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211-071
THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY November 21, 2019 Mr. David Pascal Vice President, Operations Cook Inlet Energy 188 West Northern Lights, Suite 510 Anchorage, AK 99503 Re: Location Clearance Three Mile Creek #1 (PTD #2041830) Three Mile Creek #2 (PTD #2051430) Three Mile Creek #3 (PTD #2110710) Dear Mr. Pascal: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .aogcc.alaska.gov On October 24h 2019, the Alaska Oil and Gas Conservation Commission (AOGCC) conducted a final location inspection of the drill sites of Three Mile Creek wells #1, #2, and #3. A copy of the inspector's report is attached to this letter. The drill sites were found to be in compliance with onshore location clearance requirements as stated in 20 AAC 25.170. The AOGCC requires no further work on the subject wells or locations at this time. However, Cook Inlet Energy remains liable if any problems were to occur with these wells in the future. Sincerely, f4gsie L. Chmielowski Commissioner MEMORANDUM TO: FROM Jim Regg P. I. Supervisor State of Alaska Alaska Oil and Gas Conservation Commission DATE: 10/25/19 Lou Laubenstein SUBJECT: Final Location Inspection Petroleum Inspector Three Mile Creek 1, 2 and 3 Cook Inlet Energy PTD 2041830, 2051430, 2110710 10/24/19: 1 traveled to Beluga for 3 final location inspections on the Three Mile Creek wells. Alaska Department of Natural Resources representative Mark Henspeter was also on location for these location inspections and used a drone to capture aerial images of each wellsite. There were no Cook Inlet Energy representatives on location at the time of these inspections. Three Mile Creek #1 (PTD 2041830) The location was clear of any signs of oil field equipment or debris, no visible leakage or spills could be seen on or off the pad. A large mound of dirt in the middle of the pad marks where the well was. Three Mile Creek #2 (PTD 2051430) The location was clear of any signs of oil field equipment or debris, no visible leakage or spills could be seen on or off the pad. A large mound of dirt in the middle of the pad marks where the well was. Three Mile Creek #3 (PTD 2110710) The location was clear of any signs of oil field equipment or debris, no visible leakage or spills could be seen on or off the pad. A large mound of dirt in the middle of the pad marks where the well was. Attachments: Photos (6) 11W 'y1 F a -r#'. � ., >•arey>s'9U+ -�. Y "yy i. ` ... _ ,..fin. Mr V t N T {�.„,✓�" i y +.�. � Ft., I ' ..rf 9 i y :i A D. � 't A t� �� y i e.� i �'j ��^ , ..� r 'Y '� _ � ,.' - ♦'i `p I tj. �s t L .w 1 W,14 no. � k — a _ r s a t` _ dr tj. �s t L .w 1 Regg, James B (CED) �) U Z I I ni D From: Henspeter, Mark (DNR) n Sent: Tuesday, November 12, 2019 4:54 PM �tt�I To: Regg, James B (CED) Cc: Laubenstein, Lou (CED) Subject: Threemile Creek DR&R aerial images Attachments: TMC3_reduced.jpg; TMC2_reduced jpg; TMC1_reduced jpg Hi Jim, Attached are three images from the Threemile Creek pads numbers 1, 2, and 3. These images were captured on October 24, 2019 as part of the Division of Oil & Gas Plan of Ops closure inspection. The final report for the inspection should be available on Friday. These attached images are a reduced file size so they can be inserted into a report for distribution. am sending over the full -resolution images (as well as two oblique images) through our file transfer application. Please let me know if you need any other information. Hope that helps, -Mark Henspeter -S Natural Resource Specialist Division of Oil & Gas Permitting Section Phone: 907.269.8812 ma rk. hensoeter@alaska.eov MEMORANDUM FROM Jim Regg "e�� 1(�j��/� P. I. Supervisor Lou Laubenstein Petroleum