All presentations made by State Contractor for Reserves Forecasting to the Department of Revenue for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 17. All reports filed by ANS oil producers regarding lease development for years 2005-2010. 18. All well -head data maintained by the AOGCC for the ANS for the years 2005-2010. 19. All AOGCC reports and analysis relating to the volume and recoverability of ANS reserves from 2005 through the date of the response to this request. 20. All other documents in your possession related to the amount, recoverability, economic feasibility, or transportation of ANS reserves from 2005 through the date of the response to this request. 21. All other documents in your possession that relate to oil field economics as relate to ANS reserves and/or the operation of TAPS from 2005 through the date of the response to this request. 22. Any and all documents in your possession related to Plan of Development reports. Exhibit A to Notice of Deposition of Cathy Foerster, AOGCC BP Pipelines (Alaska) Inc. v. State of Alaska, et al. Case No. 3AN-06-08446 CI Page 2 of 2 • 0 HUGHES GORSKI SEEDORF ODSEN & TERVOOREN, LLC ATTORNEYS AT LAW 3900 C STREET SUITE 1001 ANCHORAGE, ALASKA 99503 (907)274-7522 (907) 263-8320 FAx IN THE SUPERIOR COURT FOR THE STATE OF ALASKA THIRD JUDICIAL DISTRICT AT ANCHORAGE BP PIPELINES (ALASKA) INC., EXXONMOBIL PIPELINE COMPANY, UNOCAL PIPELINE COMPANY, CONOCOPHILLIPS TRANSPORTATION ALASKA, INC. and KOCH ALASKA PIPELINE COMPANY, LLC, Owners, and ALYESKA PIPELINE SERVICE COMPANY, as Agent for the Owners, FAIRBANKS NORTH STAR BOROUGH and CITY OF VALDEZ, Appellants/Cross-Appellants, vs. STATE OF ALASKA DEPARTMENT OF REVENUE, STATE ASSESSMENT REVIEW BOARD, and NORTH SLOPE BOROUGH, Appellees. Case No. 3AN-06-08446 Cl (Consolidated) 2007, 2008, 2009 NOTICE OF TAKING DEPOSITION DUCES TECUM OF THE CATHY FOERSTER, AOGCC To: Ken Diemer, Asst. Attorney General State of Alaska Attorney General's Office YOU ARE HEREBY NOTIFIED that the deposition duces tecum of Cathy Foerster of the Alaska Oil & Gas Conservation Commission will be taken on behalf of ExxonMobil Pipeline Company, ConocoPhillips Transportation Alaska, Inc., Notice of Deposition of Cathy Foerster, AOGCC BP Pipelines (Alaska) Inc. v. State of Alaska, et al. Case No. 3AN-06-08446 CI Page 1 of 3 of HUGHES GORSKI SEEDORF DDSEN & TERVOOREN, LLC ATTORNEYS AT LAW 3900 C STREET SUITE 1001 4NCHOKAGE, ALASKA 99503 (907) 274-7522 (907) 263-8320 FAx BP Pipelines (Alaska) Inc., Unocal Pipeline Company, and Koch Alaska Pipeline Company, LLC, as owners and taxpayers [the "TAPS Owners"], and Alyeska Pipeline Service Company as agent for the Owners/Taxpayers, before a court reporter duly authorized to take depositions in the State of Alaska at the offices of Hughes Gorski Seedorf Odsen & Tervooren, LLC, located at 3900 "C" Street, Suite 1001, Anchorage, Alaska 99503, on the 16th day of December, 2010, commencing at the hour of 9:00 a.m. The deponent is required to bring with her accurate and complete copies of the items as listed in the attached Exhibit A. A subpoena will issue, a copy of which is attached. The subpoena will remain in full force and effect should the date and/or time of this deposition change. You are invited to attend and put forth such interrogatories as you may elect. The oral examination will continue from day to day until completed. DATED at Anchorage, Alaska this 17th day of November, 2010. Associated Counsel: F. Steven Mahoney, Esq. MANLEY & BRAUTIGAM, PC Ralph H. Palumbo, Esq. SUMMIT LAW GROUP Michael Garatoni, Esq. GARATONI, BREEN & MALONE, INC. HUGHES GORSKI SEEDORF ODSEN & TERVOOREN, LLC Attorneys for ConocoPhillips Transportation Alaska, Inc., BP Pipelines (Alaska) Inc., ExxonMobil Pipeline Company, Unocal Pipeline Company, and Koch Alaska Pipeline Company, LLC, and Alyeska Pipeline Service Company as their Agent By: J mes M. Seedorf Alaska Bar No. 771 Notice of Deposition of Cathy Foerster, AOGCC BP Pipelines (Alaska) Inc. v. State of Alaska, et al. Case No. 3AN-06-08446 CI Page 2 of 3 HUGHES GORSKI SEEDORF :)DSEN & TERVOOREN, LLC AT AT LAW 3900 C STREET SUITE 1001 %NCHORAGE, ALASKA 99503 (907)274-7522 (907) 263-8320 FAX CERTIFICATE OF SERVICE AND FONT I hereby certify that on the date below a true and correct copy of the foregoing document, prepared in font Times New Roman 13, was delivered via US Mail, as well as electronically by e-mail, to: Kenneth Diemer, Asst. Attorney General Steve D. DeVries, Asst. Attorney General State of Alaska Department of Law Office of the Attorney General 1031 West 4th Avenue, Suite 200 Anchorage, AK 99501 William M. Walker, Esq. Craig Richards, Esq. Walker & Levesque, LLC 731 "N" Street Anchorage, AK 99501 Mauri Long, Esq. Jessica Dillon, Esq. Dillon & Findley 1049 W. 5th Avenue, Suite 100 Anchorage, AK 99501 Dated this I Kday of v ber, 2010. c .� Notice of Deposition of Cathy Foerster, AOGCC BP Pipelines (Alaska) Inc. v. State of Alaska, et al. Case No. 3AN-06-08446 CI Rene Broker, Borough Attorney Fairbanks North Star Borough, Law Department Administrative Center, 3rd floor Post Office Box 71267 Fairbanks, AK 99707-1267 Robin O. Brenna, Esq. Anthony Gurriero, Esq. Brenna, Bell & Clarkson, PC 810 "N" Street, Suite 100 Anchorage, AK 99501 Robert M. Johnson, Esq. Wohlforth Johnson Brecht Cartledge & Brooking 900 West 5 Avenue, Suite 600 Anchorage, AK 99501 Page 3 of 3 a, EXHIBIT A to Notice of Taking Deposition Duces Tecum of Cathy Foerster, AOGCC 1. Any and all documents, to include reports, notes, telephone conference records, electronic memoranda, letters, e-mails, correspondence (to include inter -office and inter -departmental correspondence or memoranda), that refer, reflect, relate or pertain to the negotiation, drafting, meaning, approval, current tariffs requested or approved for transportation of crude oil through the Trans Alaska Pipeline. 2. Any and all documents, to include reports, notes, telephone conference records, electronic memoranda, letters, e-mails, correspondence (to include inter -office and inter -departmental correspondence or memoranda), that refer, reflect, relate or pertain to future or projected tariffs for transportation of crude oil through the Trans Alaska Pipeline. 3. All documents that are collected and used to generate projections of oil and gas production by field (or pool) as reported in the Alaska Fall Forecast for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 4. All documents collected for or created for the decline curve analysis used to support the production estimates in the Alaska Fall Forecast for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 5. All notes of, or documents referencing or relating to, or memorializing discussions with field operators as reported in the Alaska Fall Forecast for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 6. All documents containing the public and private information developed by, provided to or obtained by the engineering consultant or any other person who assembled the long range production forecast as reported in the Alaska Fall Forecast for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 7. All documents reflecting reservoir performance to support the production estimates in the Alaska Fall Forecast for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 8. All documents used to determine the production currently under development as reported in the Alaska Fall Forecast for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 9. All documents provided during, or memorializing or summarizing briefings provided to the Governor regarding oil reserves and or production forecasts from 2005 through the date of the response to this request. Exhibit A to Notice of Deposition of Cathy Foerster, AOGCC BP Pipelines (Alaska) Inc. v. State of Alaska, et al. Case No. 3AN-06-08446 CI Page 1 of 2 10. All documents provided during or memorializing or summarizing briefings provided to the legislature from 2005 through the date of the response to this request. 11. All documents provided during or memorializing or summarizing briefings provided to professional societies from 2005 through the date of the response to this request. 12. All documents provided during or memorializing or summarizing briefings provided to business organizations from 2005 through the date of the response to this request. 13. All documents provided during or memorializing or summarizing briefings provided to bond rating agencies from 2005 through the date of the response to this request. 14. All documents that reflect or relate to the economic life of the reserves that feed the pipeline from 2005 through the date of the response to this request. 15. Reports prepared by the State Contractor for Reserves Forecasting for 2005 through 2010. 16. All presentations made by State Contractor for Reserves Forecasting to the Department of Revenue for the 2005, 2006, 2007, 2008, 2009 and 2010 years. 17. All reports filed by ANS oil producers regarding lease development for years 2005-2010. 18. All well -head data maintained by the AOGCC for the ANS for the years 2005-2010. 19. All AOGCC reports and analysis relating to the volume and recoverability of ANS reserves from 2005 through the date of the response to this request. 20. All other documents in your possession related to the amount, recoverability, economic feasibility, or transportation of ANS reserves from 2005 through the date of the response to this request. 21. All other documents in your possession that relate to oil field economics as relate to ANS reserves and/or the operation of TAPS from 2005 through the date of the response to this request. 22. Any and all documents in your possession related to Plan of Development reports. Exhibit A to Notice of Deposition of Cathy Foerster, AOGCC BP Pipelines (Alaska) Inc. v. State of Alaska, et al. Case No. 3AN-06-08446 CI Page 2 of 2 �1 0 • 1/18/2008 AOGCC TESTIMONY BEFORE SENATE RESOURCES COMMITTEE by Cathy Foerster, Commissioner Chairman Huggins, Vice-chairman Stedman, Senators Green, Stevens, McGuire, Wielechowski, and Wagoner. Thank you for inviting me here to talk with you about the Alaska Oil and Gas Conservation Commission, or AOGCC, and the work we are doing to help prepare the State for the eventual sales of our North Slope Gas resource. I will start with some background information that should help in understanding the big issues. First I'll give a brief description of the AOGCC's statutory responsibilities, just to put into perspective the small but important role we play in the State's quest to achieve North Slope gas sales. I'll then give a brief description of the main sources for North Slope gas sales in context with the Security and Exchange Commission, or SEC, 's reserves classifications, which will be important for the Federal Energy Regulatory Commission, or FERC, process. After that background information, I will give you what I hope to be a thorough and easy -to -follow description of the issues concerning us at Prudhoe Bay and Pt Thomson along with the status of our work in understanding and resolving those issues for each field. Then I will describe the process operators must use to get a gas sales allowable from the AOGCC. I will end with some take-home messages so that, long after you've forgotten all the boring engineering stuff I tell you, you can remember what I hope will assist you during your decision -making process. • • Before starting, I want to apologize in advance if I get too "enginerdy" in anything I tell you. Along those lines, Page 1 of the handout is a glossary of acronyms, just to help be sure I don't alphabet -soup you to death. And I want to urge you to interrupt me at any time with any questions you might have. If you'll refer to Page 2 of the handout, you'll see a list of the statutory responsibilities of the AOGCC. In our day-to-day regulatory oversight we are called upon to exercise all of these responsibilities in a variety of ways, and I'm sure the same will be true as we regulate operations relating to North Slope gas sales. But the two responsibilities I want to focus your attention on today are preventing waste of hydrocarbon resources and encouraging greater ultimate recovery of hydrocarbons. I