The URL can be used to link to this page

Home My WebLink AboutO 083 s 0 Image Project Order File Cover Page 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. 0 033 3 Order File Identifier Organizing (done) ❑ Two -sided III IIIIIII I1111 ❑ Rescan Needed 11 11111 IIII RESCAN DIGITAL DATA OVERSIZED (Scannable) ❑ Color Items: ❑ Diskettes, No. ❑ Maps: Greyscale Items: 1 P ❑ Other, No/Type: ❑ Other Items Scannable by a Large Scanner ❑ Poor Quality Originals: OVERSIZED (Non - Scannable) ❑ Other: ❑ Logs of various kinds: NOTES: ❑ Other:: BY: Maria Date: /s/ ('1 P � � (0/a6)13 Project Proofing 1 111111 I BY: ' Date: (o/.o/I3 /s/ pdp Scannin g Preparation aration x 30 = + = TOTAL PAGES q.iU p (Count does not include cover sheet) BY: Date: 0 3 /s/ Production Scanning 1111111111 11111 Stage 1 Page Count from Scanned File: q V (Count does include cover eet) Page Count Matches Number in Scanning Preparation: YES NO 9 g p BY: Maria Date: 6 9 / a0 / /3 /s/ mf 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. 1111111 I 1111 ReScanned 1111111M 11111 BY: Maria Date: /s/ Comments about this file: Quality Checked III (IIIII III IIII III 1/17/2012 Orders File Cover Page.doc • 0 INDEX OTHER ORDER NO.83 CINGSA 1. March 17, 2011 Appellant's state of points on appeal 2. May 13, 2011 Housekeeping 3. July 8, 2011 Appellant's motion to compel 4. July 8, 2011 Appellant's brief INDEX OTHER ORDER NO.83 CINGSA • IN TIFF SUPREME COI JRT FOR T1 IF STATE OF ALASKA VINCENT GODDARD. WILD PACIFIC SALMON. INC.. and INLET FISH PRODUCERS. INC.. .•• Appellants. ..„„ • • vs. Supreme Court No. 5-14934 ALASKA OIL AND GAS CONSERVATION COMMISSION and Case No. 3AN-1 1-6305 COOK INLET NATURAL GAS STORAGE ALASKA, I IC. :•• ,••• Appellees. .• .••• • STIPULATION FOR DISMISSAL, WITH PREJUDICE Appellants. Vincent Goddard, Wild Pacific Salmon, Inc.. and Inlet Fish Producers. Inc.. collectively known as Inlet Entities, and Appellees Cook Inlet Natural Gas Storage Alaska. I,LC and the Alaska Oil and (ins Conservation Commission, by and through respective counsel, stipulate and agree that all claims in this matter are hereby dismissed with prejudice. each party to hear its own respective costs and lees. I/I `• c?) 0 •=r- 0 r .4) STIPULATION FOR DISMISSAL WITH Pimumck pa I of 3 S • , i , I i)A this , ' day or ...t. . 2012, 1 LAW Ol'FICE OF MIC11All STI:1111. l, 1 Attorneys For Appel knits ; .. ,•,,- t 13 Stehle—ABA-NO:91060.4 . ...„,. '') D All .1) this --) day of ,,,1,:::. i„ C.,tv 1 k.s(,„ 'e . 1012 ., ...,, ... 1 I AS I Mt ;RN & MASON. 1).(.. 1 1 i Attorneys or Appellee C!N(iSA . . ; / 1 Br: di4----t, William Saupe. ABA \ --, DAT] I) this , i' dav ()I' .. ::(_ Ct., L ,-- 1011. , ; ()ac or the Attorne (iencral , Attorne s For Appellee -.....: -, Alaska Oil and Gas Conservation Commission • By: , t) . 7, 5: 'r - Thomas A. Ballantine II!, ABA 8806122 ''''. • siwt;LATtoN FOR DISMISSAL Willi PREJUDICL Page 2 (31'3 • CERTIFICA II OF 1'0Ni AND SERVICF The undersigned certifies that the typeface used in this document is 13 point limes New Roman. and further certifies that on Ovirivr 3 . 2012 the foregoing was served upon the lollowing h first-class mail: t 0 • Thomas A. Rallantine Senior Assistant Attorney General 1031 W -1 Ave.. Ste. 200 Anchorage AK 99501 A. William Saupe Neloira K. Smith Ashburn & Mason. PC 1227 W 9 Ave.. Ste. 200 Anchorage AK 99501 I lonorable .ludgc Philip R. Volland • Superior Court. Judge Superior Court for the State or Alaska at Anchorage ;Certification Signature .- r Si ci = ) < IPULATION FOR DISMISSAL Will PROUDICL Page 3 01'3 S - 0,..., IN THE SUPERIOR COURT FOR THE STATE OF ALASKA THIRD JUDICIAL DISTRICT AT ANCHORAGE 1 VINCENT GODDARD, WILD PACIFIC ) 1 • I SALMON, INC., and INLET HSI! ) PRODUCERS, INC., ) , 1 ) ; 1 Appellants, ) , ., 1 1 ) VS. ) ) 1 i i At ,ASKA OIL AND GAS ) Case No.: SAN-11-6305 Ci‘ il i CONSERVATION COMMISSION, and ) - COOK INLET NATIJRAI, GAS ) STORAGE Al ,ASKA, LLC, ) ) e.., R Appellees. ) m 1 i LI Li.3 ORDER OF DISMISSAL I The parties having stipulated to the dismissal of the above-captioned matter., it is 1 1 i hereby ORDERED that this case is DISMISSED with PREsit iDICL. Each party shall 1 bear its own costs and attorney's fees. Z .-4. aa C " 1- t : (-ilfe (14.14>ve--0 The I k»rabic Philip R. Volland Suvrittoft Cot la it it xil: ." .i.. T " g A) - 9 - / I < . / 1 Shit! 7 Oa. c 6-N kitA— bu 64 SO1e1..4 : 043 i 1 -047,00082153,1i Si f° - - I Page I or 2 , 1 I • • (FATIFIcATE OF SERVICE I certify that a copy of the foregoing was served by U.S. Mail on the 2 day of I )(N.:ember 201.7, on. Michael T. Stehle Law Office of Michael Stehle, P.C, 1200 It Street, Suite It Anchorage, AK 99501 Ingelli.e.,.stet plpy, rej/gD, Thomas A. 13allatitine III 1 Senior Assistant Attorney General 1031 West Fourth Avenue, Suite 200 Anchorage. AK 99501 takliallantige@alaska.goy & MASON if \ Vs tcidi wyckorc rd co r. 8 t r■ < g t 1 2 z< < z Z-4 `i 'Ft 1.4 ■••• "1 0 {1)453 -047 .00082 53,1 ORDER OF DISMISSAL Goddard v. AOGCC, 43AN -1 1-6305 Civil Page 2 of 2 • IN THE SUPERIOR COURT FOR THE STATE OF ALASKA THIRD JUDICIAL DISTRICT AT ANCHORAGE Vincent Goddard et al, Appellant, vs. Appeal Case No. 3AN-11-0630501 1 Administrative Appeal Alaska Oil and Gas Conservation Commission et al, District Court Case No. Appellee. - NOTICE AND ORDER ON APPEAL BOND A Ej supersedeas bond DK cost bond in the amount of $750.00 was posted in the above case. A decision on appeal was rendered on 10/09/12. Unless an objection showing good cause is filed by Affirmed, El the cash deposit in lieu of bond will be returned to the posting party. El the surety bond will be exonerated. CLERK OF COURT 10/11/2012 By: EStandifer Date Deputy Clerk I certify that on 10/11/2012 a copy of this notice was sent to: Appellant: Vincent Goddard Appellee: Alaska Oil and Gas Conservation Commission Agency: Clerk: EStandifer ORDER It is ordered that the: cash deposit be released and returned to the posting party. E cash deposit in the amount of $ be released to appellee and any remainder be returned to the posting party. n surety bond is exonerated. LI surety bond/cash deposit be held pending further proceedings. LI Other Oate )//2_ r-K12.Pata Judge Type or Print Name I certify that an a copy of this nolise nt Appellant „/ ' _ Appellee: , • Agency: _ _ Ar340(v) (3al) Nolice And Oitter On ApIK.reil Hood r 44 • IN THE SUPERIOR COURT FOR THE STATE OF ALASKA THIRD JUDICIAL DISTRICT AT ANCHORAGE 3AN -11 -6305 CI VINCENT GODDARD, WILD PACIFIC SALMON, INC., and INLET FISH PRODUCERS, INC., Appellants, vs. ALASKA OIL AND GAS CONSERVATION COMMISSION, and COOK INLET NATURAL GAS STORAGE ALASKA, LLC, Appellees. APPEAL OF AGENCY DECISION ALASKA OIL AND GAS CONSERVATION COMMISSION Daniel T. Seamount, Jr., Chair, and Cathy P. Foerster, Commissioner Docket SIO- I0 -05, STORAGE INJECTION ORDER No. 9 and SUBSEQUENT ORDER ON RECONSIDERATION APPELLANTS' BRIEF Michael T. Stehle Stehle & Jarvi, LLC 1200 R St., Ste. B Anchorage AK 99501 907 - 677 -7877 ABA No.: 9106054 • TABLE OF CONTENTS Table of References Page 2 Constitutional Provisions, Statutes, Court Rules, Ordinances, and Regulations Principally Relied Upon Page 4 Jurisdictional Statement Page 12 Parties Page 12 Issues Presented For Review Page 13 I. Statement of the Case Page 15 II. Standard of Review Page 27 III. Argument Page 29 A. AOGCC Violated Inlet Entities' Constitutional Right to Due Process of Law and Its Own Governing Regulations By Failing to Require Cook Inlet Natural Gas Storage Alaska, LLC ( "CINGSA ") to Amend its SIO Application to Give Notice of Its Request to No Longer Include Remediation of KU 13 -8 as a Part of Its Application, and By Engaging in Ex- Parte Communications with CINGSA and Failing to Include Those Ex -Parte Communications with CINGSA as a Part of the Public Record, and By Not Holding a Public Hearing on CINGSA's Decision to Not Remediate KU 13 -8. Page 29 B. AOGCC Erred By Failing to Comply with Its Own Regulations Governing Well Plugging Requirements. Page 32 C. The AOGCC's Finding that KU 13 -8 Need Not Be R.emediated, and That No Further Inspection Or Base Line Testing Is Required Is Not Supported By Substantial Evidence. Page 35 V. Conclusion Page 42 1 • • TABLE OF REFERENCES Alaska Const. art. 1 § 7 Page 30 AS 22.10.020(d) Page 11 AS 42.05.631 Page 36 20 AAC 25.112 Pages 14, 35, 42, 43 20 AAC 25.252 Pages 14, 35, 43 20 AAC 25.540 Page 31 Bush v. Reid, 516 P.2d 1215, 1219 -21 (Alaska 1973) Page 30 Carvalho v. Carvalho, 838 P.2d 259, 262 (Alaska 1992) (quoting Aguchak v. Montgomery Ward Co., 520 P.2d 1352, 1356 (Alaska 1974). Page 30 Leigh v. Seekins Ford, 136 P.3d 214, 216 (Alaska 2006) Page 28 May v. State, Commercial Fisheries Ently Comm'n, 175 P.3d 1211, 1216 (Alaska 2007) Page 28 Northern Timber Corp. v. State, Dep't of Transp., Public Facilities, 927 P.2d 1281 n. 10 (Alaska 1996) Pages 28, 35 Patrick v. Lynden Transport, Inc., 765 P.2d 1375, 1379 (Alaska 1988) Page 30 Peter v. Progressive Corp., 986 P.2d 865, 872 (Alaska 1999) Page 30 Public Employee Retirement System v. Gallant 153 P.3d 346, 350 (Alaska 2006) Page 30 Simpson v. State, Commercial Fisheries Entry Con 101 P.3d 605, 609 (Alaska 2004) citing Revelle v. Marston, 898 P.2d 917, 925 n. 13 (Alaska 1995). Page 28 State, Dept. ofAdmnin. i.'. Bachner Co., Inc., 167 P.3d 58, 61 (Alaska 2007) Page 29 2 • • State, Dep't of Natural Res. v. Greenpeace, Inc., 96 P.3d 1056, 1063 -64 (Alaska 2004) (quoting Matanuska Maid, Inc. v. State, 620 P.2d 182, 192 -93 (Alaska 1980)). Page 30 Tesoro Alaska Petroleum Co. v. Kenai Pipe Line, 746 P.2d at 903. Pages 28, 35 West v. Municipality of Anchorage, 174 P.3d 224, 226 -227 (Alaska 2007) citing State v. Pub. Safety Employees Ass 'n, 94 P.3d 409, 413 (Alaska 2004). Page 28 3 • • CONSTITUTIONAL PROVISIONS, STATUTES, COURT RULES, ORDINANCES, AND REGULATIONS PRINCIPALLY RELIED UPON Alaska Const. art. 1 § 7: Due Process No person shall be deprived of life, liberty, or property, without due process of law. The right of all persons to fair and just treatment in the course of legislative and executive investigations shall not be infringed, AS 22.10.020(d): Jurisdiction The superior court has jurisdiction in all matters appealed to it from a subordinate court, or administrative agency when appeal is provided by law, and has jurisdiction over petitions for relief in administrative matters under AS 44.62.305. The hearings on appeal from a final order or judgment of a subordinate court or administrative agency, except an appeal under AS 43.05.242, shall be on the record unless the superior court, in its discretion, grants a trial de novo, in whole or in part. The hearings on appeal from a final order or judgment under AS 43.05.242 shall be on the record. AS 42.05.631: Eminent domain A public utility may exercise the power of eminent domain for public utility uses. This section does not authorize the use of a declaration of taking. 20 AAC 25.112: Well plugging requirements (a) Plugging of the uncased portion of a wellbore must be performed in a manner that ensures that all hydrocarbons and freshwater are confined to their respective indigenous strata and are prevented from migrating into other strata or to the surface. The minimum requirements for plugging the uncased portion of a wellbore are as follows: (1) by the displacement method, a cement plug must be placed (A) from 100 feet below the base to 100 feet above the top of all hydrocarbon - bearing strata; (B) from the well's total depth to 100 feet above the top of all hydrocarbon - hearing strata; (C) from the well's plugged back total depth to 100 feet above the top of all hydrocarbon - bearing strata, if all hydrocarbon - bearing, abnormally geo- pressured, and freshwater strata below are isolated; however, the commission will approve plugging from the top of fill or the top of junk instead of from the plugged back total depth, if the commission determines that the objectives of this subsection will be met; or 4 • • (D) from 100 feet below the base to 50 feet above the base of each significant hydrocarbon- bearing stratum and from 50 feet below the top to 100 feet above the top of each significant hydrocarbon - bearing stratum; (2) by the displacement method, a cement plug must be placed from 100 feet below the base to 50 feet above the base of each abnormally geo- pressured stratum and from 50 feet below the top to 100 feet above the top of each abnormally geo - pressured stratum; (3) by the displacement method, a cement plug must be placed from 150 feet below the base to 50 feet above the base of the deepest freshwater stratum. (b) Plugging of a well must include effectively segregating uncased and cased portions of the wellbore to prevent vertical movement of fluid within the wellbore. The minimum requirement for plugging to segregate uncased and cased portions of a wellbore is one of the following: (1) by the displacement method, a continuous cement plug must be placed from 100 feet below to 100 feet above the casing shoe; (2) by the downsqueeze method using a retainer set no less than 50 feet but no more than 100 feet above the casing shoe, a volume of cement sufficient to fill the wellbore from the retainer to 100 feet below the casing shoe must be pumped through the retainer, and cement must be pumped above the retainer to cap it with a 50 foot cement plug; (3) by the downsqueeze method using a production packer set no less than 50 feet but no more than 500 feet above the casing shoe, a volume of cement sufficient to fill the wellbore from 100 feet below the casing shoe to the packer must be pumped through the packer, and cement must be pumped above the packer to cap it with a 50 foot cement plug. (c) Plugging of cased portions of a wellbore must be performed in a manner that ensures that all hydrocarbons and freshwater are confined to their respective indigenous strata and are prevented from migrating into other strata or to the surface. The minimum requirements for plugging cased portions of a wellbore are as follows: (1) perforated intervals must be plugged by one of the following methods: (A) by the displacement method, a cement plug placed from 100 feet below the base to 50 feet above the base of the perforated interval and from 50 feet below the top to 100 feet above the top of the perforated interval; (B) by the displacement method, a cement plug placed from the well's total depth to 100 feet above the top of the perforated interval; (C) by the displacement method, a cement plug placed from the well's plugged- ' back total depth to 100 feet above the top of the perforated interval, if all hydrocarbon - bearing, abnormally geo - pressured, and freshwater strata below are isolated; however, the commission will approve plugging from the top of fill or the top of junk instead of from the plugged -back total depth, if the commission determines that the objectives of this subsection will be met; 5 • • (D) by the downsqueeze method using a cement retainer or production packer set no less than 50 feet but no more than 500 feet above the perforated interval, a volume of cement pumped through the retainer or packer sufficient to fill the wellbore from 100 feet below the base of the perforated interval to the retainer or packer (E) if the perforations are isolated from open hole below, a mechanical bridge plug set no more than 50 feet above the top of the perforated interval, and either a minimum of 75 feet of cement placed on top of the plug by the displacement method or a minimum of 25 feet of cement placed on top of the plug with a dump bailer; (2) casing stubs within outer casing must be plugged by one of the following methods: (A) by the displacement method, a cement plug placed from 100 feet below the stub to 100 feet above the stub; (B) by the downsqueeze method using a retainer set 50 feet above the stub, a volume of cement pumped below the retainer sufficient to fill the casing stub with 150 feet of cement, and cement pumped above the retainer to cap it with a 50 foot cement plug; (C) if the casing stub annulus is cemented, a mechanical bridge plug set no more than 25 feet above the casing stub, and either a minimum of 75 feet of cement placed on top of the plug by the displacement method or a minimum of 25 feet of cement placed on top of the plug with a dump bailer; (3) if freshwater is present, the smallest diameter casing string extending to the surface must be plugged by one of the following methods: (A) by the displacement method, a cement plug placed from 100 feet below the depth of the surface casing shoe to 100 feet above the depth of the shoe; (8) a mechanical bridge plug set 100 feet below the depth of the surface casing shoe and at least 200 feet of cement placed on top of the plug. (d) Plugging of the surface of a well must meet the following requirements: (1) by the displacement method, a cement plug at Least 150 feet in. length, with the top of the cement no more than five feet below original ground level onshore, or between 10 and 30 feet below the mudline datum offshore, must be placed within the smallest diameter casing string; (2) either (A) all annular space open at the surface onshore, or in communication with open hole and extending to the mudline datum offshore, must be plugged with cement to seal the annular space in a manner satisfactory to the commission; or (B) all casing interior to the surface casing must be recovered to a depth of 100 feet or more below the original ground level onshore or the mudline datum offshore and the casing stubs plugged with cement as provided in (c)(2)(A) of this section; if the cement plug is extended to within the distance from the surface specified in (1) of this subsection, the requirement of (1) of this subsection need not be met. 6 • • (e) Cement used for plugging within zones of permafrost must be designed to set before freezing and have a low heat of hydration. (f) Each of the respective intervals of a welibore between the various plugs must be filled with fluid of sufficient density to exert a hydrostatic