Inspector State of Alaska Alaska Oil and Gas Conservation Commission DATE: 10/25/19 SUBJECT: Final Location Inspection Three Mile Creek 1, 2 and 3 Cook Inlet Energy PTD 2041830, 2051430, 2110710 10/24/19: 1 traveled to Beluga for 3 final location inspections on the Three Mile Creek wells. Alaska Department of Natural Resources representative Mark Henspeter was also on location for these location inspections and used a drone to capture aerial images of each wellsite. There were no Cook Inlet Energy representatives on location at the time of these inspections. Three Mile Creek #1 (PTD 2041830) The location was clear of any signs of oil field equipment or debris, no visible leakage or spills could be seen on or off the pad. A large mound of dirt in the middle of the pad marks where the well was. Three Mile Creek #2 (PTD 2051430) The location was clear of any signs of oil field equipment or debris, no visible leakage or spills could be seen on or off the pad. A large mound of dirt in the middle of the pad marks where the well was. Three Mile Creek #3 (PTD 2110710) 111� The location was clear of any signs of oil field equipment or debris, no visible leakage or spills could be seen on or off the pad. A large mound of dirt in the middle of the pad marks where the well was. Attachments: Photos (6) 2019-1024_Location_Three _Mile _Creek_ll. docx Page 1 of 4 a a; r rk� :r_ r TM Io c 4f STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LQG 1a. Well Status: Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑✓ ' Suspended❑ 20AAC 25.105 20MC 25.110 GINJ ❑ WINJ ❑ WAG[-] WDSPL ❑ No. of Completions: 1b. Well Class: Development Exploratory ❑ Service ❑ Stratigraphic Test ❑ 2. Operator Name: Cook Inlet Energy, LLC (a Glacier Oil & Gas Corp/Successor in interest to Forest Oil Corp) 6. Date Comp., Susp., or Aband.: j 5/18/2019 14. Permit to Drill Number/ Sundry: 211-071 3. Address: 188 W. Northern Lights Blvd, Suite 510, Anchorage, AK, 99503 7. ate pudded: 9/29/2011 15. API Number: 50-283-20156-00-00 4a. Location of Well (Governmental Section): Surface: 367' FEL, 1244' FSL, Sec. 34, T13N, R11 W SM • Top of Productive Interval: 540' FEL, 1374' FSL, Sec. 34, T13N, R11 W SM Total Depth: 1981' FEL, 1925' FSL, Sec. 34, T13N, R11 W SM 8. Date TD Reached: 10/20/2011 16. Well Name and Number: Three Mile Creek #3 9. Ref Elevations: KB: 304' ' GL: 288' • BF: 17. Field / Pool(s): Three Mile Creek - Beluga Gas Pool 10. Plug Back Depth MD/TVD: • 5040' MD / 4665' TVD • 18. Property Designation: ADL 388233 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 285835 • y- 2621670 • Zone- 4 TPI: x- 285662 y- 2621800 Zone- 4 Total Depth: x- 284220 y- 2622351 Zone- 4 11. Total Depth MD/TVD: • 5159' MD / 4771' TVD 19. DNR Approval Number: N/A 12. SSSV Depth MD/TVD: N/A 20. Thickness of Permafrost MD/TVD: N/A 5. Directional or Inclination Survey: Yes LJ (attached) No ✓ Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: N/A (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary 23. CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 13-3/8" 72# K-55 15' 80' 15' 80' Driven N/A N/A 9-5/8" 36# J-55 Surface 800' Surface 800' 12 1/4" 12ppg, Type 1 None 5-1/2" 15.5# J-55 Surface 5116' Surface 5116' 7 7/8" 12/14.8 ppg, Class G None 24. Open to production or injection? Yes ❑ No Q If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd): ( {� �D//-j�_$_ S � iIFIED 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 2-7/8" 3577 See attached ACID, FRACTURE, CEMENT SQUEEZE, ETC. W Was hydraulic fracturing used during completion? Yes LJ No Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: N/A Method of Operation (Flowing, gas lift, etc.): Date of Test: Hours Tested: _TF roduction for Test