ask you to keep these in mind as we proceed with the rest of this discussion. And I also ask you to keep in mind that nowhere in our list of responsibilities will you find mention of making the most money, balancing the budget, or making any set of constituents happy. You guys have the tough job — all we have to deal with is science. The second bit of background information we need to discuss is the reserves classifications of the SEC. Please refer to Page 4 of the handout. (Page 3_of the handout is included for those of you who want to see the exact SEC verbiage, but Page 4 is a boiled down version, and the one I'll be talking from.) For a gas pipeline open season, the FERC will only entertain nominations of gas reserves that are recognized by the SEC as proved. The 0 0 SEC breaks down proved reserves into two categories, proved developed and proved undeveloped. Proved developed reserves are hydrocarbons that can be demonstrated with reasonable certainty to exist, that are economically extractable using proven technologies and at current prices, and for which the wells have been drilled and the production equipment installed. Essentially all of the oil reserves at Prudhoe Bay and Kuparuk fall into this category. And for the sake of our gas discussion, the Prudhoe Bay gas cap would be considered proved developed. Proved undeveloped reserves are hydrocarbons that can be demonstrated with reasonable certainty to exist and that are economically extractable using proven technologies and at current prices. However, for proved undeveloped reserves, the wells have not been drilled nor has the production equipment been installed. BP's Liberty field would be considered to contain proved undeveloped reserves. But once they build the infrastructure and drill the wells, those reserves will move to the proved developed category. Again, for the sake of our gas discussion, Pt Thomson would be considered proved undeveloped. Those are the two classifications of reserves reported to the SEC and the ones that will play a role in an open season, but there is a third category of reserves that most companies keep track of internally but do not report to the SEC. Different companies have different names for this category, and some companies break it into more than one category. Regardless of what it is • called or how it is subdivided, this category is for hydrocarbons that do not meet the SEC definitions of proved developed or proved undeveloped. For our discussion, let's call these potential reserves. There is some level of uncertainty to the reserves in this category. You cannot demonstrate to the satisfaction of the SEC that the reserves exist and/or that they can be economically extracted using existing technologies. The Ugnu and some of the other heavy and viscous oils would fall into the various potential reserves categories. Although we can prove they exist, we cannot extract them economically using existing technologies. For the sake of our gas discussion, all of those yet -to -be -discovered gas fields on the North Slope can be considered potential reserves. And there are even a few discovered gas reservoirs, such as Shell's Burger prospect in the Chukchi Sea where they know there is gas but they don't know how much there is. All of these potential gas fields may or may not exist, they may or not be big enough to develop, and they may or may not be economically extractable using existing technologies. The SEC doesn't recognize them and the FERC will not consider them in an open season; but — if they are as plentiful as we hope and suspect — then they will be a very important part of the North Slope gas picture. And we need to keep them in mind as we move forward toward a North Slope gas pipeline. That concludes the background information I wanted to share with you; so let's dive into the meat of the matter. I've said that one of the pillars of our mission at the AOGCC is to ensure greater ultimate hydrocarbon recovery. For over thirty years, we've been • 0 working hard to ensure that the North Slope operators are maximizing oil production and to encourage them to achieve greater ultimate recovery of that oil. And, with a gas line on the horizon, we will soon be doing the same with natural gas. And as I just mentioned, there are three major sources of gas supply from the North Slope — the proved developed reserves at Prudhoe Bay, the proved undeveloped reserves at Pt Thomson, and the potential reserves in all of those yet -to -be -discovered gas fields. Let's look at each of these resources individually and also let's consider their interdependence. The first major gas source is the gas cap of the Prudhoe Bay oil pool. This resource is estimated at about 24 trillion cubic feet, or TCF. This is a huge resource which, all by itself, could fill a 4 BCF/D pipeline for over 15 years, assuming no decline. And remember, this resource will be proved developed once we have a gas pipeline. We know it's there, we know we can make money producing it, the infrastructure is in place, and the SEC will consider it during an open season. Given all of that, why are we not already selling this gas? For very good reasons. Every bit of that gas has been and is still being put to very good use for getting oil out of the ground, and not just at Prudhoe Bay but in other fields across the North Slope. Let me say that again just to be sure everyone heard what I said. Every bit of the gas at Prudhoe Bay has been and is still being put to VERY good use getting oil out of the ground at Prudhoe Bay and in other oil fields across the North Slope. And that use of the gas is the best use we could put it to. Period. • 0 The gas in the Prudhoe Bay gas cap is essential for oil production from Prudhoe Bay in a number of ways. Page 5 of the handout is a cartoon that illustrates how this works. First and most importantly the gas that is reinjected maintains the reservoir pressure needed to move the oil from the reservoir to the wellbore. Without reservoir pressure, there would be no oil production from Prudhoe Bay. About 7 BCF/D is reinjected for pressure maintenance. And before the gas is reinjected, natural gas liquids, or NGLs, are extracted from it. A portion of those NGLs are blended with oil and sold down the Trans -Alaska Pipeline. This blending process has already yielded about one half billion barrels of oil sold and is continuing to yield additional sales volumes. A second huge benefit of reinjecting this gas is that it strips oil out of the gas cap in a process called vaporization. This process is yielding about 2 billion of the total 13 billion barrels that we expect to recover from the Prudhoe Bay oil pool. Third, some of the gas that is produced from the Prudhoe Bay oil wells — about one third of a BCF/D — is mixed with NGLs and reinjected for enhanced oil recovery, or EOR, in the Prudhoe Bay oil pool and its satellites. FOR is yielding an additional one half billion barrels of oil from Prudhoe and its satellites. Additional gas and natural gas liquids are exported to other North Slope fields, such as North Star and Kuparuk, for their uses; so not only is the Prudhoe Bay gas increasing oil recovery from Prudhoe Bay and its satellites, • 0 but it is also contributing to the greater ultimate recovery of oil in other North Slope fields. Of course, some of the produced gas — less than half a BCF/D — is used for fuel to keep the infrastructure operating. Without the production equipment and other infrastructure running, there would be no oil production from Prudhoe Bay. Page 6 of the handout illustrates the contributions that the gas has made, and continues to make, to oil recovery at Prudhoe Bay alone. And remember, some of the gas is also at work in the other North Slope fields as well. If you believe what I've said so far, then your next question might be, "How will we know when the time is right to start selling that gas?" To answer that question you must take several things into consideration. So let's do that. First, since most of the gas is being used to maintain pressure in the Prudhoe Bay oil pool so that we can recover that huge oil resource, the later we start to sell the gas and the more aggressively BP has been producing the oil in the meantime, the less oil will be left and at risk of being lost to decreased pressure or other reservoir mechanisms associated with selling the gas. Second, we will want to continue FOR projects in Prudhoe Bay and other North Slope oil fields as long as they are yielding increased oil recoveries. Again, the later we start to sell gas and the more aggressively we have been producing the oil, the more likely we are to reap the full benefits of the FOR • 0 projects. But even after we commence North Slope gas sales, we can still use some of the available gas for EOR. Also, we will be generating CO2, carbon dioxide, as a byproduct of our natural gas production for sales, and this CO2 can and should be used as an FOR fluid either to augment or to replace the natural gas currently in use. Fuel use is the only use in which the gas is all gone once we're done using it. In the other uses, the gas has gone back into the Prudhoe Bay oil pool or another oil pool and most or all of it can be recovered as production of oil and gas continue. Since the fuel is gone once we use it, then obviously we will NOT want to be using the gas for fuel when we reach the point where the fuel we are burning has more value than the oil it is being used to produce. That said, we're a long way from that point. You will recall that the current fuel usage at Prudhoe Bay is about 460 MMCF/D. Using a simple 6 MCF/Bbl conversion, that is about 77 MBOE/D being used to produce approximately 395 MBO/D. In other words, every equivalent barrel of fuel is used to produce more than 5 barrels of oil; so we're still doing the right thing with the resource and will be for quite some time. Using a simple trend analysis, we will not be at a one -for -one ratio of fuel to production until after 2030. Last session I described to you a Prudhoe Bay reservoir study that the AOGCC had recently completed with the assistance of a reservoir engineering consultant and the cooperation of BP and the other Prudhoe Bay owners. I would say that the study was a success because it provided the AOGCC with insights and understandings of the Prudhoe Bay oil pool that will assist us in future Prudhoe Bay gas offtake allowable decisions. 