pressure exceeding the greatest formation pressure of permeable formations in the intervals between the plugs at the time of abandonment. (g) Except for surface plugs, the operator shall record the actual location and integrity of cement plugs, cement retainers, or bridge plugs required by this section, using one of the following methods, which in the case of a cement retainer or bridge plug may be performed before cement is placed on top of the plug: (1) placing sufficient weight on the plug to confirm its location and to confirm that the plug has set and a competent plug is in place; (2) testing the plug to hold a surface pressure of 1,500 psig or 0.25 psi /ft multiplied by the true vertical depth of the casing shoe, whichever is greater, and tagging the plug to confine location; however, surface pressure may not subject the casing to a hoop stress that will exceed 70 percent of the minimum yield strength of the casing. (h) At least 24 hours notice of plugging operations must be given to the commission so that a representative of the commission can witness the operations. (i) The commission will, in its discretion, approve a variance from the requirements of this section if the variance provides for at least equally effective plugging of the well and prevention of fluid movement into sources of hydrocarbons or freshwater. History: Eff. 11/7/99, Register 152 Authority: AS 31.05.030 20 AAC 25.252: Underground disposal of oil field wastes and underground storage of hydrocarbons a) The underground disposal of oil field wastes and the underground storage of hydrocarbons are prohibited except as ordered by the commission under this section. In response to a letter of application for injection filed by an operator, the commission will issue an order authorizing the underground disposal of oil field wastes that the commission determines are suitable for disposal in a Class II well, as defined in 40 C.F.R. 144.6(b) as revised as of July 1, 1998, which is adopted by reference, or the underground storage of hydrocarbons. An order authorizing disposal or storage wells remains valid unless revoked by the commission. (b) The operator has the burden of demonstrating that the proposed disposal or storage operation will not allow the movement of oil field wastes or hydrocarbons into sources of freshwater. Disposal or storage wells must he cased and the casing cemented in a manner that will isolate the disposal or storage zone and protect oil, gas, and freshwater sources. (c) An application for underground disposal or storage must include 7 • (1) a plat showing the location of all proposed disposal and storage wells, abandoned or other unused wells, production wells, dry holes, and any other wells within one - quarter mile of each proposed disposal or storage well; (2) a list of all operators and surface owners within a one - quarter mile radius of each proposed disposal or storage well; (3) an affidavit showing that the operators and surface owners within a one - quarter mile radius have been provided a copy of the application for disposal or storage; (4) the name, description, depth, and thickness of the formation into which fluids are to be disposed or stored and appropriate geological data on the disposal or storage zone and confining zones, including lithologic descriptions and geologic names; (5) logs of the disposal or storage wells, if not already on file, or other similar information; (6) a description of the proposed method for demonstrating the mechanical integrity of the casing and tubing under 20 AAC 25.412 and for demonstrating that fluids will not move behind casing beyond the approved disposal or storage zone, and a description of (A) the casing of the disposal or storage wells, if the wells are existing; or (B) the proposed casing program, if the disposal or storage wells are new; (7) a statement as to the type of oil field wastes to be disposed or hydrocarbons stored, their composition, their source, the estimated maximum amounts to be disposed or stored daily, and the compatibility of fluids to be disposed or stored with the disposal or storage zone; (8) the estimated average and maximum injection pressure; (9) evidence to support a commission finding that the proposed disposal or storage operation will not initiate or propagate fractures through the confining zones that might enable the oil field wastes or stored hydrocarbons to enter freshwater strata; (10) a standard laboratory water analysis, or the results of another method acceptable to the commission, to determine the quality of the water within the formation into which disposal or storage is proposed; (11) a reference to any applicable freshwater exemption issued in accordance with 20 AAC 25.440; and (12) a report on the mechanical condition of each well that has penetrated the disposal or storage zone within a one - quarter mile radius of a disposal or storage well. (d) The mechanical integrity of a disposal or storage well must be demonstrated under 20 AAC 25.412 before disposal or storage operations are begun, after a well workover affecting mechanical integrity is conducted, and at least once every four years. To confirm continued mechanical integrity, the operator shall monitor the injection pressure and rate and the pressure in the casing - tubing annulus during actual disposal or storage operations. The monitored data must be reported monthly on the Monthly Injection Report (Form 10 -406). 8 • • (e) If an injection rate, operating pressure observation, or pressure test indicates pressure communication or leakage in any casing, tubing, or packer, the operator shall notify the commission by the next working day and shall implement corrective action or increased surveillance as the cornrnission requires to ensure protection of freshwater. (f) The commission will require additional mechanical integrity tests if the commission considers them prudent for conservation purposes or protection of freshwater, (g) Modifications of existing or pending disposal or storage operations will be approved by the commission, in its discretion, under 20 AAC 25.507, upon application containing sufficient detail to evaluate the proposed modification. No modification will be approved unless the applicant proves to the commission that the modification will not allow the movement of fluids into sources of freshwater. (h) If wells, including freshwater wells or other borings, are located within a one - quarter mile radius of the disposal or storage well, are a possible means for oil field wastes or hydrocarbons to move into sources of freshwater, and are under the control of (1) the operator, the operator shall ensure that the wells are properly repaired, plugged, or otherwise modified to prevent the movement of oil field wastes or hydrocarbons into sources of freshwater; or (2) a person other than the operator, the commission will not issue an order under (a) of this section to the operator until the operator presents evidence to the commission's satisfaction that the person who controls the wells has properly repaired, plugged, or otherwise modified the wells to prevent the movement of oil field wastes or hydrocarbons into sources of freshwater. (i) The commission will publish notice of the disposal or storage application and will provide opportunity for a hearing in accordance with 20 AAC 25.540. (j) If disposal or storage operations are not begun within 24 months after the approval date, the injection approval will expire unless an application for extension is .approved by the commission. (k) The annular disposal of drilling wastes approved under 20 AAC 25.080 is an operation incidental to drilling a well and is not a disposal operation subject to this section. (l) This section does not apply to underground disposal that is regulated under 40 C.F.R. 147.101 by the United States Environmental Protection Agency. History: Eff. 4/2/86, Register 97; am 11/7/99, Register 152 Authority: AS 31.05.030 20 AAC 25.540: Hearings (a) On its own motion or if a written request is received to issue an order affecting a single well or a single field, the commission will publish notice in an appropriate newspaper as provided in AS 31.05.050 (b). In the notice, the commission will set 9 • • out the essential details of the requested order, provide an opportunity for public comment, tentatively specify the place, time, and date for a public hearing, and provide a telephone number that the public may use to learn if the commission will hold the tentative hearing. The commission will tentatively set a hearing date that is at least 30 days after the date of publication of the notice. A person may submit a written protest or written comments during that 30 -day period. In addition, a person may request that the tentatively scheduled hearing be held by filing a written request with the commission within 15 days after the publication date of the notice. If the commission receives a timely request for hearing, or if the commission desires to hold a hearing, the commission will hold a hearing on the date and time specified in the notice. If a request for hearing is not timely filed, the commission will, in its discretion, issue an order without a hearing. (b) On its own motion or if a written request for a public hearing is received concerning a matter within the jurisdiction of the commission under this chapter, the commission will publish notice in an appropriate newspaper as provided in AS 31.05.050 (b). In the notice, the commission will provide the essential details of the matter and set out the place for the public hearing, the date, and the time for the public hearing. The commission will set a hearing date that is at least 30 days after the date of publication. (c) Except as otherwise provided in (e) of this section, the following procedures apply to public hearings conducted under (a) or (b) of this section: (1) the hearing will be called to order and the subject of the hearing, along with the date and place of public notice given for the hearing, will be read into the record; (2) the commission will receive both sworn testimony and unsworn statements; it will give greater weight in its deliberations to sworn testimony; (3) all persons wishing to testify will be sworn; (4) each witness shall state the witness's name and whom the witness represents; (5) each witness who wishes to give expert testimony shall state the witness's qualifications, and the commission will rule on whether the witness qualifies as an expert; (6) the applicant will be asked to present testimony first; all others wishing to present testimony will be heard next; upon request, the commission will, in its discretion, allow cross - examination of witnesses; (7) a person wishing to make an oral statement will be allowed to do so after the conclusion of all testimony; (8) the commission will, in its discretion, ask questions of a witness; (9) except as may be allowed under (6) of this subsection, a person may not ask questions of witnesses directly; to have a question directed to a witness, a person must provide the question in writing, along with the person's name and that of the witness, to a designated commission representative; before the end of the hearing, the commission will review these questions and ask those that it believes will be helpful in eliciting needed information; all questions will be included in the public record; 10 • • (10) if disclosure of otherwise confidential information is required, the commission will limit and condition disclosure to the extent necessary to comport with applicable constitutional, statutory, and common law doctrines that protect trade secrets within the meaning of AS 45.50.940 and other commercially sensitive, confidential, and proprietary information; in limiting or conditioning disclosure under this paragraph, the commission will, as necessary (A) review confidential information in- camera; and (B) redact commission decisions to protect confidential information; (11) the hearing will be recorded and the recording included in the public record of the hearing; (12) the commission will, in its discretion, allow pre -filed written testimony in place of or in addition to oral testimony. (d) The commission will hold hearings on matters of statewide or general application under the applicable provisions of AS 44.62. (e) In a hearing under 20 AAC 25.535, a party may be represented by counsel, call and examine witnesses, present relevant evidence unless unduly cumulative or repetitious, cross - examine witnesses, impeach witnesses, and rebut adverse evidence. The commission will base its decision with respect to contested issues of fact only on evidence presented during the hearing. The commission will establish a reasonable date before the hearing by which the commission will and each party must provide (1) the names and addresses of persons known to have knowledge of relevant facts and, unless privileged, (A) written or recorded statements by those persons; or (B) summaries of statements by those persons; (2) the name, address, and qualifications of each expert who will testify at the hearing, and a written description of the substance of the expert's proposed testimony, the expert's opinion, and the underlying basis of that opinion; and (3) a copy of all documents and a description of all other tangible things intended to be used in the hearing. (f) By means of a pre - hearing conference or otherwise, the commission will, in its discretion, establish additional procedures for a specific hearing consistent with the procedures in (c) or (e) of this section, as applicable, or as otherwise necessary to provide due process to a party. History: Ef£ 4/13/80, Register 74; am 4/2/86, Register 97; am 11/7/99, Register 152 Authority: AS 31.05.030, AS 31.05.040, AS 31.05.050, AS 31.05.060, AS 31.05.070 1 I • • JURISDICTIONAL STATEMENT On November 19, 2010, Alaska Oil and Gas Conservation Commission ( AOGCC) issued Docket SIO- 10 -05, Storage Injection Order No. 9, authorizing underground natural gas storage in the Cannery Loop Unit, Kenai Peninsula Borough. Appellants Vincent Goddard, Wild Pacific Salmon, Inc., and Inlet Fish Producers, Inc., collectively known as Inlet Entities, moved for reconsideration of Docket SIO- 10 -05, Storage Injection Order No. 9 on December 14, 2010. AOGCC issued a decision on Appellants' motion for reconsideration on February 18, 2011, and confirmed its prior decision. Appellants appealed that decision on March 17, 2011. The firm of Ashburn and Mason, PC entered an appearance on behalf of Cook Inlet Natural Gas Storage Alaska, LLC ( "CINGSA "), on May 10, 2011, and CINGSA has since been treated as a party in all respects although no motion has thus far been presented to the Court to join it as a party. The Superior Court has jurisdiction over this matter pursuant to AS 22.10.020(d) PARTIES The parties to this appeal are Vincent Goddard, Wild Pacific Salmon, Inc., and Inlet Fish Producers, Inc. (collectively known as "Inlet Entities "), the Alaska Oil and Gas Conservation Commission ( "AOGCC "), and Cook Inlet Natural Gas Storage Alaska, LLC ( "CINGSA "). 12 • • ISSUES PRESENTED FOR REVIEW 1. Whether the AOGCC erred in failing to require Cook Inlet Natural Gas Storage Alaska, LLC ( "CINGSA ") to amend its SIO application to give notice of its request to no longer include remediation of KU 13 -8 as a part of its application; 2. Whether the AOGCC erred by engaging in ex-parte communications with CINGSA and failing to include those ex-parte communications with CINGSA as a part of the public record; 3. Whether the AOGCC erred by not holding a public hearing on CINGSA's decision to not remediate KU 13 -8; 4. Whether the AOGCC erred in not requiring CINGSA to remediate KU 13 -8 as a condition of granting the SIO; 5. Whether the AOGCC erred in not requiring CINGSA to inspect KU 13 -8 as a condition of granting the SIO; 6. Whether the AOGCC erred in not requiring CINGSA to conduct base line testing as a condition of granting the SIO; 7. Whether the AOGCC erred in not requiring CINGSA to conduct ongoing soil gas tests as a condition of granting the SIO; 8. Whether the AOGCC erred in not requiring CINGSA to complete remediation prior to granting the SIO; 13 • 9. Whether the AOGCC erred in not following its own governing regulations including but not necessarily limited to 20 AAC 25.112 and 20 AAC 25.252. 