Period Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Flow Tubing Press. Casinq Press: Calculated 24 -Hour Rate Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (corr): Form 10-407 Revised 5/2017 t4 B Z 9,11 3C0%INUED ON PAGE 2 RBDMS}�W JUN 2 0 2012 b it ORIGINIAL only 28. CORE DATA Conventional Corals): Yes ❑ No ❑ Sidewall Cores: Yes ❑ No ❑ If Yes, list formations and intervals cored (MD/1VD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No ❑ If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval information, including reports, per 20 AAC 25.071. Formation at total depth: 31. List of Attachments: Wellbore schematic, Daily summaries, photos of abandonment. Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Stephen Ratcliff Contact Name: Stephen Ratcliff Authorized Title: VP of Drilling Contact Email: sratcliff@glacieroil.com Authorized Contact Phone: 907-433-3808 Signature: —. Date: t9 INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water-Altemating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil & Gas / Division of Mining Land and Water: Plan of Operations (LO/Region YY -123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in, this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 5/2017 Submit ORIGINAL Only GLACIER June 17", 2019 Jessie Chmielowski, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7' Ave., Suite 100 Anchorage, Alaska 99501 Re: Well Completion Cook Inlet Energy, LLC: Three Mile Creek #3 Permit to Drill NO: 211-071 API No: 50-283-20156-00-00 Dear Commissioner, Cook Inlet Energy (CIE) hereby submits a Well Completion Report for the abandonment of Three Mile Creek #3. The work performed was covered under Approved Sundry 318-479. CIE requests the official status of Three Mile Creek #3 be changed to P&A. If you have any questions, please contact me at (907) 433-3808. Sincerely, Stephen Ratcliff Vice President — Drilling Cook Inlet Energy, LLC (a Glacier Oil & Gas Corp. owned company) 188 W. Northern Lights Blvd, Suite 510 Anchorage, AK 99503 10-407 Three Mile Creek #3 Daily Operations Summary API: 50-283-20156-00-00 PTD#:211-071 Date Activity 07 May 2019 R/U hot oil truck and fluid pack OA, IA and tubing. Test tubing to 1500 psi for 30 mins — good. Test IA to 1500 psi — good. R/D hot oil truck, secure well. 08 May 2019 No operations. 09 May 2019 RU hot oil truck. Test tubing to 1500 psi for 30 minutes and chart same — good. Test IA to 1500 psi for 30 minutes and chart same — good. Both tests witnessed by AOGCC Representative, Guy Cook. 10 May 2019 RU Eline. Test lubricator to 1000 psi. RIH with 1.375" tubing punch and punch tubing at 1655' ELM - all shots fired. Pressure change and circulation confirmed. RD Eline. RU cement equipment and take on water. 11 May 2019 Finish RU cementers. Pressure test lines to 2500 psi. Pump 3.5 bbls exvl� water spacer (confirm circulation between tubing and IA), followed by 52 bbls (170sx/1.71cuft/sx) of 13.5ppg Class G cement. Good cement returns to surface at 47 bbls away. RD cement equipment. 12 May 2019 Clear area and prep for excavation. 13 May 2019 Excavate around wellhead. 14 May 2019 Remove tree and wellhead. 15 May 2019 Top off tubing, IA, and OA 16 May 2019 Cement job and P&A Well ID plate witnessed and approved by AOGCC Rep, Lou Laubenstein. Approval given to back fill. 17 May 2019 P&A Well ID plate welded on well. Backfill with dirt. 18 May 2019 Mound dirt over well. P&A Complete. 2IPa c Three Mile Creek Unit No. 3 Finns P&A Well Conflguration As of 05118/1019 .