0 The confidentiality agreement we signed prohibits me from sharing many of the details of that study, but I told you last session that, even if I could share the data with you, there is not one right answer for when and how much gas to sell. There will likely be oil losses in any gas sales scenario, but the amount of those oil losses depends on a number of variables. The smaller the volume of gas taken out of the gas cap for sales, the later we sell the gas, the more aggressively BP has been producing the oil, and the more (and more effective) the mitigation steps BP has enacted to prevent oil losses, the smaller those oil losses will be. One other thing to keep in mind is that the AOGCC does not typically dictate to operators what they must do. Rather, the operator typically comes to us with a request for permission to do something and we either allow it, disallow it, or allow some modification to the originally proposed plan. For instance, we do not tell Pioneer where or how deep to drill their Oooguruk wells. Rather, they send us a request to drill a particular well in a particular location to a particular depth using particular procedures. We either approve their request, deny it, or approve it subject to some limitations or modifications. The same will hold true for gas offtake allowables. We will not dictate to the Prudhoe Bay and Pt Thomson operators what volumes of gas to sell and when to start selling. Rather, they will come to us with a request to sell a certain volume starting at a certain date and we will allow it, disallow it, or only allow a smaller volume. I know some of you are still impatient for "the answer" — so let me give it to you: Everything I've said about later and lower rate being better is still true • E BUT, within reason, whenever we get a gas line and whatever gas sales volume — within reason — is called upon from Prudhoe Bay, it will be the right answer. Remember that there are 24 TCF in the Prudhoe Bay gas cap. Using the simple 6-to-1 gas -to -oil conversion, that means there are 4 billion barrels of oil equivalent in that gas cap. Remember, too, that as of today there is a bit less than 2 billion barrels of oil in the Prudhoe Bay oil rim. Also keep in mind that when we sell the gas we will not lose ALL of the remaining oil. Rather we will lose a fraction of it. Further, in any major gas sales scenario, it will be several years before sales can commence; so there will be less oil left in the oil rim and the operational steps BP uses to mitigate oil losses due to gas sales will be further developed. Thus we will be looking at losing a smaller fraction of a smaller number in exchange for getting 4 billion equivalent barrels of gas In other words, the "right answer" is that we will want to sell whatever volume is needed from Prudhoe Bay and we'll want to sell it whenever it is needed to ensure that the gas line is a go. But that right answer assumes that the Prudhoe Bay operator aggressively produces as much oil and puts in place as much mitigation for losses as possible before gas sales begin The second major gas source is Pt Thomson. The gas resource in Pt Thomson is estimated at about 9 TCF. This resource by itself could fill a 4 BCF line for another 6 years, assuming no decline. And remember, this resource is classified by the SEC as proved undeveloped. We know it's • 0 there, we feel confident that we can make money producing it, and the SEC will consider it during an open season. So what are our concerns at Pt Thomson? Most people think of and refer to Pt Thomson as a gas field but in engineering vernacular it is what we call a gas condensate reservoir or a retrograde condensate reservoir and, under the definitions in our regulations, it's an oil field. I won't drag you through all the technical explanations of what is going on in such a reservoir. If you want that explanation, you can refer to the handout titled "Role of the AOGCC in Approving Pool Rules for the Point Thomson Field." But let's go right to the bottom line of that handout. Looking simply at the technical issues — not getting into financial concerns or politics — cycling the gas until the liquids have been recovered is ALWAYS the way to achieve greater ultimate recovery and prevention of waste from a gas condensate reservoir. There are two important concerns in producing Pt Thomson as a gas reservoir without cycling first. Number One: a significant portion of the liquid hydrocarbons will drop out and be lost in the reservoir forever. Number two: these dropped out liquids will most likely cause increased operating costs and decreased gas recovery for the gas wells. Let's look first at the liquid hydrocarbon losses since the AOGCC is charged with ensuring greater ultimate hydrocarbon recovery and preventing hydrocarbon waste. Publicly available estimates of recoverable liquid hydrocarbons associated with the gas at Pt Thomson vary from 200 to 400 million barrels, depending on the source. Using our Prudhoe Bay logic, losing this resource would be a small price to pay to get the 9 TCF, or 1-1/2 billion BOE from selling the gas. However, we have time right now to be developing Pt Thomson, cycling the gas, and recovering those liquids. If we were doing that, then we could have both the liquid recovery in the interim AND the gas sales when the line is ready. And don't let me underemphasize the size of this liquid resource; it's the size of another Alpine Field. And if we were to recover those liquids through cycling in advance of gas sales, then the second concern would also go away. The second concern is that those liquids that drop out as the reservoir pressure drops will drop out in the place where the pressure is lowest — adjacent to the wellbores. When liquids drop out there, they damage the producibility of the reservoir and, thus, decrease the ability of the wells to bring the gas up to the surface. The operator can undo some of this damage through well interventions, but these cost money, must be repeated as additional damage is done, and eventually may no longer be effective at fixing the problem. This is important to the AOGCC because it will result not only in liquid losses, but also in gas resource losses. And it is important to the State for that reason AND because, under ACES, the State shares the cost of these interventions that will likely be done over and over to keep the gas wells producing. However, for fair and balanced reporting, I must also say that cycling will likely add significant capital costs, which the State would, again, share. • 0 The AOGCC is engaged in a study, similar to the one we conducted for Prudhoe Bay, to understand the Pt Thomson resource. We are in the very early stages of the study; so we have very little data and are far from having any conclusions. The Pt Thomson evaluation process used by ExxonMobil is more complex than what we used with BP for Prudhoe Bay; so we anticipate that it could be as long as another year before the study is complete. Even though the two reservoirs are completely different as are the two evaluation processes, we are optimistic that this study will also be a success and that at its conclusion we will have insights and understanding to help us make good regulatory decisions concerning development, operations, and gas offtake at Pt Thomson. For example, ExxonMobil has taken different positions on whether or not to cycle first for liquid recovery and their latest (I think) official position is not to cycle. At the completion of our study we expect to know enough about Pt Thomson to decide whether or not we agree with that position. Even without any results of the study, I can tell you one thing: Time is the important thing to keep in mind at Pt Thomson. Right now we have time to develop the field, produce the liquids, and cycle the gas. But the longer Pt Thomson remains undeveloped, the less time we will have. You may remember that I mentioned a third source of North Slope gas, all those yet -to -be -discovered gas fields. The USGS and the MMS estimate potential for over 150 TCF of conventional gas on the North Slope. Anadarko is exploring for gas this season; God bless them. The sooner we find new gas fields, and the more gas that we find, the less pressure there will be to accept oil losses at either Prudhoe Bay or Pt Thomson. And that gas will be necessary to give that gas pipeline longevity for our kids and grandkids. So please keep this third and very important gas source in mind as we move through your North Slope gas sales decisions. The last topic I was asked to address is the process by which an operator receives a gas offtake allowable from the AOGCC. Two scenarios trigger the AOGCC to take action. The first is responsive; we respond to a petition, or request, from an operator or other interested party. The second is proactive; we act of our own volition to prevent imminent waste. In the case of North Slope gas sales, there is no sales capability and, thus, no imminent waste. Therefore, we will respond to a petition from the Prudhoe Bay and Pt Thomson operators. For Prudhoe Bay, an existing pool with rules in place, the existing offtake allowable is 2.7 BCF/D. Should the operator want a larger allowable, they would have to request a change to the existing Rule 9 which set that offtake. For Pt Thomson, an undeveloped pool with no rules in place, a gas offtake allowable rule would be part of the greater process of determining all of the rules by which the pool would be developed and operated. Again the operator would recommend pool rules and request a determination by the Commission. In either case our technical staff would gather sufficient information to make recommendations and we would hold a hearing. For Prudhoe Bay we would likely have much of the information we need by virtue of the Prudhoe Bay study we completed in 2006. And, assuming a successful completion of the Pt Thomson study, the same would hold true there. At a hearing, the operator, our staff, and other interested parties would present to us all of the relevant technical information we need to reach a decision. We would take all the information presented and make a ruling. Let me close with a very few, brief take-home messages. And then I will gladly answer any other questions you might have. 1. By the time we get a gas line, the oil volume at risk at Prudhoe Bay will not be sufficient to derail a gas pipeline. So the "right answers" for timing and sales volume are, within reason, whenever and however much. However, in the meantime, the Prudhoe Bay operator must be accelerating the oil recovery aggressively, avoiding major, unplanned shut -downs, and developing and implementing strategies to mitigate oil losses. 2. At Pt Thomson, we have time to minimize the oil losses AND the operating cost tax deductions that would result from gas blowdown. But every day that goes by with Pt Thomson undeveloped whittles away at that opportunity. 3. We need new gas discoveries for the long-term success of the gas pipeline AND to help further diminish concern over oil losses at Prudhoe Bay and Pt Thomson. Thus, we must encourage those discoveries. Page 1 Acronym Glossary ACES — Alaska's Clear and Equitable Share AOGCC — Alaska Oil and Gas Conservation Commission BCF — billion cubic feet BOE — Barrel of oil equivalent CO2 — carbon dioxide FOR — enhanced oil recovery FERC — Federal Energy Regulatory Commission MCF — thousand cubic feet MMS — Minerals Management Service NGLs — natural gas liquids SEC — Security and Exchange Commission TCF — trillion cubic feet USGS — United States Geological Survey Page 2 AOGCC Statutory Responsibilities • Prevent hydrocarbon waste • Encourage greater ultimate hydrocarbon recovery • Protect correlative rights • Protect fresh groundwaters • Protect public health and safety Page 3 SEC Definitions for Proved Reserves (from the SEC website: rules, regulations, and schedules page) (2) Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. , prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. (i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas -oil and/or oil -water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. (iii) Estimates of proved reserves do not include the following: (A) Oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. 