14 1 • I. STATEMENT OF THE CASE This appeal arises from AOGCC's issuance of a Storage Injection Order ( "SIO ") to CINGSA for purposes of operating Alaska's first underground natural gas storage utility. CINGSA applied for the SIO on or about July 27, 2010. (R. 000811) In its application it identified two abandoned wells, KU 13 -8 and CLU- 12, which intersected or penetrated the proposed storage reservoir and were abandoned without complying with AOGCC's requirements for abandoned wells. (R. 000828, 000888) Neither well had been abandoned with isolation plugs where the wells penetrated the proposed storage reservoir to prevent gas from migrating from the reservoir as required by the AOGCC's regulations. (Id.) The application represented that both wells would be remediated and re- abandoned in a manner that conformed with AOGCC's requirements. (Id.) These same representations were made in applications with the Department of Natural Resources ( "DNR ") and the Regulatory Commission of Alaska ( "RCA "). (R. 000914) This appeal primarily concerns CINGSA's unannounced decision to renege on its conunitment to remediate KU 13 -8, and the AOGCC's decision to permit the project to go forward in the absence of the proposed remediation of KU 13 -8. CINGSA filed its application for a Certificate of Public Convenience and Necessity ( "CPCN ") with the RCA on July 28, 2010, requesting approval to operate a natural gas storage facility as a public utility. It identified the Cannery Loop Sterling C Pool ( "Sterling C ") as the reservoir it intended to use as the 15 • • storage facility, and indicated that it had filed for a lease of that subsurface pore space, as well as a lease for the surface land necessary for its surface facilities, from the DNR. (R. 000816) CINGSA's application further represented that it had applied for a SIO from the AOGCC to permit it to drill a number of injection) withdrawal wells into the Sterling C. (R. 000811-000913) The Sterling C is a producing natural gas field currently being operated by Marathon Oil Co. (R. 000816- 000822) It is located underneath the City of Kenai and the mouth of the Kenai River, and lies only one mile north of the Cannery Loop Earthquake Fault. (Id.) It is in the final stage of its productive life. (Id.) CINGSA's AOGCC application represents that the Sterling C had an original gas in place volume of 26.5 Bcf at the discovery pressure of 2200 psia. (R. 000821) CINGSA proposed to operate the facility in two phases with the first phase calling for gas to be injected bringing the maximum reservoir storage pressure to 1600 psia, and providing for up to 11 Bcf of storage capacity. (R. 000822- 000823) The second phase provides for a maximum reservoir storage pressure of 2200 psia, which is at reservoir discovery pressure, and providing for up to 16 to 18 Bcf of total storage capacity. (Id.) Thirteen existing wells penetrate the Sterling C. (R. 000828 - 000829, 000868 - 000871) One well penetrates only the upper boundary of the Sterling C and is currently being used by Marathon to produce gas from the Sterling C. (Id.) Twelve wells penetrate both the upper and lower boundaries of the Sterling C. (Id.) Some of those wells are actively producing gas from the Beluga field lying 16 below the Sterling C. (Id.) Others are older exploration or production wells that were previously abandoned. (Id.) CINGSA identified two of the abandoned wells, KU 13 -8 and CLU 12, as needing remediation. (R. 000828- 000829, 000871) The proposed remediation called for CINGSA to re- drill, re -plug and re- abandon those two wells to isolate the Sterling C from the spaces above and below the Sterling C. (Id.) Current AOGCC regulations require that an abandoned well have cement isolation plugs to isolate a penetrated field) In its application for a SIO filed with the AOGCC, CINGSA represented that it intended to remediate those wells by re- drilling, re- plugging and re- abandoning those wells in conformance with today's requirements. (R. 000828 - 000829, 000871) Those same representations were made in CINGSA's lease application filed with the DNR, as well as its application for a CPCN filed with the RCA. CINGSA is a Delaware Limited Liability Company formed in 2010 for the express purpose of building and operating the proposed facility. There are several layers of parent corporations in between CINGSA and its ultimate parent corporations, SEMCO Energy and MidAmerican. Tracing the ownership back through various layers, SEMCO Energy holds a 70% share in CINGSA, and MidAmerican 30 %. SEMCO is also the parent corporation of ENSTAR Natural Gas, the largest customer of the proposed facility. 1 20 AAC 25.112. 2 R. 000829 - 000830 17 1 • Vincent Goddard and two companies owned by him engaged in fish processing (collectively, "Inlet Entities "), operate a large salmon processing business that annually employs up to 300 people. (R. 000043 - 000044) Many of the employees reside on Inlet Entities' property. Inlet Entities became interested in the proposed gas storage facility when they were informed that one of the abandoned wells that was going to be remediated, KU 13 -8, was located on their property. (Id.) Inlet Entities allowed the project proponents access to Inlet Entities' property on two separate occasions to locate the well 4 It was ascertained that the likely location of the well was between two of Inlet Entities' buildings, approximately five feet from one and thirty -five feet from the other. Remediation of the old well would require destruction of two plant buildings and posed other risks to Inlet Entities' property and operations. Prior to granting CINGSA permission to begin digging on their property, Inlet Entities required CINGSA to enter into an agreement regarding issues such as insurance and liability for harm to Inlet Entities' property or operations. Inlet Entities testified that CINGSA did not respond to Inlet Entities' attempt to negotiate an agreement. Rather, in mid September 2010 CINGSA attempted to access Inlet Entities' property without reaching an agreement with Inlet Entities by 3 Inlet Entities actually leases the subject property from the City of Kenai under a long term (55 year) lease. (R. 000043 - 000044) 4 R. 000311; Excerpt p. 3, L. 6 - 24. 5 R. 000331, L. 5 -10; R. 000328- 000329. 6 R. 000315-000316. 18 • requesting the City of Kenai to assign its right to inspect the property as Inlet Entities' landlord. Inlet Entities objected to this attempt to access its property for remediation work without first reaching an agreement regarding liability and the other issues. A hearing in front of the AOGCC on CINGSA's SIO application was scheduled for October 19 and 20, 2010. On September 30, 2010, shortly after being unable to access Inlet Entities' property, CINGSA sent an email to one of the staff members at AOGCC inquiring how best to amend its presentation at the hearing to address the fact that it no longer felt it was necessary to remediate KU 13 -8. (R. 000441) This communication between CINGSA and AOGCC was not immediately put into the public record and there was no public record in advance of the AOGCC hearing indicating that CINGSA was no longer intending to remediate KU 13 -8. The AOGCC subsequently acknowledged that the correspondence between CINGSA and the AOGCC should have been put into the public record at the time of the communication, and it is now a part of AOGCC's public record which has been submitted as an exhibit in this hearing. Inlet Entities attended the AOGCC hearing anticipating that it would address appropriate protections for their property and operations during the remediation of KU 13 -8. (R. 000704, Tr. 128, L. 12 -14) Instead, on the first day of the hearing they learned for the first time that CINGSA was stating that they no 7 Excerpt p. 1, L. 5 - 9. 8 R. 000320. 9 Excerpt p. 9, L. 5 -21. 19 • • longer believed that remediation of KU 13 -8 was necessary. (R. 000512- 000513; Tr. 19, L. 4 -16) CINGSA did not submit any study or analysis as an exhibit with the AOGCC, but it did provide testimony and an accompanying power point presentation. Following the first day of hearings in front of the AOGCC, Mr. Goddard approached CINGSA's lawyers and asked for a copy of any paper or study that addressed CINGSA's testimony that KU 13 -8 no longer required remediation. At first Mr. Goddard was rebuffed and told that no such paper existed. When Mr. Goddard pressed the issue stating that he would request the AOGCC to intercede on his behalf and request the research, CINGSA provided him a copy of what has been referred to as White Paper 2. (R. 000251 - 000301) The research in White Paper 2 essentially tracks the testimony of CINGSA that there is little chance, defined as 1%, that gas will migrate from the Sterling C using KU 13 -8 as a conduit. (Id.) CINGSA testified that this paper was drafted on October 7, 2010, a week after CINGSA wrote to the AOGCC inquiring how to go about amending their presentation regarding KU 13 -8, and two weeks after being unable to reach an agreement with Inlet Entities regarding access to remediate KU 13 -8. (Id.) After reading White Paper 2 Mr. Goddard realized that there was a prior version of the research paper and requested CINGSA to produce that earlier draft. On October 22, 2010, two days after the hearing in front of the AOGCC was concluded, CINGSA produced a copy of what has been referred to as White Paper to R. 000320 - 000321; Excerpt pp. 5 -6. 20 1. (R. 000241 - 000250) White Paper 1 was drafted on August 8, 2010, prior to CINGSA reaching an impasse with Inlet Entities. White Paper 1 discusses essentially the same research, but concludes that there is a 50% chance of gas migrating from the reservoir if KU 13 -8 is not remediated. (Id.) Both white papers review historical production data to determine whether there is evidence in the production data of gas migrating to or from the Sterling C. While White Paper 2's analysis is more detailed, both papers conclude that there is no evidence of migration in the production data. Both white papers also posit a number of reasons, and the same reasons, why KU 13 -8 may be "effectively" plugged, despite the fact that it was not formally plugged when it was abandoned in 1964. (R. 000241- 000250, 000251- 000301) But while both white papers reached the same basic conclusion that the production data suggested that KU 13 -8 appears to be effectively plugged, even if it is not known exactly how or why it is plugged, they state markedly different opinions regarding the risk of future migration. White Paper 1 recognizes that whatever is causing KU 13 -8 to be "plugged" could be transitory in nature, especially in light of the long life of the project and the continual cycling between high pressures and low pressures over the life of the project. (R. 000242) Because the unidentified author(s) of White Paper 1 could not say for certain what was causing KU 13 -8 to act as though it were plugged, they could not analyze the future efficacy of the plug and concluded, therefore, that whether KU 13 -8 would 21 • remain plugged over the life of the project was, in essence, "a coin toss." (R. 000243) White Paper 2, on the other hand, reduced this risk to 1 %. (R. 000259) The history of this re -write of PRA's White Paper is revealing. In late September 2010 one of CINGSA's investors expressed concern over the risk that re -entry and re- abandonment of the well might not be successful as discussed in White Paper 1. (R. 000421- 000425) Kirk Lavengood, testifying in front of the RCA on behalf of CINGSA's 30% investor Northern Natural Gas and MidAmerican Energy ( "MidAmerican "), testified that he was tasked with trying to reach an agreement with Inlet Entities regarding access to reniediate KU 13 -8. (Id.) In the process he reviewed White Paper I and informed CINGSA that MidAmerican would not invest any more money in the project with the risk as stated in White Paper 1. He testified, " "[s)o we had asked PRA to go back, you know, you need to scrub this because I'm not sure if this is going to be a viable project if that's really the risk we're facing." 12 The risk of a failed remediation was of particular concern because the project was moving forward on multiple fronts simultaneously. (Kirk Lavengood, NNG, R. 000421- 000436) Accordingly, MidAmerica was requesting that remediation be attempted and completed before moving forward on other areas of the project. (Id.) This caused concern for CINGSA because it would delay the project and the delay would have a financial impact on CINGSA. (Id.) 11 Excerpt p. 10, L. 19 - 25 and Excerpt p. 11, L.1 - 2. 12 Excerpt p. 11, L. 9 - 12. 22 Accordingly, a hasty decision was made to not remediate KU 13 -8. (Id.) Over the course of several days an argument was put together for why rernediation should not be required. (Multiple parties PRA and CINGSA, R. 000421 - 000440) This argument essentially consisted of looking at historical data to show that the reservoir functioned as a pressure depletion reservoir, and that there was no evidence of significant cross -flow between the Sterling C Pool and the formations lying above and below the Sterling C during production of the Sterling C Pool, or the Beluga field lying below the Sterling C. (Id., R. 000251 - 000255) Central to this argument was a material balance analysis of the Sterling C which purported to show that pressure decreased in a smooth or straight line with production, which supported the conclusion that there was no communication between the Sterling C and the formations lying above or below the Sterling C. (Id.) On or about September 30, 2010, CINGSA wrote to AOGCC stating that they no longer believed that remediation of KU 13 -8 was necessary and attached a power point presentation that they represented supported their conclusion. (Gentges CINGSA to Aubert AOGCC, R. 000441- 000442, R. 682 -690) The power point presentation included a chart showing the purported material balance analysis. (R. 000685) CINGSA inquired how to amend their application to reflect the fact that they no longer intended to remediate KU 13 -8. (R. 000441) After several ex-parte phone calls and emails, CINGSA was told that they need not formally amend their application. (Gentges CINGSA, October 7, R. 000476) The 23 • evidence also strongly suggests that they were told in advance of the October 19, 2010 hearing that the decision to not remediate KU 13 -8 would be approved. (S Thomas NNG in Note 10 to NSAI KU 13 -8 Observations, Oct 13, R. 000473) Privately, CINGSA and its investors acknowledged that the risk of gas migration still existed. (S Thomas entail Oct 5: "Dave is concerned that it may take a period of time for- the data trends to eventually be recognized as potential migration. The extended timeframe for recognition may lead to a more significant event." R. 000458) One concern was for cross -flow of reservoir storage gas to Marathon's Beluga field lying below the Sterling C. CINGSA decided to address that risk by reaching an agreement with Marathon for how such gas would be accounted for between CINGSA and Marathon. (Marquardt in note NJM41 to WP2 draft, R. 000463) A second risk was migration of storage gas to the surface. (S Thomas email to R Gentges Sep 30: With the location of the well in the cannery facility any fixture gas migration could be very serious If gas gets up the well bore to the casing, and the cement bond is poor, would gas eventually get to the surface? ", R. 000446, 4th bullet point) CINGSA proposed to address that risk by installing gas monitoring equipment at various locations on the surface. (S Thomas NNG in Note NJM40 to the KU 13 -8 WP2 draft, R. 000463) They also anticipated that if significant quantities of storage gas were lost to migration that they would have to remediate KU 13 -8 at some time in the future. ( "If a decision is made to leave the KU 13 -8 well untouched before storage operations begin, reentering the well to replug it remains a viable option in the future if the gas 24 • storage operation indicates a loss of gas." NSAI Adams to NNG, re KU 13 -8 WP2 draft, Oct 13, R. 000473) CINGSA also recognized that the decision to not remediate KU 13 -8 for financial reasons before beginning gas storage operations might expose them to liability if gas migrated from the facility and caused a catastrophic event. (R. 000452) Accordingly, CINGSA undertook a great effort to rewrite this White Paper that had identified the risk that gas might migrate from the reservoir using KU 13 -8 as a conduit as a 50% risk. (KU 13 -8 WPI, R. 000243) While the re- written White Paper essentially relies on the same data or research that shows that historical production indicates no cross -flow during production, the risk of future migration problems was reduced from 50% to 1 %. (KU 13 -8 WP2, R. 000259) There is no scientific basis for the reduction of this risk. (Miyazaki prefiled testimony R. 000151; see also R. 000355- 000363) Indeed, the numerous reviews by various people within the CINGSA organization make clear that the rewrite was done to justifi the decision or conclusion as opposed to reaching or deriving a conclusion. Indeed, at various points the risk was identified as 5% before it was finally reduced to 1 %. (Winslow email to Walsh, Sep 30, R. 000438. See also WP2 draft with NNG comments, R. 000470) Again, there is no science to justify or explain the manipulation of these numbers. In a blatant admission that the paper was being written in an attempt to protect CINGSA from the adverse consequences of this financially driven decision to not remediate KU 13 -8, C1NGSA wrote on October 3, 2010: "The report has to be viewed as a 25 cornerstone historical document that should be as conclusive as possible Jr o the reasons for not entering KU 13 -8 now. If a catastrophic event would occur in the . frture the deciding issue of current economic concerns addressed in the report would not be any defense. Is there any need to have legal review the final product and make sure it does not have anything that would be detrimental against CINGSA in f {cure discovery, or should it be privileged (or is it too late for that?).'' (S Thomas to Lavengood, Oct 3 email, R. 000452) Of course none of this information was before the AOGCC at the October hearing because it had not been disclosed by CINGSA. Indeed, because there was no public record of CINGSA's decision to renege on its commitment to remediate KU 13 -8, neither Inlet Entities nor anyone else from the public was put on notice of this issue or prepared to address this issue. The AOGCC issued the SIO on November 19, 2010. (R. 000494 - 000507) The only references to KU 13 -8 are as follows: "In accordance with existing Commission regulations, KU 13 -8 (1964, Unocal exploratory well) was plugged and abandoned with a cement plug set from 1000' to 1270'. The 8 -5/8" casing shoe (in 12 3/4" hole is set at 1159' and ceinented in place. 