-Aurora Gas, LLC Three Atile Creek 43 PTD#: 211-071 1",3.72= 51acraral ANN: W283-201.46-00-00 Conductor dtirea to 80' GL RI►'B -14ft " � 9-5 E' 36t Satiate Casing set at 886' Cesuu 8:12.0 ppb Iept 1 - .. .. Auelerated Dolt 12-174" Hole to 901' 2-78" a 5-!i" aandus dispBred with 9.6x uli6ited brine 2 74 f su 8741 EVE 3-sM Tabing Tbg paucb a 1655' VT M Circulate aide 170 x•52 bbls Class G cement (135- pp8;'1.71 rfsk field) Hvdraalt Packet a 1663' PBTD G 5,040' (4665' TS -D) ) " 5 !i" 15 .'* 2-55 Casmg to 5149' Am) Drilled 8-L2" Holm to 5,159' 11D (41771` Tl'D) Clemed out to 4100'm Sept. 2012 R' CI 3 P at Sbdme. Slmert XD a -1733' (Closed) 1704-24' PS Plvg a 1743' 1773-78' H,draalr Set Packer a WO' Weatherford Erpaaston )omt OR travel, 2112-20 dr 2126-2132 top a -2082 213x2203' 2386-24116' Ssdmg Slarve Im tOt, `BIT MD (closed) Hr41raabc Padw w -•24841' 2512-32' 7616-7e' SW=g Stw*XD6-2698' (Closed) Sbdm3 Sleesw 1CD a. -307F (Closed) Hydranbc Pear w 3132' X-Myj,1 2313" m Q 3,239' 3362272' 3t 3410-20' Frac with 88,000 m of sand Fre door R 413)1',15" ball seat (Closed) 3laclaatCal Pack" fit, 3534' w On. OHT"I a 3532' wi 231 profile S 3926-46'& 3966-86' Frac loth nipple WIL Entry Guide. 90,000 Ib of sand ' n EOT Q4m, • 86dt Cat Idubaaic9 Puar �d 4109' w) 2313 Pn81e S adpplm at 4384-9d' 4110', unit burst dist 4120- 4981-92, , PBTD G 5,040' (4665' TS -D) ) " 5 !i" 15 .'* 2-55 Casmg to 5149' Am) Drilled 8-L2" Holm to 5,159' 11D (41771` Tl'D) Clemed out to 4100'm Sept. 2012 R' CI 3 P at Three Mile Creek #3 — PTD 211-071 — Cement to Surface and Casing Cut — 5ft below original ground level. 1 .A 4 • t 4I VOR > 9 Nit MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: 5/21/19 " P. I. Supervisor FROM: Lou Laubenstein SUBJECT: Surface Abandonment Petroleum Inspector Three Mile Creek #3 Cook Inlet Energy PTD 211-071; Sundry 318-479 5/16/2019: 1 traveled to Beluga to inspect the surface abandonment of Three Mile Creek #3. 1 arrived on location and met up with Wes Jeardoe (Cook Inlet Energy) as the Company Man in charge of work being done. The casing was cut below the required 3 feet from ground level with cement to surface. The marker plate had the correct information on it and was in order. There was no sign of oil spillage or seepage in the area and the excavated hole around the casing was clean. Attachments: Photos (3) 2019-0516_Surface —Abandon _ TMC -3 11.docx Page 1 of 3 I MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission ' TO: Jim Regg 7�< S `�I " 5 11 � DATE: Tuesday, May 14, 2019 SUBJECT: Mechanical Integrity Tests P.1. Supervisor COOK INLET ENERGY, LLC 3 FROM: Guy Cook THREE MILE CK 3 Petroleum Inspector Ste: Inspector Reviewed By: P.I. Suprv� NON -CONFIDENTIAL Comm Well Name THREE MILE CK3 API Well Number 50-283-20156-00-00 Inspector Name: Guy Cook Permit Number: 211-071-0 Inspection Date: 5/9/2019 Insp Num: milGDC190510110707 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 3 Tvpelnj N'TVD 1644 Tubing o n6o neo- neo T PTD '-110710 Type Test�tpsi 1500 IA� o 65 -� 65 6s _ _ BBL Pumped: 0-2 BBL Returned: 0.2 OA 1 70 - 70- `70 - 70 — - _- Interval OTHER _ PIF P Notes: MIT -I for P&A. Sundry 318-479. Job was completed with calibrated gauges and a pump truck from Pollard. Tuesday, May 14, 2019 Page I of 1 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Tuesday, May 14, 2019 TO: Jim Regg P.I. Supervisor 1e 6-11gl/q 71 SUBJECT: Mechanical Integrity Tests COOK INLET ENERGY, LLC 3 FROM: Guy Cook THREE MILE CK 3 Petroleum Inspector Well Name THREE MILE CK 3 IInsp Num: mitGDC190510111114 Rel Insp Num: Ste: Inspector Reviewed By: P.I. Supry NON -CONFIDENTIAL Comm API Well Number 50-283-20156-00-00 Inspector Name: Guy Cook Permit Number: 211-071-0 Inspection Date: 5/9/2019 Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min - - - Well 3 Typelnj� N -TVD 644 Tubings o 0 0 0 ._ _. �_-_ PTD 2110710 Type Testy SPT Test psi 1500 IA o 1720 1720 1720 T BBL Pumped:3 - IBBL