3) Proved developed oil and gas reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. (4) Proved undeveloped reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. Page 4 North Slope Gas Reserves Categories Proved Developed SEC Definition: hydrocarbons that can be demonstrated with reasonable certainty to exist, are economically extractable using proven technologies and at current prices, and for which the wells have been drilled and the production equipment installed. Examples: Prudhoe Bay oil, Kuparuk oil, other producing fields North Slope gas: Prudhoe Bay gas cap Proved Undeveloped SEC Definition: hydrocarbons that can be demonstrated with reasonable certainty to exist and that are economically extractable using proven technologies and at current prices, but for which the wells have not been drilled and/or the production equipment has not been installed. Examples: Liberty (BP's North Slope offshore development project east of Endicott), Pioneer's Oooguruk (until the wells are drilled) North Slope gas: Pt Thomson Potential Definition: Hydrocarbons that do not meet the SEC definitions of proved developed or proved undeveloped because the operator cannot demonstrate to the satisfaction of the Sec that the reserves exist and/or that they can be economically extracted using existing technologies at current prices. Examples: Ugnu, other viscous oils, Shell's Chukchi Sea Burger prospect North Slope gas: yet -to -be -discovered gas reservoirs, gas hydrates Senate Judiciary Committee Chair French Vice -chair Huggins Wielchowski McGuire Therriault Chairman French, Vice-chairman Huggins, Senators Wielechowski, McGuire, and Therriault: Thank you for your interest in the AOGCC and the work we are doing to help prepare the State for the eventual sales of our North Slope Gas resource. Also, thank you for allowing me to testify telephonically. I had knee surgery last week and my doctor says it's too soon for me to be traveling, but I can guarantee you that I would much rather be with you in Juneau than sitting here with my leg up in this freezing ice cuff. The AOGCC's role in North Slope gas sales is to ensure that these sales do not result in hydrocarbon waste, i.e., loss to the State of a very valuable non-renewable resource. To do this we will determine what gas offtake rates should be allowed from North Slope fields, most notably Prudhoe Bay and Point Thomson. Most Alaskans know that there have been about 35 trillion cubic feet of gas already discovered at just Prudhoe Bay and Point Thomson fields. However, very few people realize that hundreds of millions of barrels of oil and condensate could be lost if gas offtake from these fields is not correctly managed. Oil is our bird in the hand and gas is our bird in the bush. The AOGCC is here to ensure that we do not harm our bird in the hand while aspiring to grasp our bird in the bush. In general, maintaining reservoir pressure enhances oil recovery, but producing gas depletes reservoir pressure. Therefore, gas reserves in most fields are usually sold only after the liquid hydrocarbon reserves have been depleted. Until then, the gas that is produced is used to promote increased liquid production in various ways. For example, gas might be reinjected into the reservoir so that it can provide the energy needed to get the liquid hydrocarbons to the surface, or the gas might be used for enhanced oil recovery operations. In fact, both of those are happening right now at Prudhoe Bay and other North Slope fields. So when you hear "they're holding our gas hostage" that just isn't accurate — they're using our gas to get more oil AND the gas will still be there when we're ready to produce it. That said, the North Slope gas sales project will ultimately involve trade-offs between oil and gas recovery. In your information packets you should have (and the general public can find on our AOGCC website) two documents -- Role of the Alaska Oil and Gas Conservation Commission in Establishing an Allowable Gas Offtake Rate for Prudhoe Bay and Role of the Alaska Oil and Gas Conservation Commission in Managing Development of the Point Thomson Field - - that explain the trade-offs in these two fields. I'll let you read those on your own time, but I invite you or your staffs to call me with any questions they might evoke. Normally, the operator of an Alaskan oil or gas field applies to the AOGCC for "Pool Rules." These are specific rules that stipulate how to develop the reservoir in a way that maximizes oil and gas recovery. Prudhoe Bay is operating under Pool Rules that were established originally in the early 1970's shortly after the field was discovered and that have been modified numerous times since then to reflect necessary changes. However, for Point Thomson, the AOGCC has received no such application for Pool Rules. Rule 9, one of the existing Pool Rules for Prudhoe Bay set allowable gas offtake at 2.7 billion standard cubic feet, or BCF, of gas per day. That rule was established in 1977, before the field • was even on production. Thirty years and 11 billion barrels of oil later, the Prudhoe leaseholders have not applied for amendment of Rule 9 to allow for a higher gas offtake rate. Why is that important? Two reasons. First with all of the information we now have, we know a lot more about how the reservoir works and what an appropriate gas offtake would be. Second, almost all of the gas sales scenarios that are being discussed publicly, including the producers', would likely require increasing the Prudhoe gas offtake allowable. The AOGCC usually waits for an application from the operator before performing the reservoir studies necessary to establish or increase gas offtake rates. However, such studies can delay the AOGCC's decision -making, especially in complex reservoirs. In the case of Prudhoe Bay and Pt Thomson such a delay could disrupt the timetable for a potential gas pipeline project, and that is NOT a preferred outcome. The AOGCC needs to complete its evaluations and make its rulings for both Prudhoe Bay and Pt Thomson so we know what the approved gas offtake allowables are in time for the "open season" process that is required under the Federal Energy Regulatory Commission ("FERC") regulations. Therefore, the AOGCC has chosen a proactive approach. There are two ways the Commission might take a proactive role with respect to such studies. One would be to conduct or arrange for consultants to conduct independent reservoir studies. The other would be to participate with the operator and its partners in their reservoir simulation studies, so that questions can be answered and adjustments can be made up front. Assuming adequate cooperation on the part of the operator and its partners, the latter approach has significant advantages: lower cost to the State of Alaska, less time required to complete evaluation of the studies, more complete and • i accurate input data, and use of proven and highly sophisticated reservoir evaluation tools. In 2005 the Commission held hearings to inquire whether the gas offtake rate from Prudhoe should be updated. The AOGCC decided that, although the 1977 allowable was based on the best available data at the time, the appropriate gas offtake allowable must now be redetermined using the thirty years worth of reservoir description and performance information that has become available since 1977. Also as part of that hearing process, BP, its partners, and the AOGCC established principles by which to perform collaborative studies. The report of the inquiry and the resultant study principles were issued by the AOGCC on December 5, 2005. The AOGCC contracted reservoir evaluation consultants to assist its technical staff in performing the Prudhoe study. BP and its partners agreed to provide the AOGCC staff and consultants access to their simulators including the underlying engineering, geologic, and geophysical information. They voluntarily set up a data room in BP's Anchorage offices, equipped with computers and software allowing review of the simulator results. The AOGCC determined that the data and information offered met the standards of AS 31.05.035(d) and 20 AAC 25.537(b) entitling it to be held confidential during the study period. (The letter -number combo's I just gave you reference AOGCC statutes and regulations concerning providing information and maintaining confidentiality.) This study process began in January 2006, and was completed in late 2006. On February 28, 2007 the AOGCC technical staff presented to the AOGCC commissioners a summary report, which is in your information packets and is also available on the AOGCC website. Additional information is still being held confidential. At some future time prior to an open season, either BP and its partners will submit an application to amend the Prudhoe gas offtake allowable or the AOGCC will call for a hearing. In either case, the 0 0 AOGCC will hold public hearings to review the development plans associated with the proposed gas sales. BP and its partners will be required to submit for the record reservoir studies that best reflect a reasonable range of offtake options and their effects. The AOGCC may request (including by subpoena) any other pertinent information that has been used in the study but is not included in the BP and its partners' submission of evidence in the hearings. Claims of confidentiality for evidence in the hearings will be determined by the AOGCC during the course of the hearings under governing law. I feel very comfortable that, unless a substantial delay occurs, we will be adequately prepared to address Prudhoe Bay gas offtake allowable amendment when it comes before us. So now let's move to Pt Thomson, where that is anything but the case. On April 26, 2006 the AOGCC, ExxonMobil, and its parnters agreed upon a similar process for studying the allowable gas offtake from that field. The AOGCC contracted reservoir evaluation consultants to assist its technical staff in performing the Pt Thomson study. ExxonMobil and its partners agreed to give AOGCC staff and consultants access to a data room in ExxonMobil's Houston offices. It was agreed that the data room would include reservoir engineering, geologic and simulation information and would be equipped with computers and software allowing review of the simulator results. The study was to begin before September 2006 and last up to six months. ExxonMobil and its partners indicated that they planned to apply to the Commission in late 2006 or early 2007 for Pool Rules and a gas offtake allowable rate for Pt Thomson. Unfortunately we were not able to follow that time line. ExxonMobil had delays in preparing the data room and information. The process was finally slated to begin about the same time that the DNR found ExxonMobil and its partners to be in default on their leases. The AOGCC and its consultants attended one meeting where we received a very small fraction of the necessary data, and then ExxonMobil put the study on hold until they could get their legal issues sorted out. In February of 2007, I met with ExxonMobil representatives who told me that ExxonMobil felt that we should resume the study and let their legal folks work the legal issues while their technical folks and ours did the technical work. Over a month has gone by and one thing or another has delayed the resumption of the Pt Thomson study. Finally, late last week, representatives of ExxonMobil and BP informed me that they would NOT be resuming the study until such time as the legal issues are resolved. They went on to say that they saw potential delays in the Pt Thomson project of up to five years — 3 years for litigation and 2 years for a new operator to get up to speed. • 11 North Slope Gas Offtake Pruhoe Bay o Approximately 25 TCF of gas o The gas in the Prudhoe Bay oil pool is used in many ways to get more oil from Prudhoe Bay and other pools. o Two billion barrels of oil currently remain in the Prudhoe Bay oil pool. o Selling the gas while there is still oil will risk the loss of some of the remaining oil. o The Prudhoe Bay operator is developing and implementing strategies to minimize the losses. o Completed a complex reservoir study of the Prudhoe Bay oil pool. ■ The later gas sales begin, the more of that 2 billion barrels has been produced in the meantime, and the lower the gas offtake required from the Prudhoe Bay oil pool, the lower the losses will be. ■ We do not anticipate a problem with allowing gas sales from Prudhoe Bay. Engaged in Pt Thomson study o Approximately 9 TCF of gas o Pt Thomson is a very complex reservoir in many ways. ■ Retrograde condensate reservoir. ■ By Alaska statutes, it's an oil pool, not a gas pool. ■ Risk of substantial oil losses (equal to or greater than an Alpine Field) if not operated properly. ■ Very high pressure. ■ Lots of reservoir uncertainty. o We initiated this study over a year ago but several events have delayed actual start-up. o Also, it now appears that there is much more data to be evaluated than originally estimated. o We anticipate the need for an additional year to complete the study. o Completing this study and evaluating the performance of the proposed cycling pilot should provide us sufficient understanding of Pt Thomson to determine an appropriate gas offtake allowable for that pool. Undiscovered gas potential on the North slope o USGS and MMS estimate undiscovered conventional gas potential of over 150 TCF. o Anadarko drilling a gas exploration well on the North slope. o Once there is more certainty of a gas line (and more certainty that it will have available capacity to support new discoveries), we anticipate lots of gas exploration activity. • C-j For Senate Resources: Good afternoon, chairman Huggins, madam president, and other members of the Senate Resources Committee. Thank you for taking the time this afternoon to consider me for reappointment to this important position. For House Resources: Good afternoon, co-chairmen Gatto and Johnson, representatives Edgmon, Guttenberg, Kawasaki, Kohring, Roses, Seaton, and Wilson. Thank you for taking the time this afternoon to consider me for reappointment to this important position. For House Oil and Gas: Good afternoon, co-chairmen Kohring and Olson, representatives Dahlstrom, Doogan, Kawasaki, Ramras, and Samuels. Thank you for taking the time this afternoon to consider me for reappointment to this important position. I have been serving the State of Alaska in the AOGCC since March of 2005, when I was appointed to complete the unexpired term of the engineering commissioner. Please allow me to explain why I wish to be reappointed. First, Alaska has given so much to me and to my family that I am grateful for the chance to give something back. My sons told me the other day how thankful they are that our family moved to Alaska when they were very young. They then went on to list all of the reasons that this has been a fabulous place to grow up and is the only place they want to live as adults. So, as you can see, I have a bit of a personal interest in working for the good of the State. 