7-5/8" hole was drilled to 5506'. The 7-5/8" well bore was not cased. A sundry reports that this well was left with a 4 foot standpipe and placard marking the abandoned location. CINGSA's investigations have shown that the pipe / marker have since been cut off and plugged, and the well casing stub is now buried below grade. Through recent land and magnetometer • • surveying efforts, CINGSA has located what appears to be the buried casing." (R. 000500) "CINGSA shall install, operate and maintain a gas detection and alarm system in all buildings located within 50 feet of the surface location of well KU 13 -08, unless prohibited from doing so by either the owner or the lessee of the land upon which KU 13 -8 is located." (R. 000503) On December 14, 2010 Inlet Entities moved for reconsideration of the S1O. (R. 000042 - 000492) AOGCC issued a decision on Appellants' motion for reconsideration on February 18, 2011, and confirmed its prior decision without discussion. (R. 000002) This appeal ensued. II. STANDARD OF REVIEW An agency's factual findings are reviewed under the substantial evidence standard, under which reversal is appropriate only if the Court "cannot conscientiously find that the evidence supporting [the agency's decision] is substantial." Substantial evidence is "such relevant evidence as a reasonable mind might accept as adequate to support a conclusion. " " The substitution of judgment standard applies where the questions of law presented do not involve agency expertise or where the agency's specialized knowledge and experience would not be particularly probative as to the meaning 13 May v. State, Commercial Fisheries Entry 69111111 175 P.3d 1211, 1216 (Alaska 2007); Leigh v. Seekins Ford, 136 P.3d 214, 216 (Alaska 2006) (citation omitted). ?7 of the statute. This standard permits the Court to substitute its own judgment for that of the agency even if the agency's decision had a reasonable basis in law. j 5 Questions of law and issues of constitutional interpretation are reviewed de novo.' The rational basis test is used where the questions at issue implicate special agency expertise or the determination of fundamental policies within the scope of the agency's statutory function.) 7 When applying the rational basis test, the Court will uphold an agency's decision if it is supported by the facts and has a reasonable basis in law,' 14 Northern Timber Corp. v. State. Dep't of Transp., Public Facilities, 927 P.2d 1281 n. 10 (Alaska 1996); Tesoro Alaska Petroleum Co. v. Kenai Pipe Line, 746 P.2d at 903. 15 M. 16 Simpson v. State, Commercial Fisheries Entry Comm'n, 101 P.3d 605, 609 (Alaska 2004) citing Revelle v. Marston, 898 P.2d 917, 925 n. 13 (Alaska 1995). 17 West v. Municipality of Anchorage, 174 P.3d 224, 226 -227 (Alaska 2007) citing State v. Pub. Safety Employees Ass'ii, 94 P.3d 409, 413 (Alaska 2004). 18 State, Dept. of Admin. v. Bachner Co., Inc., 167 P.3d 58, 61 (Alaska 2007) (citation omitted). 18 • III. ARGUMENT A. AOGCC Violated Inlet Entities' Constitutional Right to Due Process of Law and Its Own Governing Regulations By Failing to Require Cook Inlet Natural Gas Storage Alaska, LLC ( "CINGSA ") to Amend its SIO Application to Give Notice of Its Request to No Longer Include Remediation of KU 13 -8 as a Part of Its Application, and By Engaging in Ex -Parte Communications with CINGSA and Failing to Include Those Ex -Parte Communications with CINGSA as a Part of the Public Record, and By Not Holding a Public Hearing on CINGSA's Decision to Not Remediate KU 13 -8. A fundamental right under the U.S. and Alaska Constitutions is due process of law, The Due Process Clause of the Alaska Constitution provides that "No person shall be deprived of life, liberty, or property without due process of law" and guarantees a right of meaningful access to the courts in civil actions. Alaska Const. art. 1 § 7. "[P]rocedural due process under the state constitution requires `notice and opportunity for hearing appropriate to the nature of the case.'" Carvalho v. Carvalho, 838 P.2d 259, 262 (Alaska 1992) (quoting Aguchak v. Montgomery Ward Co., 520 P.2d 1352, 1356 (Alaska 1974). At the core of due process is an "opportunity to be heard and the right to adequately represent one's interests." State, Dep't of Natural Res. v. Greenpeace, Inc., 96 P.3d 1056, 1063- 64 (Alaska 2004) (quoting Matanuska Maid, Jnc. v. State, 620 P.2d 182, 192 -93 (Alaska 1980)). Alaskan courts recognize meaningful access to the judicial system as a fundamental right under the Alaskan Constitution. See Public Employee Retirement System v. Gallant 153 P.3d 346, 350 (Alaska 2006) (recognizing the right of "litigating" as a fundamental right); Peter v. Progressive 29 • • Corp., 986 P.2d 865, 872 (Alaska 1999); see also Patrick v. Lynden Transport, Inc., 765 P.2d 1375, 1379 (Alaska 1988); Busli v. Reid, 516 P.2d 1215, 1219 -21 (Alaska 1973). In addition to the Constitutional requirement of due process, AOGCC's own regulations require public notice and a public hearing prior to issuing a SIO. 20 AAC 25.540. CINGSA's July 27, 2010 SIO application expressly stated that it intended to remediate KU 13 -8 to bring it in compliance with current AOGCC standards for abandoned wells. (R. 000828, 000888) On September 13, 2010 Inlet Entities requested a public hearing. (R. 000696 - 000707) On more than one occasion Inlet Entities made clear that its concern was the proper remediation of KU 13 -8 to protect its plant, and employees. (Tr. 128) That is, Inlet Entities requested the public hearing and came to the public hearing to address how to properly remediate KU 13 -8, not whether that remediation should occur at all, as the public record gave no notice that CINGSA had decided to renege its express co dg o � p commitment to remediate KU 13 -8. (R. 000704, 000780) The Commission's November 19, 2010 decision states that CINGSA amended its application on September 30, 2010. (R. 000494) This references the purported amendment to no longer remediate KU 13 -8. In fact, however, this "amendment" was a private email from Rick Gentges at CINGSA to Winton Aubert at the AOGCC. (R. 000411) Inadvertently or not, this email "amendment" was not made a part of the public record in advance of the hearing. Inlet Entities first learned of CINGSA's decision to renege on its commitment to remediate KU 30 • • 13 -8 at the public hearing. (Tr. 19, L. 4 -16; Tr. 120, L. 5 -8) Following the public hearing Inlet Entities requested information to justify this change of position. (R. 000619- 000620) This email "amendment" was not provided to Inlet Entities until October 27, 2010, the day the record closed. (R. 000512) Staff at AOGCC apologized stating that Mr. Aubert had inadvertently neglected to forward this email to staff so that it could be put into the public record. The failure to notify Inlet Entities or the public in general of this material amendment on the precise issue for which Inlet Entities had requested the public hearing was a violation of Inlet Entities' due process rights and the public hearing process. There was simply no opportunity for Inlet Entities to address why not remediating KU 13 -8 would not be proper or prudent since Inlet Entities had not been informed of CINGSA's decision to renege on its commitment to remediate the well. For this reason alone, the Commission's decision should be set aside and a new public hearing scheduled. Moreover, internal emails obtained from CINGSA in discovery during the Regulatory Commission of Alaska hearing process strongly suggest that there was substantial ex parte contact between CINGSA and the AOGCC concerning the issues to be addressed at the public hearing. (R. 000441 -000444, 000447) Indeed, this documentation suggests that the AOGCC essentially informed CINGSA, before the hearing was held, that it would not be required to remediate KU 13 -8. In fact, the Commission's decision mirrors what CINGSA was stating in internal emails before the hearing including the decision to require installing gas detection 31 • • equipment near the wellhead of KU 13 -8. (R. 000452) This ex parte decision making process is a violation of Inlet Entities' due process rights, the public hearing process and the governing regulations. B. AOGCC Erred By Failing to Comply with Its Own Regulations Governing Well Plugging Requirements. The AOGCC's governing regulations require that an operator of a gas storage reservoir identify and report on the mechanical condition of each well that penetrates the storage zone. 20 AAC 25.252(c)(12). It further requires that all such wellbores be properly repaired or plugged. 20 AAC 25.252(h). In this case, KU 13 -8 was identified as a well that penetrates the reservoir and its mechanical condition was reported as "requiring remediation ". (R. 000828, 000871, 000888) With regard to proper repairing or plugging, the AOGCC's regulations require that all cased and uncased portions of a wellbore are plugged in a manner that ensures that all hydrocarbons and freshwater are confined to their respective indigenous strata, and are prevented from migrating into other strata or to the surface. 20 AAC 25.112. Both the cased and uncased portions of the wellbore must meet expressly identified "minimum requirements." Id. Essentially, a wellbore is required to have cement isolation plugs above and below each hydrocarbon-bearing strata. I d. It is undisputed that KU 13 -8 meets none of those Y g . requirements for either the cased or uncased portions of the wellbore. (R. 000828, 000871, 000888) 32 • The AOGCC's decision states that KU 13 -8 was plugged and abandoned "[i]n accordance with existing Commission regulations." This is false, or misleading at best, as the AOGCC did not exist in 1964. While the well may have been abandoned in accord with 1964 federal standards those standards are no longer acceptable anywhere, especially not for a well that penetrates an active gas storage reservoir. It is undisputed that the manner in which KU 13 -8 was abandoned in 1964 does not come close to meeting the requirements of 20 AAC 25.112 for either the cased or uncased portions of that wellbore. (R. 000391, 000393- 000394, 000828, 000871, 000888) The AOGCC's decision fails to even address why remediation of KU 13 -8 is not required. Presumably, the AOGCC is relying on CINGSA's argument that the historical production data and material balance analysis suggests that the reservoir functions as a pressure depletion reservoir, and that there is no historical evidence of cross -flow between the Sterling C and the formations lying above and below. But even if the evidence presented to the AOGCC by CINGSA was accurate, there is no guarantee that cross -flow or migration will not occur in the future, especially under storage conditions with relatively rapid cyclical changes in reservoir pressures. The regulations require proper plugging even for wells located outside but within a quarter mile of the reservoir within a quarter mile if 19 It is not certain that the well abandonment was in compliance even with the standards acceptable in 1964. Just a few months later, in 1965, several inadequacies were noted. (R. 000275) 33 • they are even "a possible" conduit for cross flow. 20 AAC 25.252(h). Thus, the AOGCC failed to enforce its own regulations and this Court should order that CINGSA remediate KU 13 -8 to comply with those regulations. Moreover, if historical production data suggesting that there has been no evidence of cross -flow is sufficient to justify not remediating KU 13 -8, then why is that same evidence not sufficient to justify ignoring CLU -12 as well? The AOGCC concludes that because the lower portion of CLU -12 does not isolate the Sterling C from the upper Beluga which lies below the Sterling C, CINGSA is required to re -enter and remediate that we11. But the same is true for KU 13 -8 as well; KU 13 -8 does not have isolation plugs isolating the Sterling C from either the upper Beluga lying below the Sterling C, or the formations lying above the Sterling C. In other words, KU 13 -8 was a much earlier and more primitive wellbore compared to CLU -12, and it was abandoned in a manner that does not isolate the Sterling C from either the reservoir lying above or below the Sterling C. The AOGCC provides no explanation for treating these two wells differently. If the historical evidence of lack of cross -flow is sufficient to justify ignoring KU 13 -8 and its lack of isolation plugs, then the same evidence would justify ignoring CLU -12 and its lack of isolation plugs as well. This arbitrary decision to treat KU 13 -8 differently than CLU -12 and contrary to AOGCC's own governing 20 CLU -12 is a Marathon well. Because this well is not within CINGSA's control, AOGCC's regulations require that CINGSA present evidence that the well has been properly repaired or plugged prior to issuing the SIO. This was not done in this case and for this independent reason the AOGCC's SIO should be reversed. 34 • • regulations requires the Court to reverse the AOGCC's decision and order that KU 13 -8 be remediated to conform with 20 AAC 25.112. The applicability of 20 AAC 25.252 and 20 AAC 25.112 is a question of law which this Court reviews de novo. C. The AOGCC's Finding that KU 13 -8 Need Not Be Remediated, and That No Further Inspection Or Base Line Testing Is Required, Is Not Supported By Substantial Evidence. The first step in determining whether failure to remediate KU 13 -8 poses a risk to the performance of the reservoir or to the safety of Inlet Entities or the public in general lies in looking at the technical papers prepared for CINGSA before CINGSA had a motive or reason to obtain a different result. Both the paper prepared by Petrotechnical Resources of Alaska ( "PRA ") (R. 000241- 000250) and a paper prepared by Netherland Sewell Associates, Inc. ( "NSAI ") (R. 000391- 000395) "recommend that KU 13 -8 be replugged to isolate the Sterling C Gas Pool between cement plugs, consistent with Alaska abandonment requirements, and to prevent potential gas migration from the Sterling C during gas storage operations." (R. 000391) This recommendation was made despite the 21 Northern Timber Corp. v. State, Dept of Transp., Public Facilities, 927 P.2d 1281 n. 10 (Alaska 1996); Tesoro Alaska Petroleum Co. v. Kenai Pipe Line„ 746 P.2d at 903. 22 As will be more fully discussed, CINGSA's decision to "take a second look" at KU 13 -8 was not the result of new technical information but, rather, resulted from difficulty with accessing Inlet Entities' property for purposes of inspection/remediation. (See R. 000421- 000458). CINGSA has now been issued a Certificate of Public Convenience and Necessity ( "CPCN ") and, as a result, has eminent domain powers. AS 42.05.631. Thus, any concern regarding access is moot. 35 • fact that "[p]erformance of the Sterling C Gas Pool indicates that the KU 13 -8 has not allowed gas or reservoir fluid to migrate from the Sterling C to another formation." (R. 000391. See also R. 000241) The second step is to look at why and how that recornmendation was changed. And what is striking is not only the strong evidence demonstrating that it was done for timing, Logistical and financial reasons, but the utter lack of evidence that it was done for any other reason. There is no paper from a consulting finn opining that PRA and NSAI got it wrong. There are no emails stating that significant new information was learned as a result of further inspection or testing. Indeed, no testing or inspection of the well has ever been done. Rather, the overwhelming evidence (R. 000421- 000458) supports the conclusion that CINGSA became frustrated with having to negotiate with Mr. Goddard and sought to make him irrelevant by making KU 13 -8 irrelevant. In fact, in hearings before the RCA CINGSA admitted that it was not able to negotiate access with Mr. Goddard, that it attempted to go around him by requesting access from the City of Kenai, an attempt that also was unsuccessful, and that only after those unsuccessful attempts to access the property did it reconsider the issue ofremediating KU 13 -8. (Excerpt p. 2, L. 7 -17) Further, Mr. Lavengood from Northern Natural Gas, one of CINGSA's investors, admitted that he then became the "point man" on the "Goddard issue." (Excerpt pp. 10 -11) The 23 Mr. Goddard testified that CINGSA refused to contact him for purposes of negotiating his list of concerns. 36 • emails from and to Mr. Lavengood (R. 00042 1 - 000458) make clear that the decision to take a second look at KU 13 -8 was the result of frustration over the "Goddard issue" and not a matter of maturing science. How the recommendation was changed is equally striking. (See R. 000459- 000470, R. 000486- 000492) There is no new information. There is only 24 At a minimum this evidence should cause the Court to take an independent look at the evidence regarding KU 13 -8. If it does so, it will see that the material balance analysis chart provided by CINGSA to the AOGCC in October 2010 contained erroneous data. The last data points on the chart reflecting pressure readings from October 2009 are not properly placed on the chart. Rather than show a smooth or consistent decrease in pressure with production, the latest pressure readings from October 2009 show that despite the fact that 20% of all remaining gas had been produced since the previous pressure reading in June 2008, that pressure actually increased slightly as opposed to decreasing as suggested by CINGSA's erroneous data points. CINGSA was forced to admit these erroneous data points on cross examination in front of the RCA. (T. Walsh Nov. 12, Excerpt pp. 7 -8). The Court will also see that the gas -water ratio changed substantially in 2004 and more dramatically in 2008. This increased water production could have resulted from either formation water encroaching into the production area (i.e. water drive) or water entering the formation from outside (i.e. leaking wells). The source of this water into the producing zone has not been established. Reviewing evidence regarding KU 13 -8 will also show that no physical inspection or tests have been conducted on KU 13 -8; when Ku 13-8 was first drilled and abandoned a number of problems were encountered which suggest that the cement plugs or annular seals could be compromised; and that the geophysical logs suggest that the Sterling C interval encountered in KU 13 -8 is not "tight" and that the presence of storage gas during operations could dehydrate the clay mineral and reduce any formation damage. Each of these problems is discussed by Brent Miyazaki in his report regarding KU 13 -8. (R. 000060- 000068) But no matter what the Court concludes about the history of KU 13 -8 as a result of looking at this evidence, there is no escaping the conclusion reached by NSAI in mid October 2010 that "none of the explanations for lack of crossflow can assure that crossflow will not occur in the future" and that "successful replugging of the KU 13 -8 is the best way to minimize the potential for crossflow in the KU 13 -8 well when the Sterling C is under storage operations." (R. 000472) 37 the historical evidence that KU 13 -8 does not appear to have allowed gas or reservoir fluid to migrate from the Sterling C to another formation. But that was already known when PRA and NSAI made their recommendations that KU 13 -8 should be replugged. (R. 000241- 000250, R. 000391 - 000395) What was unknown then and is still unknown now, is exactly what is causing KU 13 -8 to be plugged and whether it will remain that way over the long life and repeated pressure cycling of gas storage operations. And the answer to that is still, "no one knows." Indeed, as of October 13, 2010, even after PRA and NSAI were asked to take a second look at KU 13 -8, NSAI was still stating that "none of the explanations for lack of crossflow can assure that crossflow will not occur in the future" and that "successful replugging of the KU 13 -8 is the best way to minimize the potential for crossflow in the KU 13 -8 well when the Sterling C is under storage operations." R. 000472) And the acknowledged risk is not just for Lost And Unaccounted For gas ( "LAUF gas "). Privately, CINGSA and its investors acknowledge that there is a risk, even if it is shall, for a catastrophic event: (S Thomas email Oct 5: "Dave is concerned that it may take a period of time for the data trends to eventually be recognized as potential migration. The extended timefrarneJor recognition may lead to a more significant event. " R. 000458) 25 Even the final redrafts of the PRA and NSAI papers, which were heavily edited by CINGSA to achieve the desired result (R. 000459- 000470, R. 000486- 000492), still conclude that remediation is the safest and best way to ensure that gas does not migrate from the reservoir using KU 13 -8 as a conduit. 