Returned: 0? OA4o 14o - ao L- 140 —� Interval OTHER P/F P Notes: MIT -IA for P&A. Sundry 318479. Job was completed with calibrated gauges and a pump truck from Pollard. i Tuesday, May 14, 2019 Page I of 1 • STATE OF ALASKAEIVED AtikAOIL AND GAS CONSERVATION COIVMlltION REPORT OF SUNDRY WELL OPERATIONS JAN 2 3 2018 1.Operations Abandon LI Plug Perforations LI Fracture Stimulate Li Pull Tubing Li r (own Performed: Suspend 0 Perforate 0 Other Stimulate 0 Aker Casing 0 Change Approved Program El Plug for Redrif 0 PerforateNew Pool 0 Repair Wen 0 Re-enter Susp Well 0 Temporary Plug 0 2.Operator Aurora Gas,LLC 4.Welt'Class Before Work: -5.Permit to Dr l Number_ Name: Development 0 Booratory 9 211-071 3.Address: 3705 Arctic Blvd.#2114 Anchorage,AK 99503 , Stratigraphic 0 Service 0.6.API Number: 283-20156-00 7.Property Designation(Lease Number): 8.Well Name and Number: ADL 388233 Three Mile Creek#3 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): NA Three Mile Creek Beluga Gas 11.Present Well Condition Summary: 'T l3measured 5*49 :feet . . :measured.1743 :feet true vertical 4771 feet Junk measured None feet Effective Depth measured 5040 feet Packer measured 1663-4100 feet true vertical 4665 feet true vertical 1584-3850 feet . Casing Length Size MD TVD Burst Collapse Structural Conductor .80 ;13.718.72#440 .80 80 (: Surface 886 95/8 3646355 .4, asa 35201 psi 2020ps1 intermediate Production 51449+ 5 11/2 15.5#055 51149 4765 4910 psi 4040psi Liner Perforation depth Measured depth 1704-4992 feet ne•.Verh oaF_r pth'1603—4620 .feet • Tubing(size,grade,measured and true vertical depth) 2 7/8 6.5#Ji55 3577 3268 Packers and SSSV(type,measured and true vertical depth) 12.Stimulation or cement squeeze summary: Intervals treated(measured): pp�, �s,1 1 V l`iA .SCA" s3 Treatment descriptions includinglvolumes used and final pressure: NA 13. Representative Daily Average Productienor Injection Da Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 Subsequent to operation: 0 0 0 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) ,15.Well Class after work: Daily Report of Wen Operations El Exploratory 9 Developtnent Service 9 Stratigraphic 9 Copies of Logs and Surveys Run 0 16.Well Status after work: Oil 9 Gas 9 WDSPL,0 , Printed and Electronic Fracture Stimulation Data 0 GSTOR 9 WINJ 0 WAG Li GINJ 9 3USP L SPLUG 9 17.1 hereby certify that the foregoing is true and correct to the best of my knovvle . ,;Sunny Number or•N/A i€CO_ _Exempt 317-285 Authorized Name: George Pollock Contac Name: Authorized Title: M -Prod Ops&Eng CorrtactErna#_ QpollockAaurorapower.cr Authorized Signature: '" Dab 1/23/2018 Contact Phone: 907.351.8286 (,_Form ,2 C le) REDMS L." A F,, �: H�18 10-404 Revised 4/2017,�� 2/41 s Submit Original Only • • Aurora-Gas.,LLA: Operations Summary— Set Temporary Plug Three Mile Creek#3 Well juIy22,xO 7 1500 hours Mobilize to location from SM2 1530 hours R/U WL, PT lubricator w/wellbore 1600=h-ours =RIId-w12.33";gauge=ring=to 1743'=KB,=tag profile,=POOH 1630 hours 8111 w/2=7/8"X-line w/ PX Plug to 1743',WT,set plug, POOH 1715 hours RIH w/2" SB w/Prong to 1743',WT,set Prong, POOH 1745 hours Bleed off well, monitor Pressure 30 minutes, Pass 115 hours =RD WL . w S • 2 7/8 6.5#8rd EUE J-55 Tubing Aurora Gas, LLC �,#,' ` `,'it ‘,`.' Three Mile Creek#3 4 ;- . , PTD#:211.07113-38"72#Structural AP1#:50-283-20156-00-00 �,? Conductor driven to 80'GL RKB-14ft ' , (July 2017) '. 9-518"361/Surface Casing set at 886' Current Cement w/12.0 ppg Type l Accelerated Drill 12-1/4"Hole to 901' ,''1 'pi.2-7/8" x 5-W'annulus diced . with 9.6#inhibited brine 1 hydraulic Packer*1663' 1704-24' ' II _,..