0 • My second reason is purely business. The AOGCC is in the middle of several extremely important and highly technical projects right now, many of which are heavily dominated by engineering issues. We just completed a technical study that will assist us in determining the appropriate allowable gas offtake from Prudhoe Bay when we have North Slope gas sales. We are in the early phase of a similar study for Pt Thomson. We are in the process of updating our regulations regarding well safety systems and are in the conceptual phase of a review of our regulations and processes involving gas disposition. The State has an investment in the time I have already spent understanding these complex issues and I feel it would be a big set -back for someone new to have to get up to speed on them, especially midstream. Lastly, throughout my career as a petroleum engineer I've been blessed with wonderful opportunities to learn and contribute, and my time with the AOGCC has been one such opportunity. I'm especially pleased and honored to serve the people of Alaska as a part of such a well -respected Commission and in concert with such intelligent, honest, ethical, and hard-working gentlemen as Dan Seamount and John Norman. (They will pay me later for saying that.) This concludes my statement. Thank you. 0 0 DONE: For Senate Resources: Good afternoon, chairman Wagoner, vice - chair Seekins, senators Dyson, Elton, Guess, Stedman, and Stevens. Thank you for taking the time this afternoon to consider me for this important appointment. For House Resources: Good afternoon, co-chairmen Samuels and Ramraz, representatives Crawford, Elkins, Gatto, Kapsner, Ledoux, Olson, and Seaton. Thank you for taking the time this afternoon to consider me for this important appointment. Thursday 5pm (Alaska), 8pm (Texas): For House Oil and Gas: Good afternoon, chairman Kohring, representatives Dahlstrom, Gardner, Kerttula, McGuire, Rokeburg, and Samuels. Thank you for taking the time this afternoon to consider me for appointment to this important position. I was raised to give more than I get; Alaska has given so much to me and to my family that I am grateful to have this chance now to give something back. With my training and experience as a petroleum engineer, the Alaska Oil and Gas Conservation Commission should be an ideal place for me to serve the State of Alaska. I have had a variety of engineering assignments — from reservoir development to facilities design. I have also had opportunities to supervise and mange a broad range of groups — from small, highly -technical groups of engineers and geoscientists to large operations groups of mainly skilled and unskilled laborers. Most of my early experience was onshore Texas and offshore Louisiana, but for the last 13 years I have worked the 0 0 North Slope of Alaska — from well operations at Prudhoe Bay to new field development on the western North Slope. I'm particularly proud of a few of my Alaska work experiences and would like to share them with you. • I was operations superintendent for the Prudhoe Bay Wells Group during the time that group helped to pioneer coiled tubing drilling in Alaska. Now, I was not one of the brilliant technical people doing the real work; I was merely an enabler for them. • I had the privilege of leading the strategic business review team that initiated the West Sak development that Alaska is enjoying today. • I was part of the consulting team that prepared an analysis for the DNR of how to assist new operators in acquiring access to North Slope facilities. Throughout my career I've been blessed with wonderful opportunities to learn and contribute, and I see this appointment as another such opportunity. I'm especially pleased and honored to have the opportunity to serve the people of Alaska as a part of such a well -respected Commission and in concert with such intelligent, honest, ethical, and hard-working gentlemen as Dan Seamount and John Norman. Thank you. Senator Huggins, Senator Stedman, Representative Samuels, members of the Alaska Legislature, citizens of the State of Alaska: Thank you for inviting me here to talk with you about the Point Thomson technical issues under the regulatory oversight of the Alaska Oil and Gas Conservation Commission, or AOGCC. I will start with a brief description of the AOGCC's statutory responsibilities, just to put into perspective the small but important role we play in the State's quest to achieve North Slope gas sales. I'll then give you what I hope to be an easy -to -follow description of the issues concerning us at Pt Thomson. I'll end with a description of how we are working and will continue to work to ensure that Pt Thomson is developed and produced appropriately. After that I will be available for any questions you might have. In understanding what the AOGCC does, it's important first to know how we are different from the DOG, from whom you've just heard. The DOG is responsible for maximizing the value to the State of Alaska of the oil and gas under State lands. The AOGCC regulates oil and gas operations throughout the State, not just on State lands, but also on Federal Native, and privately held lands. And the State, by law, has no greater standing in our adjudications than any other party. The AOGCC has five primary responsibilities. We prevent waste of oil and gas, we encourage greater ultimate recovery of oil and gas, we protect sources of fresh ground water from harm by oil and gas operations, we protect human health and safety related to downhole oil and gas operations, • 0 and we protect correlative rights. And, as I said, we do this throughout the State, regardless of land ownership. In our day-to-day regulatory oversight we are called upon to exercise all of these responsibilities in a variety of ways, but the two responsibilities I want to focus your attention on today are preventing waste of oil and gas and encouraging greater ultimate recovery of oil and gas. I ask you to keep these in mind as we proceed with the rest of this discussion. And I also ask you to keep in mind that nowhere in our list of responsibilities will you find mention of making the most money, balancing the budget, or making any particular set of constituents happy. You guys have the tough job — all we deal with is science and engineering. So let's talk a little science and engineering. Although most people think of and refer to Pt Thomson as a gas reservoir, the gas is so rich with condensate — liquid hydrocarbons associated with the gas — that we actually classify Point Thomson as an oil reservoir. That point is important because, as a general petroleum engineering rule, if you produce the gas from an oil reservoir before producing all of the oil first, you stand to lose some of the oil. In engineering vernacular Point Thomson is what we call a gas condensate reservoir or a retrograde condensate reservoir. In such a reservoir, the hydrocarbons are in the gas phase until the pressure drops below a certain point — called the dew point. When the pressure drops below the dew point, some of the hydrocarbons, the condensates, switch to the liquid phase and 0 drop out of the gas. When this happens, a substantial portion of those liquids can be trapped in the reservoir, and can never be recovered. In many retrograde condensate reservoirs, cycling — that is reinjecting the produced gas over and over again to maintain high reservoir pressure until the liquid condensate has been recovered — is the way to prevent these losses. Looking simply at the reservoir mechanics issues — not getting into financial concerns or politics — cycling the gas until most of the liquids have been recovered is the way to achieve greater ultimate recovery and prevent waste from a gas condensate reservoir such as Pt Thomson. Publicly available estimates of recoverable liquid hydrocarbons associated with the gas at Pt Thomson vary from 200 to 500 million barrels, depending on the source and the method of development. As I just said, if we produce Point Thomson as a gas reservoir without cycling first, a significant portion of those liquids are at risk. And don't let me underemphasize the value of this liquid resource; it's the size of another Alpine Field. There is a second potential problem with not cycling first. If we don't recover those liquids first, then as the reservoir pressure drops they will drop out in the place where the pressure is lowest — adjacent to the wellbores. When liquids drop out there, they damage the producibility of the reservoir and, thus, decrease the ability of the wells to bring the gas up to the surface. The operator can undo some of this damage through well interventions, but these cost money, must be repeated as additional damage is done, and eventually may no longer be effective at fixing the problem. This is important to the AOGCC because it will result not only in liquid losses, but also in gas losses. And it is important to the State for that reason AND because, under ACES, the State shares the cost of these interventions that will likely be done over and over to keep the gas wells producing. However, you should keep in mind that cycling will likely add significant capital costs, which the State would, again, share via ACES. A third problem exists around producing the gas from Pt Thomson. Underlying this thick gas condensate reservoir is a relatively thin oil layer. If we produce the gas from Pt Thomson before producing the oil, much of that oil will be lost. So what will the AOGCC do about our concerns? Since we are charged with preventing waste of hydrocarbon resources in Alaska and since producing gas from an oil reservoir can cause waste, we determine when and how much gas can be produced from every oil reservoir throughout the State. And we do this with an eye to greater ultimate recovery of both the oil and the gas. We do not typically dictate to an operator what he must do. Rather, the operator typically comes to us with a request for permission to do something and we allow it, disallow it, or allow some modification to the originally proposed plan. For instance, we do not tell an operator where or how deep to drill his wells. Rather, the operator requests to drill a particular well in a particular location to a particular depth using particular procedures. We approve the request, deny it, or approve it subject to some limitations or modifications. • 0 The same will hold true for gas offtake from an oil field, such as Prudhoe Bay and Point Thomson. Before the operator can produce gas from Point Thomson, he must come to us and request a gas offtake allowable. As a very important part of that request, he must prove to us that waste will not occur. Without that proof we cannot grant the request. Unfortunately not enough is currently known about the Thomson Sand, either the gas portion or the oil layer, to know what the right answer is — for the oil companies or the State. We don't know if there is adequate connectivity in the gas condensate part of the reservoir for cycling even to work. And if it doesn't work, then both the oil companies and the State will have wasted a lot