38 • • (S Thomas email to R Gentges Sep 30: With the location of the well in the cannery facility any fixture gas migration could be very serious If gas gets up the well bore to the casing, and the cement bond is poor, would gas eventually get to the surface?" R. 000446, 4th bullet point) (S Thomas to Lavengood, Oct 3 email: "Tire report has to be viewed as a cornerstone historical document that should be as conclusive as possible for the reasons for not entering KU 13 -8 now. If catastrophic event would occur in the future the deciding issue of current economic concerns addressed in the report would not be any defense. Is there any need to have legal review the final product and make sure it does not have anything that would be detrimental against CINGSA in fixture discovery, or should it be privileged (or is it too late for that ?) " R. 000452) Even NSAI attempted to shield itself from liability for a future catastrophic event by stating that its conclusion that the risk of gas migration to the surface is small "is based on the integrity of the existing well plugs to prevent migration to the surface of KU 13 -8." (R. 000483, Oct. 15, 2010 email from S. Thomas to K. Lavengood attaching NSAI recommendation; see also NSAI report at R. 000473 "This assumes that the quality of the existing cement plugs is still good. ") But no one knows anything about the integrity of the existing well plugs because they have not been tested or inspected. Essentially NSAI states that the risk of gas migrating to the surface is small assuming that the old well plugs and annular seals are sound, but they have not attempted to ascertain if, in fact, those assumptions are true. (R. 000473) 26 Brent Miyazaki's report (R. 000060- 000068) expressly discusses the fact that no inspection of KU 13 -8 has been done, that there is good reason to suspect that the 46 year old cement plugs and /or annular seals are not sound or will not remain so, and that inspecting KU 13 -8 is the absolute minimum that must occur. He states 39 • • Brent Miyazaki is one of the foremost experts in the world on the subject of well integrity in relation to gas storage operations. He has published a number of pertinent articles in peer reviewed publications and is constantly in demand as a featured speaker at large international conferences related to the gas storage industry. He has been employed by the California Public Utilities Commission ("CPUC") on a number of occasions to assist the CPUC to review and consider numerous applications for new gas storage facilities in California, and has participated in the difficult decisions associated with the decommissioning of problematic storage facilities. Mr. Miyazaki examined substantial information regarding CINGSA's gas storage project in general and KU 13 -8 in particular, and wrote a detailed paper making recommendations for addressing the risks of gas migration. (R. 000060-000068) His recommendations are pragmatic and based upon both industry practice and experience as well as specific data related to CINGSA's project. In essence, his recommendation is identical to the recommendations of PRA and NSAI before they were asked to reconsider their recommendations; Mr. Miyazaki recommends that both CLU -12 and KU 13 -8 be remediated to meet the current standards for plugged and abandoned wells. In addition, Mr. Miyazaki reconunends that soil -gas surveys be conducted to establish baseline conditions for future monitoring, that an on -going surface and subsurface monitoring program be initiated, and that data concerning the pressure that it is impossible to state that gas cannot or will not migrate to the surface using KU 13 -8 without such an inspection. 40 • • readings of the reservoir be made publicly available to ensure that timely action is taken in the event of an anomalous reading. CINGSA admitted to both the AOGCC and the RCA that its budget expressly includes money for remediating both CLU -12 and KU 13 -8. ( AOGCC transcript day 1 Oct 19 2010, Richard Gentges page 19, lines 4 -22; Excerpt p. 4, L 1 -17) It further acknowledged that an order requiring it to remediate both of those wells would be acceptable. (Id.) Finally, any legitimate concern it may have had regarding access is now moot with the issuance of CINGSA's CPCN and its concomitant power of eminent domain. Accordingly, there is no justification for not requiring CINGSA to remediate KU 13 -8. In the words of one of CINGSA's insiders, doing so is "(relatively) cheap insurance." (R. 000450) In short, there is not substantial evidence to justify the AOGCC's finding that remediation of KU 13 -8 is no longer required. Indeed, the AOGCC does not even attempt to justify this conclusion. Rather, it makes the false statement that KU 13 -8 was plugged and abandoned "Din accordance with existing Commission regulations." This is patently false. The manner in which KU 13 -8 was plugged and abandoned does not begin to meet existing Commission regulations. Because the AOGCC's decision is not supported by substantial evidence this Court should require CINGSA to re- enter, re -plug and re- abandon KU 13 -8 to conform with the AOGCC's regulations set out in 20 AAC 25.112. CINGSA has already testified that it is prepared to do so and that its budget contains the funds necessary to comply with this regulation. 41 • N. CONCLUSION The Court need only look at CINGSA's application to the AOGCC wherein it identified KU 13 -8 as being substandard and in need of remediation, and the applicable AOGCC regulations (20 AAC 25.112 and 25.252), to conclude that the AOGCC has failed to enforce its own regulations. On that basis alone the Court should order CINGSA to properly rernediate KU 13 -8 to comply with those regulations. The Court need not defer to the agency on this decision. To the extent the Court digs deeper, it need only read White Paper 1 and White Paper 2 to conclude that there is no rational or substantial basis for reducing what was perceived as a 50 % chance of gas migration in the first paper, to a less than 1% chance in the second paper. The data and analysis are identical; only the conclusion was altered. And the background information, the emails and circulated drafts of the altered research paper, make clear that this change was not made on the basis of science. Indeed, most of the changes made in the circulated drafts were made not by the original researcher, but by the financiers of the project. There simply is no scientific evidence to justify this complete about face. For this additional reason the Court should order that CINGSA be required to remediate KU 13 -8 to comply with the AOGCC's well plugging requirements. Finally, if the Court does nothing else, it must order that the AOGCC conduct new public hearings on this issue as neither Inlet Entities nor the greater public was given proper notice of this requested departure from the AOGCC's regulations. It is imperative that the public be given notice of this intended 42 1 • departure from the regulations in advance of any hearing, in order to properly present testimony and /or cross examine the testimony of others. DATED: July _ , 2011 S EHL : & JARVI, LLC By: 1. 41 icha- T. Ste le ABA No.: 9106054 43 • • CERTIFICATE OF TYPEFACE Pursuant to Alaska Rule of Appellate Procedure 513.5(c)(1)(B), this certifies that 13 point, proportionally spaced, Times New Roman typeface was used in this document. CERTIFICATE OF SERVICE I hereby certify that on July 8, 2011, a copy of the foregoing Appellant's Brief was mailed to the following: Thomas A. Ballantine 111 Assistant Attorney General 1031 West Fourth Avenue, Suite 200 Anchorage, Alaska 99501 A. William Saupe Moira Smith Ashburn & Mason, PC 1227 West Ninth Ave., Suite 200 Anchorage, Alaska 99501 e & Jarvi, LLC 44 r 4k 3 • 411, IN THE SUPERIOR COURT FOR TI IE STATE OF ALASKA THIRD JUDICIAL DISTRICT AT ANCHORAGE VINCENT GODDARD, WILD PACIFIC SALMON, INC., and INLET FISH PRODUCERS, INC., Appellants, VS. ALASKA OIL AND GAS CONSERVATION COMMISSION, and Case No. 3AN-11-6305 CI COOK INLET NATURAL GAS STORAGE ALASKA, LLC, Appellees. MOTION TO COMPEL COMPLETE RECORD In preparing their brief and attempting to find proper citations to the record it came to appellants attention that the AOGCC has not provided the Court with a compete record of the evidence submitted to the agency. In particular, appellants submitted to the AOGCC two computcr disks. (R. 000058). Disc one contained discovery obtained from CINGSA and disc two contained transcripts from three days of hearings before the Regulatory Commission of Alaska. (Id.). Because these materials were submitted to the -5 AOGCC they should be included as a part of the record in this appeal. Appellants have jcog attached as an excerpt of record filed with their opening brief 11 pages that should have ckl been included as a part of the record. g MOTION TO COMPEL COMPLETE RECORD Goddard et al v. AOGCC and CINGSA Case No. 3AN- II- 6305 CI Page I of 2 • • DATED this day of July, 2011. STEHLE & JARVI, L.L.C. Attorneys fo laintiff By: _ -- icha 1. Stehle, ATh054 CERTJF1CATE OF SERVICE I hereby certify that on July , 2011 a true and correct copy of the foregoing was served by US mail on the following: Thomas A. Ballantinc Senior Assistant Attorney General 1031 W 4 Ave., Stc. 200 Anchorage AK 99501 A. William Saupe Moira Smith Ashburn & Mason, PC 1227 W 9 Ave., Stc. 200 Anchorage AK 99501 ifiE41 —i 03 § .-108 >u, 5,t ce I I P O. MOTION TO COMPEL COMPLETE RECORD Goddard et aL v. AOGCC and CINGSA Case No. 3AN-I I - 6305 Cl Page 2 of 2 • • IN T1 LE SUPERIOR COURT FOR THE STATE OF ALASKA THIRD JUDICIAL DISTRICT Al' ANCHORAGE VINCENT GODDARD, WILD PACIFIC SALMON, INC., and INLET FISH PRODUCERS, INC., Appellants, vs. ALASKA OIL AND GAS CONSERVATION COMMISSION, and Case No. 3AN-11-6305 CI COOK INLET NATURAL GAS STORAGE ALASKA, LLC, Appellees. ORDER ON MOTION TO COMPEL COMPLETE RECORD IT IS SO ORDERED. The Alaska Oil and Gas Conservation Commission shall have until 201 to file a complete record of the evidence submitted to the agency. DATED at Anchorage, Alaska, this day of , 2011. Michael R. Spaan Superior Court Judge 1 i MOTION '10 COMPEL COMPLETE RECORD - ORDER Goddard et al. v. AOGCC and CINGSA Case No. 3AN-11- 6305 ('I Page I of 2 • • CERTIFICATE OF SERVICE I hereby certify that on July 2011 a true and correct copy of the foregoing was served by US mail on the following: Thomas A. Ballantine Senior Assistant Attorney General 1031 W 4 Ave., Ste. 200 Anchorage AK 99501 A. William Saupe Moira K. Smith Ashburn & Mason, PC 1227 W 9 Ave., Ste. 200 Anchorage AK 99501 ifL4cc;t7Tm Signature a P > in 0?!1; .aE MOTION TO COMPEL COMPLETE RECORD - ORDER Goddard ed al. v. AOGCC and CMIGSA Case No. 3AN-1 I- 6305 CI Page 2 of 2 • Y • • • RECEIVED LAW AGO ANC JIJL 11 2011 A1'f 1(J :2A IN THE SUPERIOR COURT FOR THE STATE OF ALASKA THIRD JUDICIAL DISTRICT AT ANCHORAGE 3AN -11 -6305 CI VINCENT GODDARD, WILD PACIFIC SALMON, INC., and INLET FISH PRODUCERS, INC., Appellants, vs. ALASKA OIL AND GAS CONSERVATION COMMISSION, and COOK INLET NATURAL GAS STORAGE ALASKA, LLC, Appellees. APPEAL OF AGENCY DECISION ALASKA OIL AND GAS CONSERVATION COMMISSION Daniel T. Seamount, Jr., Chair, and Cathy P. Foerster, Commissioner Docket S10-10-05, STORAGE INJECTION ORDER No. 9 and SUBSEQUENT ORDER ON RECONSIDERATION APPELLANTS' EXCERPT OF RECORD Michael T. Stehle Stehle & Jarvi, LLC 1200 R St., Ste. B Anchorage AK 99501 907 - 677 -7877 ABA No.: 9106054 1 someone to do something with the well. That was a very 2 separate issue with Chevron. This letter exists. We don't 3 dispute its authenticity and we don't dispute the date and 4 don't dispute that CINGSA was discussing those other regulatory 5 issues with Chevron. As far as CINGSA contacting the City of 6 Kenai to request access to the property, yes, there is a 7 letter. I don't know if it's in the record here, but there was 8 a letter sent to the City of Kenai requesting access to the 9 property. 10 ALJ WOOD: Thank you, Mr. Findley. 11 MR. STEHLE: I -- I'm going to move on, Your Honor. 12 ALJ WOOD: Thank you. I was going to remind everyone that 13 we are -- not only are we trying to accommodate CINGSA as far 14 as their witness availability, we are trying to accommodate the 15 Inlet entities witnesses as well. So I don't want to limit 16 anyone's ability to cross examine but please proceed with that 17 in mind. And I have completely forgotten what the ques -- 18 original question was and what the objection was. So I -- if 19 you want to withdraw it and move on, that will get us going. 20 MR. STEHLE: I think given the stipulations and the 21 colloquy of counsel, I mean I think that I am prepared to move 22 off the access issue. If the witness would turn 23 ALJ WOOD: Just for clarify about it, I don't think there 24 was any agreement -- I don't want to slow this down, but there 25 was no agreement on a stipulated -- any stipulated facts. I 211 PAGE 4 4 1 mean there was representation by Mr. Findley, you wanted to add 2 a couple of caveats that was not accepted. If there's clarity 3 on the stipulation I'm happy to get it on the record. If you 4 want to just move on, we can do that as well. 5 MR. FINDLEY: If you want, I can state what we are willing 6 to agree to, and if you agree to that we'll just move on. 7 MR. STEHLE: We're agreed to stipulate to one, that CINGSA 8 requested access from Mr. Goddard. Number 2, CINGSA and Mr. 9 Goddard were not able to agree on terms of access. And number 10 3, CINGSA sent a letter to the City of Kenai requesting access. 11 MR. STEHLE: And the only thing I would ask is were you 12 able to get access from the City of Kenai? 13 MR. FINDLEY: And there is no very formal response from 14 the City of Kenai to that letter. 15 MR. STEHLE: I'll accept that and move on, Your Honor. 16 ALJ WOOD: Okay. We'll put those stipulated facts on the 17 record and 18 MR. FINDLEY: Thank you. 19 ALJ WOOD: Thank you. Please proceed, Mr. Stehle. 20 Q (By Mr. Stehle) Mr. Gentges, if you'd turn to page -- to 21 Exhibit H -2, page 977 and then mark that one and then also 22 to H -2, page 233 and following. 23 A Yes, I have those. 24 MR. FINDLEY: Counsel, I'm sorry, I missed those page 25 numbers. 212 mo ExcEM1PT PAGE 2 OF t_„_I • 1 the location. And there are records in AOGCC's files that 2 show where the surveyed location of this well is. When we 3 first approached -- or first looked at this project and we 4 realized this well was in its condition that it's in today 5 and believed we might need to re -enter the well, we wanted 6 to confirm its location. We saw from maps that Mr. 7 Goddard's facilities were, you know, roughly in the same 8 area as the well and we approached him about gaining 9 access to confirm the location. And he initially allowed 10 us to go in and survey in the coordinates, shoot the 11 survey in to see -- from the original drilling survey and 12 confirmed where the location of the well would be using 13 those survey coordinates. We then asked him for 14 permission to run a sophisticated magnetic survey that 15 would allow us to penetrate the ground and detect magnetic 16 -- you know, metallic objects below ground. And he agreed 17 to allow us to do that. And that second survey confirmed 18 that there is a large, metal mass at the survey location 19 of the well where it was originally surveyed in and at the 20 same location that we used simple survey, you know, civil 21 survey coordinates before we did the magnetic survey. If 22 you're asking have we dug up the ground and confirmed that 23 the well is there? The answer is no. 24 Q And the age of the well is considerably older than any of 25 the other wells that penetrate the reservoir, just the age 294 EXHIBIT G-xc * PT PAGE 3 OF U • . 1 REDIRECT EXAMINATION 2 BY MR. FINDLEY: 3 Q Sorry, Rick, you're almost there. 