-,, Slitirrug Sleeve X0*-174Y(closed) 1773-78' PX Plug 1.1743' I Hydraulic Set Packer @ 1943' �� Weatherford Expansion joint Eft travel, le 2112-20&2126-2132 a ill top @2082' 2188-2208' �4 2386-2416' =11 i MitringSleeve XD a -2313'MD i,- (Closed) • w Hydraulic Packer*-2484' 2512-32' l 7616-26' _� Sliding Sleeve XD @-2595' (Closed) I , iti Sliding Sleeve XD @ 3076e(Closed) 379-84' _...ing ii Hydraulic Packer at 3182' 3362-72'&3410-20'Frac with ` i 0X-Nipple 2313"ID 3,289' K8.000 II)of sand' 1 111 Frac dove @ 3391',1.5"ball seat(Closed) _ , Mechanical Packer(a?3534'w/On- ' —` •'0. Off Tool*3532'w/231 profile X 3926-46'&3966-86'Frac with ___ --_- supple W/L Entry Guide.LOT @a, 94,510(1 lb of sand -3577' mill Black Cat Mechanical'Packer 4384-94' N 4100'w/2313 profile X nipp a at Cr, 4110',ceramic burst disk 4120' III 4987-92' 'mud PBTD 5,040'(4665'TVD) 5 W'15.5#J-55 Casing to 5149'(t1D) Drilled 8-1/2"Hole to 5,159'MI) (4771'TVD) (leaned out to411X11'in Sept.2012 ri°i(`1' ` • • yOF Tit hw\� /7/: THE STATE Alaska Oil and Gas o fA Conservation Commission F.. =��s_e C�1 l LAsKA. . -� 333 West Seventh Avenue Anchorage, Alaska 99501-3572 \T, GOVERNOR BILL WALKER g va Main: 907.279.1433 '_"e*' Fax: 907.276.7542 www.aogcc.alaska.gov George Pollock Manager Aurora Gas, LLC S�NH�® JUL2 j 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Three Mile Creek Field, Beluga Undefined Gas Pool, Three Mile Creek 3 Permit to Drill Number: 211-071 Sundry Number: 317-286 Dear Mr. Pollock: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. The Alaska Oil and Gas Conservation Commission(AOGCC)approves the setting of a temporary plug in this well to provide isolation from the reservoir as a short-term barrier. This work does not meet AOGCC's regulatory requirements for suspension or plugging and abandonment of this well. Prior to relinquishing the lease back to the landowner,the operator is required by law to properly plug and abandon this well. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 02fr•CHollis S. French 4L. Chair DATED this 4 day of July, 2017. RBDMS 1/1/JUL 1 1 2017 S 0 RECEIVED STATE OF ALASKA JUN 1 6 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon 0 Plug Perforations 0 Fracture Stimulate 0 Repair Well D Operations shutdown 0 Suspend 0 Perforate 0 Other Stimulate 0 Pull Tubing Ei Change Approved Program 0 Plug for Redrill 0 Perforate New PoolL] Re-enter Susp Well 0 Alter Casing 0 Other Temporary Plug 0, 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number Aurora Gas,LLC Exploratory 0 Development 0, 4 211-071 3.Address: 1400 W.Benson Blvd.Suite 410 Stratigraphic 0 Service D 6.API Number. Anchorage,AK 99503 50-283-20156-00 ' 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? 4/if' Three Mile Creek#3 Will planned perforations require a spacing exception? Yes LI No Ff hi.a 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL 388233 Three Mile Creek Beluga Undefined Gas 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Totale., q11 TyD(ft): Effective Depth MD: Effective Depth ND: MPSP(psi): Plugs(MD): Junk(MD): 5149' lib 5040 ' 4665' • 650 psi 5040' None Casing Length Size MD ND Burst Collapse Structural Conductor 80' 13 3/8"721 H40 110' 110' Surface 886" 9518"361 J55 886' 883' 3520 psi 2020 psi Intermediate Production 5149' 5 1/2"15.5#J55 5149' 4766' 4910 psi 4040 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(It): 1704'-4992' , 1683'-4620' 2 7/8" 6.5#J55 3577' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft y.,, Hydraulic set and Mechanical packers Hydraulic©1663',1943',2313'and 3182'.Mechanical @ 3534'and 4100' 12.Attachments: Proposal Summary Ei Wellbore schematic Ei 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Stratigraphic 0 Development 0' Service 0 14.Estimated Date for TBD 15.Well Status after proposed work: Commencing