of money. Also, we don't know enough about the characteristics of the oil in the oil layer to know whether it is technically recoverable. In other words, even if we all agreed to get that oil first, we don't even know if it can be done. The oil may or may not be too viscous to produce; the gas above and water below it may cone into the oil layer and drown out the oil production; the extremely expensive wells required to attempt to produce the oil may or may not be economical. We just don't know enough. And without a bit of drilling, producing, and cycling we never will. This concludes my prepared testimony. I will be happy to answer any questions. Mr. Chairman, members of the Alaska Legislature, citizens of the State of Alaska: Thank you for inviting me here to talk with you about the Point Thomson technical issues under the regulatory oversight of the Alaska Oil and Gas Conservation Commission, or AOGCC. I will start with a brief description of the AOGCC's statutory responsibilities, just to put into perspective the small but important role we play in the State's quest to achieve North Slope gas sales. I'll then give you what I hope to be an easy -to -follow description of the issues concerning us at Pt Thomson. I'll end with a description of how we are working and will continue to work to ensure that Pt Thomson is developed and produced appropriately. After that I will be available for any questions you might have. In understanding what the AOGCC does, it's important first to know how we are different from the DOG, from whom you've just heard. The DOG is responsible for maximizing the value to the State of Alaska of the oil and gas under State lands. The AOGCC regulates oil and gas operations throughout the State, not just on State lands, but also on Federal Native, and privately held lands. And the State, by law, has no greater standing in our adjudications than any other party. The AOGCC has five primary responsibilities. We prevent waste of oil and gas, we encourage greater ultimate recovery of oil and gas, we protect sources of fresh ground water from harm by oil and gas operations, we protect human health and safety related to downhole oil and gas operations, and we protect correlative rights. And, as I said, we do this throughout the State, regardless of land ownership. i 0 In our day-to-day regulatory oversight we are called upon to exercise all of these responsibilities in a variety of ways, but the two responsibilities I want to focus your attention on today are preventing waste of oil and gas and encouraging greater ultimate recovery of oil and gas. I ask you to keep these in mind as we proceed with the rest of this discussion. And I also ask you to keep in mind that nowhere in our list of responsibilities will you find mention of making the most money, balancing the budget, or making any particular set of constituents happy. You guys have the tough job — all we deal with is science and engineering. So let's talk a little science and engineering. Although most people think of and refer to Pt Thomson as a gas reservoir, the gas is so rich with condensate — liquid hydrocarbons associated with the gas — that we actually classify Point Thomson as an oil reservoir. That point is important because, as a general petroleum engineering rule, if you produce the gas from an oil reservoir before producing all of the oil first, you stand to lose some of the oil. In engineering vernacular Point Thomson is what we call a gas condensate reservoir or a retrograde condensate reservoir. In such a reservoir, the hydrocarbons are in the gas phase until the pressure drops below a certain point — called the dew point. When the pressure drops below the dew point, some of the hydrocarbons, the condensates, switch to the liquid phase and drop out of the gas. When this happens, a substantial portion of those liquids can be trapped in the reservoir, and can never be recovered. 11 In many retrograde condensate reservoirs, cycling — that is reinjecting the produced gas over and over again to maintain high reservoir pressure until the liquid condensate has been recovered — is the way to prevent these losses. Looking simply at the reservoir mechanics issues — not getting into financial concerns or politics — cycling the gas until most of the liquids have been recovered is the way to achieve greater ultimate recovery and prevent waste from a gas condensate reservoir such as Pt Thomson. Publicly available estimates of recoverable liquid hydrocarbons associated with the gas at Pt Thomson vary from 200 to 500 million barrels, depending on the source and the method of development. As I just said, if we produce Point Thomson as a gas reservoir without cycling first, a significant portion of those liquids are at risk. And don't let me underemphasize the value of this liquid resource; it's the size of another Alpine Field. There is a second potential problem with not cycling first. If we don't recover those liquids first, then as the reservoir pressure drops they will drop out in the place where the pressure is lowest— adjacent to the wellbores. When liquids drop out there, they damage the producibility of the reservoir and, thus, decrease the ability of the wells to bring the gas up to the surface. The operator can undo some of this damage through well interventions, but these cost money, must be repeated as additional damage is done, and eventually may no longer be effective at fixing the problem. • This is important to the AOGCC because it will result not only in liquid losses, but also in gas losses. And it is important to the State for that reason AND because, under ACES, the State shares the cost of these interventions that will likely be done over and over to keep the gas wells producing. However, you should keep in mind that cycling will likely add significant capital costs, which the State would, again, share via ACES. A third problem exists around producing the gas from Pt Thomson. Underlying this thick gas condensate reservoir is a relatively thin oil layer. If we produce the gas from Pt Thomson before producing the oil, much of that oil will be lost. So what will the AOGCC do about our concerns? Since we are charged with preventing waste of hydrocarbon resources in Alaska and since producing gas from an oil reservoir can cause waste, we determine when and how much gas can be produced from every oil reservoir throughout the State. And we do this with an eye to greater ultimate recovery of both the oil and the gas. We do not typically dictate to an operator what he must do. Rather, the operator typically comes to us with a request for permission to do something and we allow it, disallow it, or allow some modification to the originally proposed plan. For instance, we do not tell an operator where or how deep to drill his wells. Rather, the operator requests to drill a particular well in a particular location to a particular depth using particular procedures. We approve the request, deny it, or approve it subject to some limitations or modifications. 0 0 The same will hold true for gas offtake from an oil field, such as Prudhoe Bay and Point Thomson. Before the operator can produce gas from Point Thomson, he must come to us and request a gas offtake allowable. As a very important part of that request, he must prove to us that waste will not occur. Without that proof we cannot grant the request. Unfortunately not enough is currently known about the Thomson Sand, either the gas portion or the oil layer, to know what the right answer is — for the oil companies or the State. We don't know if there is adequate connectivity in the gas condensate part of the reservoir for cycling even to work. And if it doesn't work, then both the oil companies and the State will have wasted a lot of money. Also, we don't know enough about the characteristics of the oil in the oil layer to know whether it is technically recoverable. In other words, even if we all agreed to get that oil first, we don't even know if it can be done. The oil may or may not be too viscous to produce; the gas above and water below it may cone into the oil layer and drown out the oil production; the extremely expensive wells required to attempt to produce the oil may or may not be economical. We just don't know enough. And without a bit of drilling, producing, and cycling we never will. This concludes my prepared testimony. I will be happy to answer any questions. Alaska Oil and Gas Conservation Commission (AOGCC) Overview and Update Permitting Description • • t� AOGCC Overview and Update • What we do at the AOGCC • • Staffing and organization • 2005 highlights • Industry activity Current challenges and projects 0 What we do at the AOGCC • Quasi-judicial State regulatory agency — Oversight for underground operations � • Alaska private and public lands and waters • All but Denali National Park • Regulate drilling and production for oil & gas Protect correlative rights • Promote greater ultimate recovery � • Manage Class II UIC program of the EPA — Protect underground fresh water AOGCC website: www.aogcc.alaska.gov AOGCC Goals and Strategies PREVENT PHYSICAL WASTE OF THE RESOURCE • Evaluate drilling programs to ensure proper well design, construction and well control equipment. • Inspect wells and drilling projects to verify compliance with approved regulations, procedures and safety requirements for drilling and production practices. • Evaluate proposals for reservoir development. Is AOGCC Goals and Strategies (Continued) PROMOTE GREATER ULTIMATE RECOVERY • Analyze production data, including reservoir pressures, gas -oil ratios, water cut etc., to ensure these variables fall within the required parameters necessary to provide for greater ultimate recovery. • Review and approve development proposals, including plans for enhanced oil recovery operations and gas development. AOGCC Goals and Strategies (Continued) INDEPENDENTLY ASSESS OIL AND GAS DEVELOPMENT • Independently audit/verify that oil and as proposals are in compliance p Y Y g P P with the purposes and intent of Title 31. I* AOGCC Goals and Strategies (Continued) PROTECT ALASKA'S UNDERGROUND SOURCES OF DRINKING WATER • Provide engineering and geological review of all applications for FOR & underground disposal of drilling wastes. Provide engineering and geological review of all applications to drill oil and gas wells. 49 11 AOGCC Goals and Strategies (Continued) PROTECT CORRELA� RIGHTS • Provide all owners of oil and gas rights the opportunity to recover their fair share of the resource through well spacing regulations, permit review, and pooling authority. WHEN NECESSARY ADJUDICATE DISPUTES BETWEEN OWNERS • Provide a public forum to resolve disputes between owners. f Where Does AOGCC Fit In? Issues Oil Company Land Owner ADEC AOGCC (Regulated (e.g. DNR DOG (Exercises (Exercises Community) or Native Police Powers of Police Powers of Corporation) the State) the State) Ownership of Lessee of Oil & Gas Landlord & Lessor Role Is Regulatory, Role Is Regulatory, Resource Lease (Has Right to of Oil & Gas Lease Not Proprietary- Not Proprietary - Drill and Produce) Mainly Surface & Air Mainly Sub -surface Jurisdiction Only on Lands Owner's Land Only State, Federal and State, Federal and Where They Have Private Lands Private Lands Right to Drill and Produce Economics Profit Oriented Manages Owned Regulates to Protect Regulates to Resources for environment Prevent Waste, Revenue & Other Protect Correlative Values Rights, & Promote Greater Recovery Net $$ Interest Owns Majority of Owns Minority of None- Regulates None- Regulates Production Production (Royalty Only Only Interest) AOGCC generally regulates sub -surface activities. ADEC and other agencies have regulatory authority over most surface activities. i Ia EAST TEAM COORDINATOR Reservoir Engineer PCN 021036 XE Anchorage Sr Petroleum Engineer PCN 021039 XE Anchorage Sr. Patrolaum Geologist PCN 080155 XE Anchorage II Petro Geology Asst II PCN 080169 XE Anchorage AOGCC Staffing II ss PCN Chairman OSO150, AnchXE orag 11 5080 52 II II Special AncXE 7 horagaII WEST TEAM COORDINATOR Sr Patrolaum Engineer PCN 080156 XE Anchorage Reservoir Engineer PCN 080160 XE Anchorage Patroleum Geologist PCN 021038 XE Anchorage Statistical Technician 11 PCN 060100 GGU Anchorage Statistical Technician II PCN 080101 GGU Anchorage Net. Ras. Tech 1/11 PCN 080103 GGU Anchorage Administrative Clark 11 PCN 02N036 GGU Anchorage Administrative Clark III 021050 GGU Anchorage POLICY INSPECTIONS II Patroleum Engineer II PCN 080106 XE c Anhorage Pat "um Inspector PCN 080151 XE Anchorage Pat "um Inspector PCN 100801 XE Anchorage Patrolaum Inspector PCN 021037 XE Anchorage 11 Patrolaum Inspector PCN 080164 XE Anchorage Patrolaum Inspector PCN 100802 XE Anchorage Petroleum Inspector PCN 021046 XE (Seasonal) Anchorage NETWORK ADMINISTRATION 8. P ROGRAM M 1 NO Analyst ro Pgrammer IVPCN 080165 XE Anchorage Analyst Progmmmar III PCN 02X001 XE Anchorage 0 ADMINISTRATIVE Administrative Mgr II PCN 080102 SU Anchorage Accounting Clark I PCN 080105 GGU Anchorage Work Sites AOGCC pnbocm North Slope Deadhorse_♦Oil Fields ._ � Field Office ?17--, i �tlon� AOGCC .