4 A Cheers. 5 Q You recall Commissioner Wilson asked you about the 13 -8 6 well and also, I believe, Commissioner Giard asked you 7 about the well as Commissioner Giard asked you about 8 monitoring wells. If the AOGCC orders CINGSA to re -enter 9 the 13 -8 well and plug the well, will CINGSA do so? 10 A Yes, sir. 11 Q If CINGSA is ordered to re -enter and re -plug the well and 12 is not successful in doing so will the AOGCC allow CINGSA 13 to inject gas into the reservoir? 14 A No. 15 Q If the AOGCC orders CINGSA to have a monitoring well or 16 monitoring wells, will CINGSA do so? 17 A Yes, it will. 18 Q Okay. You remember Commissioner Giard asked you about 19 infrastructure and whether there would be a CINGSA witness 20 to discuss infrastructure issues? 21 A Yes. 22 Q What is your understanding why CINGSA's customers have 23 offered testimony on infrastructure issues, but why CINGSA 24 itself has not? 25 A Well, CINGSA hasn't -- hasn't offered witnesses because 313 EST e'w.r- Lpr PAGE OF-1—. • 1 the Sterling C. Now, isn't that a reflection of the fact 2 that you looked at the fact that production had taken 3 place out of the Beluga prior to the Sterling C being 4 produced and that it had not negatively impacted the 5 native pressure of the Sterling C? 6 A Yes. However, we had not downloaded the Beluga production 7 information and plotted it against the CLU -6 production 8 information at that time, so this was a very general 9 statement of that fact. 10 Q Okay. But it supported your conclusion in White Paper 1 11 that based upon this historical production data Sterling C 12 seemed -- appeared to be isolated? 13 A We felt that it was isolated, yes. 14 Q Okay. And notwithstanding the fact that the historical 15 data appeared to support the fact that the Sterling C was 16 isolated, you concluded in White Paper 1 that because you 17 didn't know why it was isolated, what mechanism was 18 keeping it isolated that there was a 50 percent chance 19 that in the future there might be some migration as a 20 result of KU 13 -8, is that correct? 21 A We did feel that there was some risk of cross flow between 22 reservoirs in that 13 -8 wellbore at that time. 23 Q Okay. What I'd like to do now is I'd like to -- well, let 24 me ask you this, when you went to make your presentation 25 to the AOGCC on October 19th did you share with them White 635 EX:MT & c o*. r PAGE ..____ OF sit • • 1 Paper 1 at that time? 2 A We did not deliver White Paper 1 to the AOGCC prior to our 3 hearing. It was not required. The supporting 4 information, all of the public information that went into 5 the generation of the White Paper had been supplied to the 6 AOGCC and is in their records. 7 Q But your conclusions in White Paper 1 were not shared with 8 the AOGCC? 9 A The conclusions from White Paper 1 were actually 10 incorporated in the application. 11 Q Insofar as you were recommending remediation of KU 13 -8? 12 A Um -hum, yes. 13 Q Okay. But by the time you made your presentation you had 14 decided that remediation was no longer required, is that 15 correct? 16 A We had done a significant amount more of design 17 engineering on the project and we did come to the 18 conclusion that we did not feel as though 13 -8 was as 19 critical a risk to this project as earlier envisioned. 20 Q If you'll turn to JOR -4 page 46 of 53. 21 MR. SAUPE: Excuse me, what page are you on (ph)? 22 MR. STEHLE: Page 46 of 53. 23 Q And do you have that, sir? 24 A I do. 25 Q Okay. And this is the Material Balance Analysis that we 636 EST L ? x cit ? PAGE b Of 1f 1 is this is the power -- this is one of the slides, if you 2 will, from the power point presentation given to the 3 AOGCC, yes. 4 A Okay. Just to make it clear that this is not specifically 5 about 13 -8. It's about the isolation of the Sterling C 6 reservoir. 7 Q That's correct. 8 A Okay. 9 Q That's correct. And looking at this slide from the power 10 point presentation given to the AOGCC you see that there 11 is a point that's identified on this chart that is not on 12 the chart that is on page 46 of 53 of JOR -4, do you see 13 that -- do you see that point marked lower than all of the 14 others and denominated as coming from October 22nd, 2009? 15 A I believe it's actually two points, but yes, I do see 16 that. 17 Q Okay. That point or those points marked October 22nd, 18 2009 are erroneous, is that correct? 19 A They were not on the original P/Z plot and our -- our 20 position at this point is those should not be on the plot. 21 They were inadvertently included in this graph. 22 Q Okay. In fact, the four dots that are higher up include 23 the information from October 22nd, 2009, correct? 24 A I believe that is correct. 25 Q So essentially an additional point was added further down 641 :T AGE 1 on this chart that was represented to be from data from 2 October 22nd, 2009 when, in fact, the October 22nd, 2009 3 is higher up at the same pressure level essentially or 4 very consistent or very close to the pressure level as the 5 May 16, 2008, correct? 6 A That is correct. And as I said these two points were 7 included inadvertently, but I will point out that these 8 two points are exactly on the line and have absolutely no 9 impact on the variance of the straight line curve. We 10 have done some analysis and the R squared (ph) of this 11 curve is .9945 showing that this is, indeed, a straight 12 line. Without those two points it is .9916 so it is -- 13 these two points have no impact on the curve. 14 Q Well, let me just ask you, sir, that -- when did you learn 15 that these two points on H -2, page 236 were erroneous? 16 A I believe these two points were identified as not included 17 on the table that was included in the Injection Order 18 Application in interrogatory provided by Dr. Robertson. 19 Q Okay. And has there been any attempt made by CINGSA that 20 you're aware of -- has CINGSA made any attempt to notify 21 the AOGCC that the data that it provided to them at the 22 hearing contained this inaccurate information? 23 A I do not know if that has taken place or not, but again I 24 will state that these two data points have absolutely no 25 impact on the outcome of the analysis. 642 PAGE ,_5" OF 11 • • 1 was a mistake. It wasn't filed in the -- it should have 2 been filed in the public, you know, file. And that was 3 upsetting. The -- then on the morning of the 27th as I 4 was putting finishing touches on several things that I was 5 submitting. I got another phone call and an e -mail that 6 disclosed that the -- that -- that Mr. Gentges had sent an 7 e -mail with a PowerPoint presentation attached to it to 8 the Commission on the 29th -- on the 30th of September 9 which was the first time that -- that CINGSA had suggested 10 to the Commission that they did not want to remediate KU 11 13 -8, so that discussion with Commission staff was 12 generated on the 30th of September. I was told on the 13 morning of the 27th as I'm writing my final statement, a 14 full week after the hearing was closed, that that e -mail 15 should have been part of the public record, and they're 16 sorry and it's not part of the public record. So it -- 17 it's part of H -2. It shows in there a date of September 18 29th on it. It actually became part of the public record 19 on October 27th as did Mr. Gentges' e -mail of September 20 30th. That became part of the public record on October 21 27th. We were also compromised in our ability to present 22 a proper picture to the AOGCC because CINGSA didn't 23 provide the back -up documentation. And we were -- you 24 read in my testimony that we were lucky basically to get 25 both White Paper 2 and White Paper 1. 831 � &caEP - PAGE _OF v .. 1 A Yes, thank you. I've actually been involved in the KU 13- 2 8 from Northern's perspective. And yeah, it -- it was 3 definitely a big concern. As an investor -- let me back 4 up, I guess. The project team through their property 5 acquisition was having difficulty reaching agreement with 6 Mr. Goddard 7 Q Yes. 8 A so 9 Q And I can understand. 10 A And so I was asked to lend a hand with that process. So 11 the first -- one of the first things I did was try to 12 understand why it is we need access to the property, so 13 that's when I was handed the White Paper number 1 for the 14 first time. And that raised considerable concerns for me 15 and Northern Natural Gas. And I should correct that it's 16 actually MidAmerican Energy who we are a subsidiary of 17 that is an investor 18 Q Okay. 19 A in the project. So when I first saw the White Paper, 20 you know, we had concerns whether is this even a viable 21 project. And so one of the first things we did was go 22 back to PRA and say, you know, is this -- I mean is this 23 really the risk that you're -- for this well because, 24 frankly, if it is, you know, we're not going to commit any 25 more money to the project until we get a better 841 PAGE._j(j OF N • 1 understanding of whether this is a -- this is the real 2 risk that you've identified here. And I guess from -- and 3 I'm not a technical person so I couldn't weigh the 4 credible of anything they've said there, but the -- I did 5 have questions about the 50 percent and other folks at 6 Northern Natural Gas had -- had asked questions as well 7 and c- -- and had -- basically asked -- had wondered 8 whether that was a real number or not is -- is the way 9 I'll characterize it. So we had asked PRA go back, you 10 know, you need to scrub this because I'm not sure if this 11 is going to be a viable project if that's really the risk 12 we're facing. Separately from that we as part of the due 13 diligence process before we became partners with SEMCO, we 14 had hired Netherland Sewell & Associates as an independent 15 consultant in evaluating this reservoir. So -- and 16 everything had come out very clear on that. And so when 17 this issue came up we then retained them again to address 18 this specific issue, again, as an investor of the project. 19 Q Uh -hum. 20 A So -- excuse me, so that was really the -- kind of the 21 process of going from, I guess, the White Paper 1 to White 22 Paper 2. When White Paper 2 was then completed, it, you 23 know -- it -- I -- I'm -- I live in Omaha, so I'm not 24 familiar with Alaska. And I wasn't familiar with PRA. 25 And just from my distance from -- from the -- I guess, the 842 PAGE A OF if #2 • Colombie, Jody J (DOA) From: Colombie, Jody J (DOA) Sent: Friday, May 13, 2011 9:52 AM To: 'Christina Ford' Subject: RE: Goddard v. AOGCC record Christina, Per our conversation yesterday afternoon the AOGCC will be preparing a digital copy of the record in 3AN -11 -06305 CIV. Furthermore, the CD should be ready for pickup late on Wednesday May 18, 2011. Jody Colombie From: Christina Ford f mailto:cford.stehlelaw@ gmail.coml Sent: Tuesday, May 10, 2011 3:24 PM To: Colombie, Jody 3 (DOA); mstehle.stehlelaw Subject: Goddard v. AOGCC record Hi Ms. Colombie, Per my conversation with you this afternoon, please have a copy of the record in this matter prepared for us, and notify me when it is ready so that I may pick it up. I understand that you wish to make the copies internally, and that you cannot do so until Thursday or Friday, so I will anticipate a call from you on Monday. As I work at two different offices, I think the easiest number to reach me at would be my cell, 907 - 229 -5113. Thank you for your assistance. Chrissie Ford Christina Ford Legal Assistant Stehle & Jarvi, LLC 1200 R St., Ste. B Anchorage, AK 99501 Tel. 907 - 677 -7877 Fax 907 - 677 -7894 1 • P ROFESSIONAL EIN - 13- 4333691 Invoice I Delivery- [REGAL / Date Invoice # opy 101 Post Road Phone: 277 -2679 Anchorage, Alaska 99501 Fax: 277 -2689 ? 3/29/2011 102769 /; www. prolegalcopy.com Bill To Ship To SOA / Oil & Gas Conservation Commission SOA / Oil & Gas Conservation Commission 333 West 7th Ave. 333 West 7th Ave. Anchorage, Alaska 99501 Anchorage, AK 99501 Client Matter Terms Ship Via RCA Hearing Net 15 Our Truck Description Qty Rate Amount CD Duplication 2 10.00 20.00 Attn: Jodi AMOUNT I ,e- - EN or CC_Z'21 f .r . ACC APPROVED_ ' , r, q / / • j t) i/ NI 14,/7/ o All work is complete! Total $20.00 Remit Payment To P.O. Box 201395 Anchorage, Alaska 99520 • Colombie, Jody J (DOA) From: Dawn Bishop - Kleweno [ Dawn. Bishop - Kleweno ©enstarnaturalgas.com] Sent: Thursday, May 12, 2011 4:04 PM To: Colombie, Jody J (DOA) Subject: AOGCC Record Hi Jody, As we discussed, ENSTAR would like a CD o f the record at the cost of $ 1.00. Thanks, Dawn Bishop - Kleweno ENSTAR Natural Gas Company 334 -7608 1 • • TRANSMITTAL OF AGENCY RECORD TO: Superior Court Clerk Date: April 17, 2011 825 West 4th Avenue (Court Address) Anchorage, Alaska 99501 FROM: Alaska Oil& Gas Conservation Comm (Name of Agency) Jody Colombie (Name of Person at Agency) 333 West 7th Avenue, Suite 100 (Address) Anchorage, Alaska 99501 RE: Case Name: Vincent Goddard et. al. vs Alaska Oil and Gas Conservation Commission Appeal Case Number: 3AN -11 -06305 CI Agency Case Number: Storage Injection Order No 9 Pagination of the agency file has been completed. In accordance with Appellate Rule 604(b)(1)(B)(ii) and (iii), the following items are being forwarded to you: 3 volumes of agency file (a copy) 0 list of exhibits being forwarded The file is numbered from (List only those not included in page 000001 to 000920 . the agency file.) 1 volumes of transcript (original) 1 envelopes/boxes containing exhibits 0 volumes of depositions (copies) 1 list of exhibits retained by agency other: oversized exhibit marked Exhibit 2 If the court needs any of the exhibits being retained by the agency, the court must contact the following person: Name: Jody Colombie Title: Special Assistant Phone No. 907- 793 -1221 7' April 17, 2011 ��id i _ Date I / A: fncy Representative Location: 333 West 7th Avenue, Suite 100, Anch AP -312 (3/01)(cs) TRANSMITTAL OF AGENCY RECORD • • L7" r-7 I i -t SEAN PARNELL, GOVERNOR Inc r /7 ; � V � � Lqi � t G,�p 1, L7 ALA.SKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COM3IISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 March 29, 2011 Michael Stehle Attorney at Law 1200 R Street, Suite B Anchorage, Alaska 99501 Re: Vincent Goddard, et. al. vs Alaska Oil and Gas Conservation Commission 3AN -11 -06305 CI Dear Mr. Stehle: In absence of an agreement between the parties or court order, Appellate Rule 604(b)(1)(B)(iv) requires all reasonable costs incurred in connection with copying the transcript and the agency file shall be borne by the appellant. The preparing agency may require advance payment of the costs as reasonably estimated by the agency. The Commission charges copy costs at $0.25 per page. The estimated number of pages in the administrative record is approximately 1,641. This estimate includes the transcripts that have been prepared, for which you are only billed the copying costs. The Commission also had duplicated two disks from the Regulatory Commission of Alaska's proceedings copied to CD's that was submitted for the record. The cost of this duplication was $20.00. The total required in advance of preparation of the record is $430.25. Sincerely, Is J (!' y J.t olombie S •ecial Assistant cc: A. William Saupe, Esq. Tab Ballantine, AGO 000001 • u . . ....I.L.... A[Ni\..... X....99a:a1aa.... ....7�NUS.L .... ...m..vacua.......cu..a..mvawianuau_, ......... .......(��q (� z W ELLS FAR60 BANK ALASKA, N.A. 0 1 2 4 9 3 LAW OFFICE OF MICHAEL STEHLE P.C. 'r ANCHORAGE, ALASKA www.wellsfargo.com w 1200 R ST., SUITE B S ANCHORAGE, AK 99501 89 5/1252 0 (907) 677 -7877 4/6/2011 k PAY TO THE I $ * *430.25 ORDER OF AOGCC Four Hundred Thirty and 25/ 100**, rtt, t*, t***, r***********, r****, r***, r************, t************+*** * * * * * * * * * * ***,r,r * * * * * * * * * * * * ** * DOLLARS u X AOGCC 333 W 7th Ave., Ste. 100 Y Anchorage AK 99501 -3539 1 1 z9' gE °F U I� . � W III MEMO ... AUTHORIZED SI ATU', °c, ' r 3AN -11 -6305 CI Goddard v. AOGCC 100L249311' 1:L2 520005?I: L9 749 3 2004li' LAW OFFICE OF MICHAEL STEHLE P.C. AOGCC C• •:.6.14 . 4/6/2011 012493 I. AOGCC transcript, file / _ 430.25 i ----- <:....) APR •1 & £8 X6118 �� j Ait al[;ige " Operating 3AN -11 -6305 CI Goddard v. AOGCC 7> 430.25 IN THE DISTRICT /SUPERIOR COURT FOR THE STATE OF ALASKA ; f2 " . THIRD JUDICIAL DISTRICT AT ANCHORAGE Vincent Goddard, .'.. Appellant, CASE NO: 3AN- 11- 06305CI vs. - Alaska Oil and Gas Conservation Commission, Appellee. N. t } NOTICE OF JUDICIAL {' ASSIGNMENT .E This case is assigned to the Honorable Judge Gregory A Miller for all purposes including trial. 3/22/2011 By: BHarris Date Deputy Clerk I certify that on 3/23/11 a copy of this order was mailed or delivered to: +, Michael T Stehle Alaska Oil and Gas Conservation Commission • Clerk: BHarris ,{'" f i ALASKA OIL AND GAS CONSERVATION COMMISSION 5 •', 333 W. 7TH AVE. STE. 100 clv2ANPRQ,RAGE AK 99501 Notice Of .1udieiat fi, ssgnment . • 0 . :i'fq 5,y IN THE SUPERIOR COURT FOR THE STATE OF ALASKA �' THIRD JUDICIAL DISTRICT AT ANCHORAGE : ;.,:.} }, Vincent Goddard, ;. �+ Appellant, Appeal CASE NO: 3AN- 11- 06305CI .: , :>):;.. vs. t ` , 3Y), NOTICE OF PREPARATION • ` ` , l; r. Alaska Oil and Gas Conservation :_ { Commission OF RECORD IN AN : , , r) , ;` �,, A ADMINISTR APPEAL '': Appellee. :'' To Alaska Oil and Gas Conservation Commission ; 7 Attached is a copy of the notice of appeal filed on 03/21/2011 from an order or decision of your agency. ' ''F Pursuant to the Appellate Rules: ki :'' 2. Within 10 days of service of this notice, the agency must file with this court a list of names and addresses of all counsel and pro se parties who appeared in the matter before the agency. '...!• P. Please use the enclosed form AP -311. Appellate Rule 602(c)(2). 2. The agency must number the pages of the agency file consecutively throughout all volumes. 44 The agency shall forward the following to the superior court within 40 days from the date of 0 v service of this notice. .