Operations: OIL 0 WINJ D WDSPL Ei Suspended El 16.Verbal Approval: Date: GAS 0 • WAG 0 GSTOR D SPLUG CI Commission Representative: GINJ 0 Op Shutdown ci Abandoned Il 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. George Pollock George Pollock Authorized Name: ../ Contact Name: Authorized Title: Manager-P . Ir':ESTrar Contact Email: apollock eau rorapowercoM Contact Phone: 907-277-1003 Authorized Signature: / Date: 16-Jun-17 COMMISSION USE ONLY Conditions of approval: 'otify Commission so that a representative may witness Sundry Number 2-1C Plug Integrity 0 BOP Test 0 Mechanical Integrity Test D Location Clearance 111 Other: y‹,--levik- ,e„mtkj-04 ret,,A40. cc,ii-S v....X1,-1," VAILTCT ("Le Cx4yZelk.401,5747% Ft't .'0,:t .ec -1..- t•EX---) te. Post Initial Injection MIT Req'd? Yes El No k 10--4o4 RBDMS 1,'-' JUL 1 1 2017 Spacing Exception Required? Yes El No Subsequent Form Required: Approved by: HD_4_Can.------ COMMISSIONER APPROVED BY THE COMMISSION Date: 1 q 1 kl Submit Form and °31. kiPomil10-4037-/Revilsed lafo: RILINA Ld for 12 months ifr-io btlte date of approval. Attachments in Duplicate 1' • • Aurora Gas, L L C June 16, 2017 Ms. Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Application for Sundry Approval—Set Temporary Plug Three Mile Creek#3 Well PTD #: 211-071 API #: 50-283-20156-00 Dear Ms. Foerster: Aurora Gas, LLC hereby requests approval to set a temporary plug to secure this onshore development well in the Three Mile Creek Beluga Undefined Gas Field on the west side of Cook Inlet, northeast of the Village of Tyonek. This well is currently not producing and the well is mechanically sound. Aurora Gas is currently in Chapter 11 bankruptcy protection while attempting to reorganize and emerge with new owners/investors. This application is being submitted as part of our Reorganization Plan filed with the bankruptcy court if liquidation actions are ordered. Aurora Gas, LLC will provide all potential new owners/investors notice of the impending action before on-site activity begins. The proposed work involves setting a plug via wireline in the profile at a depth of 1,663' above all open perforated intervals to mechanically isolate the reservoir. After this plug is set, tubing pressure will be monitored for 30 minutes to ensure isolation. The master valve will be closed providing double isolation and the wellhead secured. A follow up pressure reading will be obtained after 24 hours to ensure the integrity of the plug. . Please find the attached information as required by 20 AAC 25.110 for your review: • Form 10-403 Sundry Application • Current wellbore diagram illustrating the current well configuration. • Slickline Temporary Plug Set—Generalized Procedure If you have any questions or require any further information, please contact me at (907) 277-1003. Sincerely, G rge Pollock Manager—Production Operations & Engineering 4645 Sweetwater Boulevard,Suite 200 * Sugarland,TX 77479 * (832) 939-8991 1400 W Benson Blvd, Suite 410 * Anchorage, AK 99503 * (907) 277-1003 • • 2 7/8 65#8rd ELSE J-55 Tubing t ! f Aurora Gas, LLC ',* '° .4 t,} ,' ir' Three Mile Creek#3 PTD#:211-071 F 13-3/8"72#Structural API#:50-283-20156-00-00 •, ." Conductor driven to 80'GL RKB -14ft ' . . (Sept.2012) , < ♦ ` -, , ti ` 9-5/8"36#Surface Casing set at 886' Current "`*• ''. Cement w/12.0 ppg Type I . Accelerated * „ .,'.� Drill 12-1/4"Hole to 901' '„`. 4. `a:r 14 . 2-7/8" x 5-1/2"annulus displaced ' with 9.6#inhibited brine *-- ,« „, * r s Hydraulic Packer @1663' t' a { 1704-24' X . 1773-78' ``" , -- Sliding Sleeve XD @—1743'(closed) ° *A Hydraulic Set Packer(1943' <' Weatherford Expansion joint 6ft travel, 2112-20&2126-2132 =111 › �!�"" top 2082' 2188-2208' d4 . 