� Home Office MAx �hATidNAI1 AOGCC has oversight responsibility for oil & gas projects everywhere in Alaska except Denali National Park. Courtesy of the Anchorage Convention & Visitors Bureau GLRF ALAIKA Cook Inlet Oil & Gas Fields / Mat -Su Valley 0 North Slope KUPARUK RIVER HaMSOR Bay KUUKPIK _@ COLVR , LE RIVER RP 4v%--•^>> PMLLI TRALBLAZER A- H by C PHILLIP NECHt31KP PALM I Tabax BP pi BP PHILLIPS Fiat Clee© ALPINE bbE5T1 /j • NdWE 01-01 PHILLIPS PHILLIPS l UK 1 &0"2 LOOKO`UT 1OSUNRISE 1 PHILLIPS SPARK30 OAR L 2 Tam PHLUS PHILLIPS RENDEMUSA' SPARKIRLA CLO / { HLUPS PH ILLS . RBI DEZVDUS1 ATLA�PROS PECT� tt�lia�ul PeEekvm 1HILLIPS HUNTER I"�`-A7ab.� &Atk HIL SALA6KABIC — ER NORTH 292A � PHILLIPS AIRS KAI MELTWATER NORTH 1 1 *ARCO ALASKA MELTWATER SOUTH 1 r West Team f. �r D 5 10 15 20 25 Miles Beaufort Sea /SANDPIPER UNIT POINT 'Ar IR RTHSTAR UNR � Mc COVEY UNIT - PHILLLPS Safb i�jAAcCOVEY PROSPECT .kkktgreAr dd? &y r de �li Yk ag L2ft hhrlgt A :DUCK ISLA NO UNIT 8LLS8 r Ike ,i47err klL3e40— h?arl V SAmS e Eay Af lolmn PRUDH BAY UNR J Geographic Delineation of Decisions Teams East Team Map Legend Units Oil Field / Accumulation 2001 Prospects • Active Wells — Road --- Trans -Alaska Pipeline ��fbm m eAmad Thor sort T THOM SON UNIT �� rAa�mav Ldard I � ®x�Bcttati�l } r waa1;&L1ae� M.PLm9m • Ci Cook Inlet Map Legend Unit Boundary Oil Field / Accumulation Gas Field / Accumulation Selected Wells C) Proposed / Active Wells ri Platform Pipelines Production Facility Map Area Geographic Delineation of Decisions Teams West ,—.. RS,r Pretty Cr � Beluga Riv� Anadarko C Lone Creek Moqu .kie Nicolas C[�k Alber[ K.I. -/ Granite Point Trading S rr!! GRZ or Royston 1 Palmer all sad we iLake `� Fire 4 �AN Fj !PAGE Inlet \� 4North Middle Gr Shoal McArthur Ri Lr�ICilrrl a8irch Hill r,1/ h i W�iltttler W. McArthur Ri 'Middl � Shoa ..at Pore l an�''y�\�-,IL I l�)J A/ JJ Swanson River S PorceneYgy Y 8- Kuatatan P' 1G F Be Creek ' Pod Nikiaki `/ Red t Nni��FC Nnit 5 R Shoal / Shoal Q est Pork Drift Riveraj&a �.5terling Q J a 1 Cannery K r$oldo[na q i Kalgin $ Island / EastF Pall. rathon Graaelm Oskolkoff 1 Bew,� \. mil�hik �+ L � V' I Phillips � a Coeniopoli tan 1 S�^ North Pork \� �NorthrPq�C/Ma11�1 Homer eJ Gulf )� J `` Alas a Ll AOGCC 2005 Highlights • Key accomplishments — 88 orders and approvals 216 drilling permits approved — 388 sundry applications approved S enforcement actions • Highlights of rulings and findings 8 orders establishing / modifying pool rules — 7 orders approving / extending pilot projects — 8 orders approving / modifying enhanced oil recovery — 2 orders approving underground storage of hydrocarbons — 9 orders approving / modifying / denying disposal injection operations — 4 orders reducing paperwork for routine operations 350 i 300 �O 250 C 200 N .E L a 150 4- 0 L (D 100 E 3 Z 50 1950 Alaska Oil & Gas Activity 1960 1970 1980 1990 2000 4500 4000 3500 Z 3 C7 3000 CD O 2500 n Z 2000 �s cD 1500 N 1000 Approved Permits 500 Active Reservoirs 0 2010 L Active Wells u Cumulative Annual Well Activity Permiting 1] r: In 2005, activity did not decrease. Wellwork complexity and time per job increased. EXPLORATORY WELL PERMITS (1996 - 2005) 35 30 25 10 5 0 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 Operator a - BP - CPAI ® UNOCAL - MARATHON 0 PIONEER AURORA - FOREST 0 KERR-MCGEE ANADARKO - PELICAN HILL 0 FEX - GRI - TECK COMINCO - TOTALE&P ALASKAN CRUDE _ RUTTER & WILBANKS DEPT OF INT EXPLORATORY WELL PERMITS (1996 - 2005) OPERATOR 1996 1997 1998 1999 r 2000 2001 2002 2003 2004 2005 . Total CONOCOPHILLIPS ALASKA INC 9 10 4 3 8 17 10 4 5 7 -77 BP EXPLORATION (ALASKA) INC 3 4_ 8 1 1 _ _ 1 _ 2 20 UNION OIL CO OF CALIFORNIA 1 i 1 1 2 4 7 15 MARATHON OIL CO 1 1 1 2 1 4 3 1 1 14 PIONEER NATURAL RESOURCES ALASKA, INC. AURORA GAS LLC FOREST OIL CORP 2 3 2 1 9 KERR-MCGEE OIL & GAS CORP ! ! F 3 5 8 ANADARKO PETROLEUM CORPORATION --- _ PELICAN HILL OIL AND GAS INC. 2 1 3 3 . _. GRI—INC E 2 TECK COMINCO ALASKA INCORPORATED ; 2 2 TOTAL E&P USA, INC. _ __. i i I 1 2 ALASKAN CRUDE CORP I i RUTTER AND WILBANKS CORPOR—ATION U S DEPT OF INTERIOR s I 1 1 � _-___-_.i - -- - - - - - 21 28 1 185 Year TotalsE 14 15 15 4 14 24 33 17 1 Vertical Well Extended Reach Well ., More complex wellwork requires more rig time. With fixed rig count and more complex wellwork, fewer jobs can be done in a year. i Recycling of Old Wells Side Track Well Multi -Lateral Well bores Sealing Rock Reservoir Rock Complex wellbores require more time and effort to evaluate permit applications. Key Challenges and Projects ➢ Determine the impacts of major gas sales upon ultimate hydrocarbon recovery from Prudhoe and Pt. Thomson reservoirs before gas sales off - take rates can be approved. — Mitigation of oil losses ➢ Facilitate expanded statewide exploration and development, including NPR -A and exploration licensing areas that are outside the North Slope and Cook Inlet. — Increased production ➢ Evaluate and respond to the need for a revised regulatory scheme to safely oversee new development of nonconventional, shallow and gas storage resources. — Responsible development s ➢ Finalize AOGCC's Internet -based Well and Production Information System available to anyone in the world. — Help increase investment in Alaska Key Challenges and Projects (continued) ➢ Maintain an active role to protect Alaska's UIC program. Take over responsibility for Class I injection wells from EPA. — Faster permit decisions ➢ Respond to changing conditions in mature oil fields to make certain operations are conducted in a safe and skillful manner while ensuring that recovery of oil and gas resources is maximized. - Safer operations and less resource waste E ➢ Conduct comprehensive review of natural gas production in Alaska and of all gas which is being flared, vented or otherwise not put to beneficial use. - Less resource waste i ➢ Continue to evaluate ways to increase the AOGCC's efficiency. — Reduce costs AOGCC Permitting • Types of permits Drilling, Well or Program Modifications, Underground Injection, Orders, Special Considerations Je • Permitting process — Application filed with supporting documentation — Program checked for conformance to regulations — Commission approval or denial • Our performance — Permit to drill average decisions — 7 days — Sundry application average decisions — 4 days Types of AOGCC Permits • Drilling • Wellwork • Underground injection • Conservation Orders • Special development considerations Drilling Permits • Location � — Surface, bottomhole, and trajectory • Total depth • Fluids used • Tubulars used • Cementing i • Blowout prevention equipment & procedures Wellwork • Abandon a completion � Add or plug perforations • Stimulate producing pools • Convert to/from production/injection • Repair/ pull tubing • • Suspend or abandon a well Underground Injection • Enhanced recovery 0 — Water — MI — Dry gas — CO2 • Gas storage • • Waste disposal Conservation Orders • Determination of well status (oil or gas) � • Allowable offtake rates by well or pool • Performance monitoring requirements • Well spacing • Voidage replacement • • Reporting requirements • Pilot project approval Special Development Considerations • Spacing exceptions • C-plan exemptions • Annular disposal • Information dissemination s • Permitting Process • Application filed with supporting documentation 0 1. Received and logged in 2. Recorded in Commission database • Program checked for conformance to regulations 1. Lease, ownership, bonding, well spacing 2. Pipe and cement programs, BOP equipment 3. Shallow drilling hazards, H2 S, site conditions • 4. Good oilfield practices, maximum resource recovery 0 Commission approval or denial 35 30 _ 25 E 4) 20 CL L Q 15 N cC 10 5 N Drilling Permit Approval Time 91 00 00 O� O^ 01' 01' O� O� Off` Off` Oh O111 O110 Although review process has gotten more complex and thorough, review time has remained - 7 days. 80 Z •70 60 O, 50 (D 40 N 30 A C 20 (D 10 . 0 After the 2006 Prudhoe Bay • Shut -down: Corrective Actions and Oversight AOGCC Role • Cathy Foerster, Commissioner 2/14/07 Primary Areas of AOGCC Oversight • Prevent resource waste and encourage greater ultimate recovery • Protect fresh groundwaters • Protect correlative rights • Ensure good oilfield practices are used in � drilling, workover, and reservoir management operations AOGCC Oversight of Pipeline Integrity • Custody transfer meter accuracy • No other authority 0 • AOGCC Involvement in Corrective Actions • Stayed apprised of operating conditions and remedial plans & actions — to respond to public inquiries — to prevent loss of hydrocarbons • Approved changes to custody transfer metering • Provided technical support to Arctic Pipeline Technology Team 0 11 What's New Since mid-2006? • New BOPE regulations in place • New SVS regulations being developed • Gas disposition study planned • Prudhoe Bay gas offtake study completed • Pt Thomson gas allowable study on hold 0 • Additional inspector to be hired s • Investigation of BP NS well integrity allegations completed Key Findings: BP Well Integrity Investigation • No violations of AOGCC regulations • Regulatory gap in well cellar requirements • Some housekeeping issues • AOGCC working with other agencies to develop proactive approach to monitoring routine operations more closely 0 • MEMORANDUM STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION TO: Chair John K. Norman DATE: February 28, 2007 Commissioner Daniel Seamount Commissioner Cathy P. Foerster , FROM: Jane Williamson SUBJECT: Prudhoe Major Gas Sales Sr. Reservoir Eng` Study Blaskovich Services, Inc. (BSI) and Commission staff recently completed a study of the impact of a future Major Gas Sale (h4GS) on oil and gas recovery from the Prudhoe Oil Pool. The following is provided as a summary of major findings and conclusions from this study. Foreward,— Historical Review and Study PnM29e In 1977, the Commission set the maximum allowable Prudhoe Oil Pool annual gas ofdiake rate at 2.7 billion standard cubic feet per day (BSCF/D), which contemplated an annual average gas pipeline delivery sales rate of 2.0 BSCF/D. This allowable, set out in Rule 9 of Conservation Order 341D, was approved without benefit of production Nstory. The Commission recognized that the rates may be changed as production data and additional reservoir data became available. Over the past five years, there has been significant activity concerning a potential major gas sale. BPXA, Exxon -Mobil, and ConocoPhillips commissioned a $125 million dollar study to determine the conceptual feasibility of a gas pipeline. The tentative plan resulting from this study was for a 4.3 BSCF/D pipeline, with capacity to expand to 5.6 BSCF/D. The Prudhoe Bay Unit, Prudhoe Oil Pool is the only North Slope developed field with significant gas reserves (estimated at more than 24 trillion cubic feet (TCF)) and is of primary importance for any decision concerning the pipeline. Pt. Thomson, with over 8 TCF of gas and several hundred million barrels of gas condensate and oil, was assumed to also provide a supply of gas for the pipeline. The companies and the State of Alaska have devoted significant resources to negotiate fiscal terms to build the pipeline. Based on these efforts, the Commission became concerned that no application for modification to the Prudhoe gas