\ a. A copy of the numbered agency file. . : ': l b. The transcript of proceedings before the agency, unless cassettes are authorized by • 'K' Appellate Rule 604(b)(1)(A) or court order. ; , %' 4',' c. All documentary and photographic exhibits no larger than 8 1 /2" X 14" which are not filed 04' in the agency case file and a list of the exhibits being transmitted. • ' , ; 1; d. A list of all exhibits retained by the agency. ' ' '4°' e. A copy of all depositions filed with the agency. ;'),?4"�� f. A Transmittal of Agency Record. Please use the enclosed form AP -312. Appellate Rule ,,,'-:° 604(b). " , ? 3. The appellant must arrange and pay for preparation of a transcript unless cassettes are ; ':?; r : authorized by Appellate Rule 604(b)(1)(A) or by court order. The appellant must also pay all ;:,':,`,, reasonable costs incurred by the agency to prepare the court's copy of the agency file, unless ,' _;,14: otherwise ordered by the court or agreed to by the parties. The agency may`require advance .!;; :, r payment of the costs. Appellate Rule 604(b)(1)(B)(iv). r '' CLERK OF COURT a y ,} 3/22/2011 By: BHarris ' ' -, c:= Date Deputy Clerk ;:R ut1�: j , :1. I certify that on 3/23/11 �;_',, a copy of this order was mailed or delivered to: :' Michael T Stehle -girl: 1 Alaska Oil and Gas Conservation Commission ! ;';, „ ; , Clerk: BHarris � y, i ALASKA OIL AND GAS CONSERVATION 4 ;k{�f;,, • COMMISSION 333 W. 7TH AVE. STE. 100 ,,' I. Ali -31ANg 9 - AGE AK 99501 ' + `i Notice For Prepa,ati ;.:rn Of RecuUUAchrun.Aopeal 1 :7 ': • s „; W, . f 41 . • IN THE SUPERIOR COURT FOR THE STATE OF ALASKA THIRD JUDICIAL DISTRICT AT ANCHORAGE VINCENT GODDARD, WILD PACIFIC SALMON, INC., and INLET FISH RECEIVEC PRODUCERS, INC., 1t? 2W+ Plaintiffs, Alaska Ctif & bas Cans. Commission vs. Ancnarbge ALASKA OIL AND GAS CONSERVATION COMMISSION, Case No. 3AN -11- CI Defendant. STATEMENT OF POINTS ON APPEAL Appellants submit the following points on appeal: 1. The Alaska Oil And Gas Conservation Commission ( "AOGCC ") erred in failing to require Cook Inlet Natural Gas Storage Alaska, LLC ( "CINGSA ") to amend its SIO application to give notice of its request to no longer include remediation of KU 13 -8 as a part of its application; 2. The AOGCC erred by engaging in ex -parte communications with CINGSA and failing to include those ex -parte communications with CINGSA as a cos part of the public record; ,T)1 r , 3. The AOGCC erred by not holding a public hearing on CINGSA's decision w oa� x " _ to not remediate KU 13 -8; a w STATEMENT OF POINTS Goddard et al. v. AOGCC Case No. 3AN -11- CI Page 1 of 3 • 4. The AOGCC erred in not requiring CINGSA to remediate KU 13 -8 as a condition of granting the SIO; 5. The AOGCC erred in not requiring CINGSA to inspect KU 13 -8 as a condition of granting the SIO; 6. The AOGCC erred in not requiring CINGSA to conduct base line testing as a condition of granting the SIO; 7. The AOGCC erred in not requiring CINGSA to conduct ongoing soil gas tests as a condition of granting the SIO; 8. The AOGCC erred in not requiring CINGSA to complete remediation prior to granting the SIO; 9. The AOGCC erred in not following its own governing regulations including but not necessarily limited to 20 AAC 25.252(h)(1 -2). DATED this ( `� day of March, 2011. STEHLE & JARVI, L.L.C. Attorneys 41:Ir Plaintiff By: V r c a _ tehle, • : : • 0605 .. N Q LL b N o ti N V .Jy C tD W Q O H 01 STATEMENT OF POINTS Goddard et al. v. AOGCC Case No. 3AN -11- CI Page 2 of 3 • CERTIFICATE OF SERVICE I hereby certify that on March j S" , 2011 a true and correct copy of the foregoing was served by electronically and by US mail on the following: Daniel T. Seamount, Jr. Chair Alaska Oil and Gas Conservation Commission 333 West 7 Ave., Ste. 100 Anchorage AK 99501 Office of the Attorney- General P.O. Box 110300 Juneau AK 99811 Certification Signature STATEMENT OF POINTS Goddard et al. v. AOGCC Case No. 3AN -11- CI Page 3 of 3 • IN THE SUPERIOR COURT FOR THE STATE OF ALASKA THIRD JUDICIAL DISTRICT AT ANCHORAGE VINCENT GODDARD, WILD PACIFIC SALMON, INC., and INLET FISH RECEIVED E PRODUCERS, INC., MAP 2, 1 • Plaintiffs, Alaska Oil 81 Gas Cons. Commission vs. Anchorage ALASKA OIL AND GAS CONSERVATION COMMISSION, Case No. 3AN -11- CI Defendant. NOTICE OF APPEAL COME NOW APPELLANTS, Vincent Goddard, Wild Pacific Salmon, Inc., and Inlet Fish Producers, Inc., collectively known as Inlet Entities, by and through counsel Stehle & Jarvi, LLC, and give notice of appealing to the Superior Court at Anchorage the attached decision of the Alaska Oil and Gas Conservation Commission Docket SIO -10- 05, Storage Injection Order No. 9 dated November 19, 2010, and the subsequent order on reconsideration, dated February 18, 2011. Also accompanying this notice of appeal is a statement of points on which appellants intend to rely on appeal. Appellants may be contacted at the following address: . m ° Stehle & Jarvi, L.L.C. u R - 1200 R Street, Suite B n'1"" Anchorage, AK 99501 a3 n Tel: (907) 677 -7877 N ti Fax: (907) 677 -7894 F DATED this t7 day of March, 2011. NOTICE OF APPEAL Goddard et al. v. AOGCC Case No. 3AN -11- CI Page 1 of 2 • STEHLE & JARVI, L.L.C. Attorneys Plaintiff Apr By ® 'c ael T. St e, CERTIFICATE OF SERVICE I hereby certify that on March $'fir , 2011 a true and correct copy of the foregoing was served by electronically and by US mail on the following: Daniel T. Seamount, Jr. Chair Alaska Oil and Gas Conservation Commission 333 West 7 Ave., Ste. 100 Anchorage AK 99501 Office of the Attorney - General P.O. Box 110300 Juneau AK 99811 Certification Signature NOTICE OF APPEAL Goddard et al. v. AOGCC Case No. 3AN -11- CI Page 2 of 2 • 0 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF Cook Inlet ) Docket SIO -10 -05 Natural Gas Storage Alaska, LLC for an ) Storage Injection Order No. 9 order authorizing underground natural gas ) storage in the Cannery Loop Unit, Kenai ) Cannery Loop Field Peninsula Borough, in conformance with ) Cannery Loop Unit 20 AAC 25.252 and 20 AAC 25.412. ) Sterling C Gas Storage Pool ) ) February 18, 2011 AMENDED ORDER ON RECONSIDERATION On November 19, 2010 the Commission entered Storage Injection Order 9 (SIO 9). On December 14, 2010, Vincent Goddard, Wild Pacific Salmon, Inc., and Inlet Fish Producers, Inc. (Goddard) requested reconsideration of SIO 9. On December 27, 2010, the Commission requested additional briefing from Cook Inlet Natural Gas Storage Alaska, LLC ( CINGSA) and Goddard. That briefing was tendered on January 10, 2011. Based upon a review of the submissions from both CINGSA and Goddard, the Commission confirms SIO 9 as entered on November 19, 2010. This order is a final decision. Any appeal must be taken within thirty (30) days. DONE at Anchorage, Alaska and dated February 18, 2011. Cz' Daniel Seam Jr., Chair Alaska T. Oil and Gas Conserv Commission 1. a '''''''\\\ } , y "- 1 �i r c ; Cathy P. , � NI: B erster, ommissioner t Alaska 011 and Gas Conservation Commission 4 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7th Avenue, Suite 100 Anchorage Alaska 99501 Re: THE APPLICATION OF Cook Inlet Natu- ) Docket SIO -10 -05 ral Gas Storage Alaska, LLC for an order ) Storage Injection Order No. 9 authorizing underground natural gas storage ) in the Cannery Loop Unit, Kenai Peninsula ) Cannery Loop Field Borough, in conformance with20 AAC ) Cannery Loop Unit 25.252 and 20 AAC 25.412. ) Sterling C Gas Storage Pool ) November 19, 2010 IT APPEARING THAT: 1. By application dated July 27, 2010, Cook Inlet Natural Gas Storage Alaska, LLC (CINGSA) requested a storage injection order from the Alaska Oil and Gas Conservation Commission (Commission or AOGCC) authorizing injection for underground storage of natural gas, in the proposed Sterling C Gas Storage Pool of the Cannery Loop Unit (CLU). 2. On August 20, 2010, pursuant to 20 AAC 25.540, the Commission published in the Alaska Journal of Commerce notice of opportunity for public hearing on October 19, 2010. Notice was also published in the Peninsula Clarion on August 29, 2010. 3. On September 13, 2010, Inlet Fish Producers, Inc. (IFP) requested a hearing and protested CINGSA's application for this CLU gas storage. 4. On September 20, 2010 and September 30, 2010, CINGSA electronically submitted to the Commission amendments to its July 27, 2010 application. 5. The Commission held a public hearing on October 19 and 20 2010 at 333 West 7 Avenue, Suite 100, Anchorage, Alaska 99501. Testimony was presented by CINGSA and IFP. CINGSA and IFP also submitted written exhibits. 6. The record was held open until October 27, 2010, to permit CINGSA and IFP to provide written additional comments for the hearing record. FINDINGS: 1. Operator Marathon Oil Company (Marathon) operates the CLU, which is located within the Kenai Field on the east side of the Cook Inlet, Kenai Peninsula Borough, Alaska. CINGSA anticipates acquiring the proposed Sterling C Pool reservoir from Marathon. As of October 19, 2010 the Alaska Department of Natural Resources had not issued a CLU gas storage Iease to CINGSA. • • Storage Injection Order 9 November 19, 2010 Page 2of12 2. Injection Strata The proposed Sterling C Gas Storage Pool is comprised of the Cl and C2 fluvial channel sandstones (in descending order). The proposed injection and storage interval corresponds to the CLU No. 8 well between the measured depths of 6690' and 6945' (see Figure 1, below). Gross interval thickness for the proposed storage reservoir averages about 200', and net sand thickness averages about 95'. The original structure at the top of the proposed storage reservoir is comprised of a structural, four -way dip closure that was charged by biogenic methane gas. The CLU is situated along the Aleutian megathrust tectonic plate boundary. The Cannery Loop and the nearby Kenai Gas Fields have produced regularly since 1988 and 1962, respectively, and have not been affected by seismic activity within the Cook Inlet Basin. The nearest known active fault is the West Boundary Fault in Cook Inlet, about 16 miles from the proposed CLU gas storage site. The Cannery Loop Fault is a north - dipping, east- west - trending fault located about 2 miles from proposed CLU surface facilities. Planned wells do not intersect the Cannery Loop Fault and no fault rupture hazard exists. The CLU earthquake ground motion hazard is similar to that of gas storage areas in southern California, western Washington and Oregon, where wells move with the surrounding soil and rock, and there is no differential displacement. There are no nearby slopes or free faces that would allow lateral spread by liquefaction; none was reported in the CLU area as a result of the 1964 earthquake. No CLU site hazards have been identified that could result from tectonic and local subsidence, tsunami, flooding, slope stability, or volcanic hazards, other than volcanic ash fall. 3. Pool Information The Cannery Loop Field contains four separate gas pools. They are, in ascending order: Tyonek D, Upper Tyonek, Beluga, and Sterling Undefined. The youngest, the Sterling Undefined Gas Pool, produces from the CI and C2 sandstones. These sandstones have been managed as a single reservoir through commingling of multiple perforated intervals within well CLU -06. To date, only the Sterling C interval within the Sterling Formation has had commercial gas development. The Sterling sandstones are Miocene- Pliocene aged. They are part of a sequence of sandstone, siltstone, mudstone, and coal deposited by large, meandering stream systems. Individual sandstone layers are typically 25' to 50' thick, fine upward, and are separated by coal, siltstone, and shale barriers. The thickest sandstone bodies of the Sterling consist of amalgamated sand sequences deposited in the central portions of meander belts, and can be in excess of 200' thick. The Sterling sandstones are classified as quartz -rich litharenites that contain little matrix and are slightly cemented with calcite, smectite, and kaolinite. These sandstones are fine- to coarse - grained, angular to subrounded, and moderately well sorted, with porosity ranging from 20% to 35 %, and extrapolated penneabilities ranging from 10 to 1000 millidarcies. The Sterling C sandstones display good reservoir properties and thick, continuous intervening shales (lateral and top seals). They exhibit pressure depletion characteristics with minimal water production (see Finding 13 and Figure 2, below). The proposed interval is an excellent candidate for gas storage. • • Storage Injection Order 9 November 19, 2010 Page 3 of 12 1640140 2040050 501331001400 501332053400 . , 4 2253 ft -i - 100 UNOCAL MARATHON KENAI UNIT 13-08 CANNERY LOOP UNIT 8 1774 FSL 1034 FWL 208 FSL 486 FEL TWP: 5 N - Range: 11 W - Sec. 8 TWP: 5 N - Range: 11 W - Sec. 7 --.-- 77antsten NOR R•47 0.472 Oto470x PO. I.7 .* krosIo COORION 40 ti.C1 it( X120064 COCX .." ***"' INA t Ur 2 OMR ORM 2W ti OM I X . 72 174071 nfl GM= 20 NOISS7 R77 ,,-.... 7. TVORS/ 0 22 22 047 7 R.7:44 OPOR0./4 OR TVO NRSR11.1 2104 It ORR NC ?.2 COSI XXX V X AR 24 22 UM 44 ( MIA MONA) t 7 ". =i7LJO 'LL'i.,7,k7.* 44 mr 4-a ufl 144 4 Atte 6700 -4608 -... ,.....-7. - and -- '*': NI 'MIMI' f gtig4t4 7.*Afa ' -- c.- , - • ' .,--,,, Vei...' ..-Ickl.", v .-. 4WD ',,■,,,i,t,-,z,',"7,, 7.172ra IIe 77 1P 70 - - ,Z04 ,14:4 ' ''''' •( ' '' - ' 1,710,.. rtl.% , - .k. _._,, Figure 1. Representative Well Logs for the Proposed Sterling C Gas Storage Pool' ' Figure 1 is for illustration purposes only. Refer to the well log measurements recorded in CLU No. 8 for the precise re- presentation of the proposed injection and gas storage interval. The horizontal grid lines in this figure represent increments of ten feet measured depth. The acronym TVD refers to true vertical depth, and the acronym TVDSS refers to true vertical depth subsea (true vertical depth below sea level). • Storage Injection Order 9 November 19, 2010 Page 4 of 12 4. Proposed Injection Wells CINGSA has optimized the number of proposed service wells and well completion designs to meet reservoir deliverability and surface facility design requirements. The program proposes five injection/withdrawal service wells, drilled from a single surface pad. The wells will be directionally drilled from a gravel pad to the west/southwest, to target the prospective gas storage reservoir along the crest of a 4-way dip, structural trap. No wells may be drilled absent a Permit to Drill issued by the Commission. 5. Operators /Surface Owners Notification CINGSA provided an affidavit affirming that all operators and surface owners within one - quarter mile of the storage injection area were notified of CINGSA's subject proposal. 6. Description of Operation CINGSA proposes to develop Sterling C gas storage in phases. Initially, the storage facility is designed to provide 1.1 billion cubic feet (BCF) of working gas deliverable in approximately ninety days under maximum withdrawal conditions. The required base -gas volume is estimated to be 7 BCF, which will allow the field to operate efficiently to a minimum surface flowing pressure of about 400 psi. Maximum total gas inventory wilI be Iimited to 18 BCF initially (11 BCF working gas + 7 BCF base gas), or 68% of the initial gas in place. The storage facility's maximum injection and withdrawal rates will be limited to 150 million cubic feet per day (MMCFD). Simulation indicates that the storage facility should operate at surface pressures ranging from approximately 400 psi to 1450 psi. The facility is designed such that additional storage capacity can be accommodated. 7. Well Spacing To simplify well geometry while providing, for maximum drawdown, it may be necessary to space the wells as close as 200' apart. Well completion design will stagger perforations stratigraphically among wells in close proximity to enable each well to drain effectively the storage pore volume within its drainage polygon. Well spacing exceptions will be requested as part of CINGSA's applications for Permits to Drill. 8. Well Logs All logs from existing wells within the CLU were previously submitted to the AOGCC by the field operator. CINGSA intends to acquire logging - while - drilling (LWD) logs in the new injection/withdrawal wells. The minimum logging program will consist of continuous mud logging, ganuna -ray for surface and intermediate holes, and triple -combo (gamma -ray, resistivity, neutron, and density) in the production hole. Cement bond logs will be run on the intermediate and production casings. Once acquired, this data will be filed per AOGCC regulations. 9. Proposed Mechanical Integrity and Well Design All casing strings in new injection /withdrawal wells will be cemented in accordance with AOGCC regulations. An application will be made later with a Permit to Drill for annular disposal of drilling wastes. This will necessitate leaving intermediate casing cement below the surface casing shoe in the subject well. A liner will be run and cemented across the target gas • Storage Injection Order 9 November 19, 2010 Page 5of12 storage interval and into the intermediate casing. Selective liner perforation will be based on petrophysical analysis of logs to be acquired by LWD across the prospective interval prior to running the production liner. Production liners will include a liner top packer and tie -back seal bore on production tubing to provide isolation /integrity of the reservoir from the annulus. The liner and tubing will utilize "gas tight', metal -on -metal premium connections. A hydraulic - actuated wireline retrievable surface controlled subsurface safety valve (SSSV) will be installed, at an estimated depth of 150'. Proposed storage injection/withdrawal wells will be tested for mechanical integrity during completion per 20 AAC 25.412. CINGSA will continue monitoring tubing/casing annulus pressures. Abnormal annular pressure in any well will be followed by actions to isolate the well from reservoir pressure. CINGSA will investigate any abnormal pressure occurrence and perform remedial actions as required. Following corrective action, CINGSA will conduct a mechanical integrity test (MIT), witnessed by a commission representative, to re- confirm well mechanical integrity. 10. Fluid Type and Source CINGSA intends to inject dry natural gas with a typical composition of about 98% methane and specific gravity ranging from 0.56 to 0.58. It is expected that injection gas will generally originate in the greater Cook Inlet region and be transported via the KNPL pipeline. 11. Fluid Compatibility CINGSA provided analysis of gas from various points throughout the Cook Inlet gas pipeline system. Only compatible gas will be injected into the Sterling C Zone. 12. Injection Rates and Pressures, Fracture Information CINGSA plans to operate the storage facility between a maximum and minimum field inventory of 18 BCF and 7 BCF, respectively. This equates to a working volume of 11 BCF. At the maximum storage volume of 18 BCF, material balance (P /Z v. cumulative gas production, Figure 2) indicates an average reservoir pressure of approximate 1521 psi. Modeling indicates that the storage facility will operate at surface pressures ranging from approximately 400 psi to 1450 psi. The injection profile used in the model initiated fill -up at a total injection rate of 150 MMCFD, stepping down to a final rate of 75 MMCFD (for all five wells). The reservoir can thus be filled within a time period of approximately 100 days. The model showed the final injection pressure for individual wells to vary between 1430 psi and 1460 psi. This corresponds to a maximum pressure during injection at the reservoir datum (4966' TVD) of 1610 psi. Even though modeling indicates that a maximum injection pressure of approximately 1450 psi should be sufficient to fill the storage reservoir, actual well performance (due to completion design and efficiency, reservoir heterogeneities, etc.) will likely dictate a higher injection pressure. Leak off tests were performed in wells CLU -8, CLU -9, and CLU -10 below the 9- 5/8" intermediate casing shoes. In these wells, intermediate casing was set just above the proposed Sterling C storage interval. Following cementing operations, approximately 20 feet of new foiniation was drilled below the casing shoe and leak off tests performed. Average fracture gradient was 0.684 psi /ft for leak off at the top of the Sterling C interval. This fracture gradient is significantly higher than the proposed Sterling C Gas Pool discovery pressure gradient of • • Storage Injection Order 9 November 19, 2010 Page 6 of 12 0.444 psi /ft. The original discovery pool gradient was obtained from the initial reservoir pressure of 2206 psi (at a reservoir datum of 4966' TVD), measured in well CLU -6. CINGSA intends to operate the Sterling C storage facility below the initial reservoir pressure of 2206 psi. The initial phase of development calls for a maximum storage volume of 18 BCF (as compared to the initial gas in place of 26.5 BCF), which, based upon material balance, equates to an average reservoir pressure of approximately 1520 psi. C1NGSA intends to limit injection pressure so that the injection pressure gradient does not exceed 0.5 psi /ft at the reservoir datum of 4966' TVD. This equates to a maximum injection pressure of 2200 psi at surface and 2483 psi at 4966' TVD. 13. Underground Sources of Drinking Water The proposed gas injection reservoir depth is approximately 4900' TVD to 5100' TVD. Aquifer exemption is addressed in a separate commission order (see. Aquifer Exemption Order No. 13). 'CANNERY LOOP UNIT Sterling C Pool 3000 - -- .._. -.... _------ _- ___._.._ ., ._ __ -- _..._ -. ■ 2500 • • • Gt.l1#fi 0 2000 • { N 1500 • 1000 t t i ` 500 € 3 I 1 0i T I 5,000 10,000 15,000 20,000 25,000 30,000 Cumulative Produced Volume, MMscf Figure 2: P/Z plot of Cannery Loop Sterling C Reservoirs 14. Mechanical Condition of Pool Wells Three wells (CLU -06, CLU -08 and CLU -12) within the field require remedial work to isolate the Sterling C storage interval. Remedial procedures will be jointly developed between • • Storage Injection Order 9 November 19, 2010 Page 7 of 12 CINGSA and Marathon. All necessary well remediation will be conducted in compliance with Commission regulations before injection will commence. In accordance with existing Commission regulations, KU 13 -8 (1964, Unocal exploratory well) was plugged and abandoned with a cement plug set from 1000' to 1270'. The 8 -5/8" casing shoe (in 12 '/" hole) is set at 1159' and cemented in place. 7 -5/8" hole was drilled to 5506'. The 7 -5/8" well bore was not cased. A sundry reports that this well was left with a 4 foot standpipe and placard marking the abandoned location. CINGSA's investigations have shown that the pipe / marker have since been cut off and plugged, and the well casing stub is now buried below grade. Through recent land and magnetometer surveying efforts, CINGSA has located what appears to be the buried casing. Drilling and completion activity on CLU -12 (2006, Marathon development well) was suspended when the Beluga objectives were apparently found to be non - viable. The deeper portion of the well was abandoned with numerous cement plugs, leaving the shallower portion of the well as a sidetrack candidate. The 9 -5/8" casing shoe (in 12 '/" hole) is set at 7259' and cemented in place. 8 -1/2" hole was drilled to 10415'. The 8 -1/2" hole section was not cased. The lower portion of the Sterling C interval and the upper Beluga are not isolated. Remedial procedures which comply with Commission regulations will be jointly developed between CINGSA and Marathon and approvals gained to allow for re -entry to drill out plug #3 and cement from the top of plug #2 into the 9 -5/8" casing. This work will insure isolation of the Sterling C interval in this well for gas storage integrity and will be completed as a prerequisite to gas injection. 15. Monitoring Individual storage injection /withdrawal wells are designed to operate at a maximum rate of approximately 50 MMCFD. To manage risk, CINGSA will install a surface controlled subsurface safety valve (SSSV) in each well. CINGSA will also install a Supervisory Control and Data Acquisition (SCADA) system for the well pad. The SCADA system will include the ability to monitor the pressure, temperature, and gas flow rate at each injection/withdrawal well from a central control room located in the compressor station. Each of the 6" well lateral flow lines and the 16" gathering header will include actuator- equipped isolation valves that will enable each lateral and the gathering header to be shut -in from the well pad gate as well as from the central control room. CINGSA will monitor daily injection and withdrawal rates and pressures to validate mechanical integrity through material balance monitoring. The Sterling C gas pool has followed a classic P/Z depletion drive curve (Figure 1), indicating no subsurface communication. Forward monitoring of pressures and volumes will provide an additional check on integrity, where data from primary depletion can be compared with data from subsequent injection /withdrawal cycles. 16. Public Comment IFP submitted written objection to CINGSA's Cannery Loop gas storage proposal, presented oral testimony at a Commission public meeting on September 1, 2010 and at a Commission hearing on October 19 and 20, 2010 and submitted written exhibits during the hearing on October 19 and 20, 2010 and on October 27, 2010. IFP offered testimony and exhibits through two witnesses, Vincent Goddard and Dr. John O. Robertson. Mr. Goddard runs a fish • Storage Injection Order 9 November 19, 2010 Page 1 of 12 processing business. Dr. Robertson was qualified to testify as a petroleum engineer. Mr. Goddard's testimony included technical information in geology, geophysics and petroleum engineering. Given Mr. Goddard's lack of expertise in any of these technical areas, the Commission finds his testimony on those matters lacks credibility. Dr. Robertson was qualified to testify as an expert in the area of petroleum engineering. However, the bulk of Dr. Robertson's testimony was offered on the subject of geology and geophysics, areas in which he was not qualified as an expert. As a. result, the Commission believes his testimony on those topics lacks credibility. To the extent Dr. Robertson's testimony was in direct conflict with the testimony of experts offered by CINGSA, the Commission finds the testimony of the experts offered by CINGSA to be more credible than that offered by Dr. Robertson. CONCLUSIONS: Based upon the evidence and testimony presented, the Commission concludes as follows: 1. The proposed Sterling C Gas Pool storage project meets the requirements of 20 AAC 25.252. However, prior to submission of any application for a Permit to Drill, CINGSA must obtain a gas storage lease and assume operatorship of the proposed gas injection and storage reservoirs within the CLU. 2. There are no compatibility concerns between injected gas and native gas in the proposed Sterling C Gas Storage Pool. 3. Construction records, casing and cementing records, cement bond logs and witnessed mechanical integrity tests will demonstrate the mechanical integrity of proposed injection storage wells and demonstrate that fluids will not move behind casing beyond the gas storage zone. 4. Prior to commencement of any injection activities, CINGSA will demonstrate to the satisfaction of the Commission that all existing pool wells have been appropriately remediated. S. The proposed injection and storage operations will be conducted in permeable strata, which can reasonably be expected to accept injected fluids at pressures less than the fracture pressure of the confining strata. 6. The injection of natural gas into the proposed Sterling C Gas Storage Pool will not propagate fractures through the confining zones. 7. Aquifer Exemption Order No. 13 separately addresses exemption of aquifers within the project area. 8. Surveillance of operating parameters for storage and offset wells will provide continued assurance that stored gas remains confined to the proposed Sterling C Gas Storage Pool. 9. Limiting the reservoir pressure to 1700 psi for natural gas storage in the proposed Sterling C Gas Storage Pool will insure that storage reservoir pressure remains below original reservoir pressure. 10. The proposed injection of natural gas into the proposed Sterling C Gas Storage Pool for the purpose of storage will not cause waste, jeopardize correlative rights, endanger freshwater, or impair ultimate recovery. • • Storage Injection Order 9 November 19, 2010 Page 9 of 12 NOW THEREFORE IT IS ORDERED that the following rules, in addition to statewide requirements under 20 AAC 25, apply to the underground storage of hydrocarbons by injection operations in the proposed Sterling C Gas Storage Pool, in the affected area described below: Seward Meridian Township 05N, Range 11W SW1 /4 -SW1 /4 of Section 4 W 1 /2- SEI /4 -SW 1/4 of Section 4 S3 /4- NW1 /4 -SW1 /4 of Section 4 S1 /2 -SE1/4 of Section 5 S3/4- NEI /4 -SE1 /4 of Section 5 S1 /2- NW1 /4 -SE1 /4 of Section 5 S1 /2- NE1 /4- NW1 /4. -SE1/4 of Section 5 E1 /2- SE /14 -SW1 /4 of Section 5 SE1/4- NE /14 -SW1 /4 of Section 5 E1/2- E1/2 -SE1 /4 of Section 7 El /2 of Section 8 SW1 /4 of Section 8 S 1 /2 -N W 1 /4 of Section 8 E 112 -NE U4 -N W 1 /4 of Section 8 SW1 /4- NEI /4 -NWI /4 of Section 8 SE 1 /4 -NW 1 /4 -NW 1/4 of Section 8 W3 /4 -NW 1/4 of Section 9 N/2- NWI /4 -SW1 /4 of Section 9 SW 1 /4 -NWI /4 -S W 1 /4 of Section 9 NW 1 /4 -S W 1 /4 -S W 1 /4 of Section 9 N314 -W l /2 -NEI /4 of Section 17 N3 /4- WI /2 -E1/2 -NEI /4 of Section 17 N3 /4- E1 /2 -NW1 /4 of Section 17 NW1 /4 -NW1 /4 of Section 17 NEI /4- SW1 /4 -NW 1/4 of Section 17 N 112 -NW U4 -SW 1 /4 -NW 1 /4 of Section 17 NE1 /4- NE1 /4 -NE1 /4 of Section 18 NE 1 /4 -SE 1 /4 -NE 114 -NE 1 /4 of Section 18 RULE 1: STORAGE INJECTION The Commission approves injection for storage of natural gas in the CLU within the interval identified in Rule 2 (below), which constitutes a gas storage pool named the Sterling C Gas Storage Pool. RULE 2: POOL DEFINITION The Sterling C Gas Storage Pool consists of the interval within the Affected Area that is common to, and correlating with, the measured depths from 6690' to 6945' in well CLU No. 8. • • Storage Injection Order 9 November 19, 2010 Page 10 of 12 RULE 3: GAS DETECTION CINGSA shall install, operate and maintain a gas detection and alarm system in all buildings located within 50 feet of the surface location of well KU 13 -08 unless prohibited from , p doing so by either the owner or the lessee of the land upon which KU13 -08 is Iocated. RULE 4: WELL REMEDIATION CINGSA shall demonstrate that any wells in the pool meet all Commission requirements for hydrocarbon production wells, or that the wells have been suspended or abandoned in accordance with applicable requirements. RULE 5: DEMONSTRATION OF MECHANICAL INTEGRITY The mechanical integrity of proposed storage injection wells and existing pool wells must be demonstrated before injection begins, and before returning any well to service following a workover affecting mechanical integrity. A Commission - witnessed mechanical integrity test must be performed after injection is commenced for the first time in any well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed on each storage injection well at least once every four years thereafter. The Commission shall be notified at least 24 hours in advance of a test. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure of 1,500 psi or 0.25 psi/ft multiplied by the vertical depth of the packer, whichever is greater. Stabilizing pressure that does not change more than 10 percent during a 30- minute period is required for a valid test. Results of all mechanical integrity tests must be provided to the Commission. RULE 6: WELL INTEGRITY FAILURE AND CONFINEMENT The operator shall maintain a continuous data acquisition system to record flow rates and pressures on all active wells in the field. Field personnel must perform daily visual inspections and maintenance of all active wells and production equipment. Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by injection rates, operating pressure observations, tests, surveys, logs, or other evidence, the operator shall notify the Commission by the next business day and submit a plan of corrective action on a Form 10 -403 for Commission approval. The operator shall immediately shut in the well if continued operation would be unsafe or would threaten contamination of freshwater, or if so directed by the Commission. RULE 7: MAXIMUM RESERVOIR PRESSURE The reservoir pressure for this project shall be limited to a maximum of 1700 psi. RULE 8: PERFORMANCE REPORTING The Operator shall report disposition of production and injection as required by 20 AAC 25.228, 20 AAC 25.230, and 20 AAC 25,235. An annual report evaluating the performance of the storage injection operation must be provided to the Commission no later than March 15. The report shall include material balance calculations of the gas production and injection volumes and a summary of well performance data to provide assurance of continued reservoir confinement of the gas storage volumes. Additional data collection and analysis will be based on a review of the operating . • • Storage Injection Order 9 November 19, 2010 Page 11 of 12 perfonnance and could include temperature surveys, pressure surveys, and production logs. RULE 9: OTHER CONDITIONS a. It is a condition of this authorization that the operator complies with all applicable Commission regulations. b. The Commission may suspend, revoke, or modify this authorization if injected fluids fail to be confined within the designated injection strata, or for any other violation of the law. c. As provided in 20 AAC 25.252(j), if storage operations are not begun within 24 months after the date of this Order, the injection approval shall expire unless an application for extension has been approved by the Commission. RULE 10: ADMINISTRATIVE ACTIONS Unless notice and public hearing are otherwise required, the Commission may administratively waive or amend any rule stated above as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in fluid movement outside of the authorized injection zone. DONE at Anchorage, Alaska and dated November 19, 2010. OIL 0/ . ey t4. �� Daniel T, Seamou t, Jr., Chair ii .lam , y A laska Oil and Gas Conservation Commission ,t . , --- -+ _ (on/ 1-' ' .71 11 , .-- f .. . . - 204 4,7 ( Cathy P. oerster, Commissioner Alaska it and Gas Conservation Commission • • Storage Injection Order 9 November 19.201 0 Page 12 of 12 RECONSIDERATION AND APPEAL NOTICE As provided in AS 31.05.080(4 within 20 days after written notice of the entry of this order or derision or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration ol'the matter determined by it. If the notice was mailed. then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be ernmeous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. lithe Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appeared to superior court. The appeal MUST be filed within 33 days alter the date on which the Commission mails, OR 30 days if the Commission otherwise distributes. the order or decision denying reconsideration, UNLESS the denial is by inaction. in which case the ap- peal MUST be filed within 40 days alter the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Ratter, the order or decision on reconside- ration will he the FINAL order or decision of the Commission. and it may be appealed to superior court, That appeal MUST be filed Within 33 days after the date on which the Conunission mails, OR 30 days if the Commission otherwise distributes. the order or decision on reconsideration. As provided in AS 31.05.080(h). " [tlhe questions revietted on appeal are limited to the questions presented to the Commission by the application for re- consideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included. unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall 00 a weekend or state holiday.