ofliake rule had been submitted. As a result of a Commission inquiry and several public hearings, the Commission published a report on December 5, 2005 concluding that there was a need to comprehensively revisit the question of the appropriate gas off take limits in light of several decades of reservoir development and information that has become available since 1977. Because delay in the Commission's decision -making could disrupt the timetable for a potential gas pipeline project, the Commission adopted a proactive approach to ensure there would be an adequate factual basis for its eventual decision on • 6 Prudhoe Major Gas Sales Study Febnuvy 28, 2007 Page 2 of 3 allowable gas of%ke. The Prudhoe Working Interest Owners (WIO) and the Commission therefore agreed to principles allowing the Commission consultants and staff to access their reservoir simulation and other relevant engineering studies for the purpose of analyzing gas ofitake rates and gas sales startup timing for the Prudhoe Oil Pool. Blaskovich Services, Inc. (BSI) was commissioned to provide reservoir engineering consultation in this study. This work-study officially began in late January 2006. A brief summary follows: Summary of 2006 Commission Audit Results The Prudhoe WIO full field reservoir simulator was used as the primary tool in this evaluation. In addition to runs made assuming no gas sales, simulation runs were made at various gas sales rates (1.0-5.6 BSCF/D) and gas sales startup dates (2015, 2019, and 2024). Some simulation cases were run to test the impact of other factors such as changes in waterflood operation, fuel usage, C% ofRake, and some drillinglworkover variations. We also evaluated the effect of varying assumptions for and of the field life (EOFL). Throughout our analysis, we searched for major factors that would affect the trends in total hydrocarbon recovery as a function of gas of lake rates and timing, We were not searching for "thee' optimum development strategy. We did not value one type of energy resource (e.g., liquids or gas) over another, but equated thew using their relative energy content in units of barrels of oil equivalent (BOE). Based on our analysis of currently available data, we have reached the following major conclusions. • A major gas sale at Prudhoe represents approximately an additional 4 billion BOB recovery. • The latest WIO model needs improvements in its ability to predict future field performance. Model errors are increasing with time. Nevertheless, it is the best tool currently available. It should be suitable for comparing directional trends in energy recovery during a gas We. • Increased oil capture prior to gas sales can increase hydrocarbon recovery and result in recovery trends that are less sensitive to either gas ofitake rates or gas sales startup dates. This was the only mitigation option evaluated that significantly improved trends in DOE recovery. • End of field life (EOFL) is a major source of uncertainty in determining the gas sale strategies that will maximize energy recovery. o Comparison of model reserves predictions at the some elate for EOFL tended to favor an earlier, higher rate gas sale. We found the time limit EOFL approach to be inappropriate because ending energy production rates could be vastly dif hwt between the high rate, early startup case and the low rate, delayed startup case. Prudhoe Major Gas Sales Study Fobruary 28, 2007 Page 3 of o Model results based on equivalent EOFL rate limits consistently show that total energy recovery is substantially decreased with an earlier, higher rate gas sale. We believe that rate limits are more reasonable than time limits for comparison of gas sales model predictions. However, exclusive use of rate limits is flawed because the risks of wells and field infrastructure failures with age are ignored. • Well, facilities and infrastructure failures can significantly increase the risk of lost hydrocarbons. The longer that gas sale is delayed, the greater the risk of well and facilities failure resulting in premature field shutdown. Furthermore, near term failures will defer production and may result in more reserves loss with early gas sales. Diligent efforts to maintain, repair, and replace aging wells and facilities will help to mitigate risks and maximize recovery under any sales scenario. Recommendations The Commission has not received a request for a new gas offiake rule. At this time, we cannot recommend a specific gas offtake rate and sales startup timing. The Prudhoe WIO model evaluations and studies that have been shared with us are not sufficient to justify an allowable above that specified in Rule 9, CO 341D. An early, high rate gas sale could result in the loss of a substantial volume of hydrocarbons. However, even greater volumes may be at risk if gas sales are indefinitely delayed and Prudhoe wells and infrastructure fail before these reserves can be recovered. We are concerned that Rule 9 does not specifically require a plan for such a major change in the Prudhoe Oil Pool depletion strategy. The ultimate impact of gas sales on hydrocarbon recovery cannot be appraised in the absence of a proposed development plan that identifies the start date, sales rate and liquid loss mitigation efforts. Although the start up for gas sales is a minimum of 8 years away, many decisions that affect the project will be made earlier. Depletion planning should be required prior to commitments to sell gas so that the Commission is adequately informed and assured that other factors do not exist that would justify or require action by the Commission. Regardless of the timing of their submittal, the Prudhoe WIOs need to develop near -term strategies to prepare the field for gas sales with focus on methods to increase the capture of oil prior to gas sales and to ensure facility and well downtime is minimized. On a regular basis, the Commission needs to be kept informed of the progress of the depletion planning efforts, including review of study plans, reservoir study results and other relevant information that may impact the Commission's ultimate decisions concerning gas sales offtake. The exchange of information in the past year was very successful and a similar mechanism of exchange Mould be considered during the depletion planning stage. We wholeheartedly appreciate the cooperation of the Working Interest Owners over the past year, particularly that of the BP technical representatives who worked with us in this endeavor. This report reflects the evaluation and opinions only of the authors and does not necessarily reflect those of the Prudhoe Owners or other Commission staff. Prudhoe Oil Pool Gas Offtake Reservoir Study Public Summary February 28, 2007 0 212812007 AOGCC Public Meeting - MGS Reservoir Study Presentation Summary • Commission authority • Historical perspective • Reservoir concerns related to gas sales • Study purpose and available information • Observations • Recommendations 212812007 AOGCC Public Meeting - MGS 2 Reservoir Study AOGCC Major Gas Sales Reservoir Study Disclaimer Evaluation and opinions reflect those of only BSI and AOGCC staff who worked directly on the project. These opinions do not necessarily reflect those of the WIO, Commissioners or other AOGCC staff 212812007 AOGCC Public Meeting - MGS 3 Reservoir Study Prudhoe Gas Offtake Allowable Commission Authority • Commission Duties (related to MGs decisions) — prevent physical waste of resource — promote greater ultimate recovery • Authorities — require/approve development plans — set allowable offtake � 212812007 AOGCC Public Meeting - MGS 4 Reservoir Study Prudhoe Gas Offtake Allowable Historical • • Pool Rules CO 341D, Rule 9 (1977) — Offtake allowable set at 2.7 BCFD — Envisioned?---, 2.0 BCFD Pipeline Delivery • Currently produced gas re-injected i 212812007 AOGCC Public Meeting - MGS S Reservoir Study Why do we care about gas offtake? • Gas extraction lowers reservoir pressure • — Decreases energy required for oil production — Oil recovery suffers; gas production benefits How is ultimate total hydrocarbon recovery affected by gas sales offtake? • 212812007 AOGCC Public Meeting - MGS 6 Reservoir Study Prudhoe Gas Offtake Allowable Recent Activities • 2002 WIO study — Tentative P/L design of 4.3 BCFD — Prudhoe major source for P/L (+24 TCF) • Pipeline fiscal discussions/negotiations • No Application for Rule 9 Amendment • AOGCC 2005 inquiry — Concluded comprehensive revisit of Rule 9 needed — Proactive Approach — "Principles" for access to WIO reservoir studies 212812007 AOGCC Public Meeting - MGS 7 Reservoir Study i Prudhoe Gas Offlake Study • Study begun January 2006 0 — Engineering Consultant Blaskovich Services Inc. (BSI) — WIO provided Data Room with necessary information and studies • WIO Full Field Reservoir Simulator Primary Tool — Access/Electronic copies of reservoir simulation results — Additional simulation runs on request i • Good Cooperation from WIO staff, management 212812007 AOGCC Public Meeting - MGS 8 Reservoir Study Study Approach • Simulation runs variables — Gas Startup Times (2015-2024) Offtake Rates (1-5.6 BCFD)• — Other field operating strategies Compared on basis of total energy content — Units of Barrel Oil Equivalent (soE) • Concentrated on trends in recovery, not absolutes — Not looking for "the" optimum development strategy S 212812007 AOGCC Public Meeting - MGS 9 Reservoir Study Conclusions • Major, Gas Sales adds 4 Billion BOE � (+/- 24 TCF) — 11.4 BSTB Oil/Condensate/NGLs produced to date — 1977 projections of less than 9 Billion Barrel Oil • Initial projections assumed 1982 Gas Sales � • End of Field life estimated 2003 212812007 AOGCC Public Meeting - MGS 10 Reservoir Study Conclusions - Model • WIO model best currently available 9 — Years in development — Should be good for evaluation of directional trends — Some improvements needed in predictive mode C: 212812007 AOGCC Public Meeting - MGS 11 Reservoir Study Conclusions • Increased oil capture prior to Gas Sales Improved recovervv trends — Most encouraging strategy — Recovery trends less sensitive to gas offtake or S/U Rate • Allows for more flexibility 212812007 AOGCC Public Meeting - MGS 12 Reservoir Study i i End of Field Life (EOFL) • End of Field Life (EOFL) is when costs exceed revenue from continued production. 0 — Reserves are evaluated at an assumed EOFL — Unknown —but important to compare all cases at same assumed EOFL • Major effect upon predicted recovery outcomes • Date Limit favors earlier, higher rate MGS • • Rate Limit favors later, lower rate MGS 212812007 AOGCC Public Meeting - MGS 13 Reservoir Study Hypothetical Profiles* High Rate, Early - - - Low Rate, Delay -- - . -------------- Profiles Illustrative Only • Time 1 A 212812007 AOGCC Public Meeting - mciJ 1 Reservoir Study .. 212812007 Hypothetical Profiles* EOFL - Time Limit Time AOGCC Public Meeting - MGS Reservoir Study IS • • Hypothetical Profiles* EOFL - Rate Limit • * Profiles Illustrative Only Time 212812007 AOGCC Public Meeting - MGS 10 Reservoir Study EOFL Summary • Time limits do not treat production • (revenue) fairly. • Rate limits do not treat future risk (costs) fairly. We believe rate limits are more correct � but we need to consider risk with age. • Use rate limits and risk analysis 212812007 AOGCC Public Meeting - MGS 17 Reservoir Study Field Well/Infrastructure Failures is Failures increase reserves risk 0 — If MGS delayed 9 Higher risk with age— impact field life — Near Term failures 0 • Deferred oil production prior to MGS risks reserves 212812007 AOGCC Public Meeting - MGS 18 Reservoir Study Recommendations MGS Offtake • There is insufficient evidence at this time to recommend r increasing Rule 9 Offtake • No request for modification of Rule 9 • Depletion planning should be required prior to commitments to sell gas CI 212812007 AOGCC Public Meeting - MGS 19 Reservoir Study Recommendations Pre-MGS Strategies/Plans • Regardless of timing of request for modification near term strategies needed to prepare for MGS • Increase oil capture prior to MGS • Minimize well and facility downtime • Mechanism needed for exchanging information during the depletion planning stage 10 212812007 AOGCC Public Meeting - MGS 20 Reservoir Study