2386-2416' Sliding Sleeve XD(a —2313'MD " '` (Closed) . . * ',, «.. is Hydraulic Packer @—2484' 2512-32' � ipiap- 2616-26' r o-- Sliding Sleeve XD(t—2595' (Closed) ;I/ i f' Sliding Sleeve XD Ca—3076'(Closed) 3079-84' '__, om __r-- . ,- s Hydraulic Packer at 3182' t` ;`J ' X-Nipple 2313"ID @ 3,289' 3362-72'&3410-20'Frac with 7.1 jam. SS.000 i b of sand + .14 Frac door a 3391',13"ball seat(Closed) '4 Mechanical Packer*3534'wI On- ' ' Off Tool at 3532'w/231 profile X 3926-46'&3966-86'Frac with "' ' nipple W/L Entry Guide.EOT 4t.t1(it;11-of sand —3577' Black Cat Mechanical Packer ie -_!� T 4100'w/2313 profile X nipple at 4384-94' ""�! 1 C 1 ilie'"" 4110',ceramic burst disk 4120' 4987-92' -"".111111i CP". - PBTD(d 5,040'(4665'TVD) A IL 5 W'1534 J-55 Casing to 5149'(MD) Drilled 8-1/2"Hole to 5,159'MD (4771'TVD) Cleaned out to 4100'in Sept.2012 w/CT • AURORA GAS, LLC Slickline Temporary Plug Set - Generalized Procedure June 2017 SUMMARY: This procedure describes the steps taken to set a temporary plug in wells operated by Aurora Gas, LLC to secure the well for a short term shut in. RIH with drift for the appropriate sized tool for the tubing, in most cases 2 7/8"tubing with 2.312"or 3 1/2"tubing with 2.812"X landing nipple profile. Set PXX plug in uppermost landing profile. If a profile is not available, RIH with tubing stop pack-off plug and set above uppermost packer. After plug is set, a negative pressure test will be performed to ensure the plug has isolated the productive intervals from the surface. Upon passing the negative pressure test, the wellhead will be secured. PROCEDURE: 1) AG Operators to shut-in well and monitor pressure while rigging up. 2) RU Pollard Wire Line and lubricator on tree after removal of tree cap. Open well to pressure test lubricator—have pressure gauge on lubricator. 3) RIH with appropriate drift for X profile and sliding sleeves in upper profile. Pass through sleeve approximately 10' to insure safe operation of setting tool. POOH. 4) RIH with PXX Plug body on X-Line running tool. Set Plug body in upper most Sliding sleeve X profile above upper most production packer in well. 5) RIH with RB retrieval tool as running tool with prong. Set Prong in Plug body and POOH. 6) Record pressure and Bleed well bore to zero PSI, Monitor for 30 minutes recording pressure readings at 15 minute intervals. 7) Test successful if no pressure increase observed. If test fails, RIH and reset plug. 8) RDMO Pollard Wire Line. 9) Secure the wellhead. 10)Move to next well. 11)After 24 hours, a pressure reading will be obtained to ensure the integrity of the plug. 41€ .Savage(6/11/2017) Image Project Well History 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. c3Z1 - Q_ .J Well History File Identifier Organizing(done) ❑ Two-sided ❑ Rescan Needed RESC N: OVERSIZED: NOTES: Color Items: rzt: Xyscale Items: : ❑ Poor Quality Originals: ❑ Other: ❑ Other: , BY: eft Date: /s/ u Project Proofing BY: AM Date: 14117105- 1 17 5 isi IA Scanning Preparation5- x 30 = I + c . = TOTAL PAGES 1 4;--c9"" (Count does not include cover sheet) BY: Maria Date: Liti 7/f...5-Production Scanning Stage 1 Page Count from Scanned File: ) 5-3 (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: YES NO BY: MEM Date: /41I 7fiLS /s/ 04F Stage 1 If NO in stage 1, page(s)discrepancies were found: YES NO BY: Maria Date: /s/ Stage 2 Additional Well Reports: YES NO TOTAL PAGES: l'3 Digital version appended by: Meredith- Michal Date: (,p/2_0 ( ( s- /s/ Final Page Count: Stage 1 + Stage 2: TOTAL PAGES: 1 q Co I Scanning is complete at this point unless rescanning is required. 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C G C f0 O V1 0 0 c C G �+ LL� '�O N .Q m 10 U E Q co W £ Q 24 • . ------ , urora Gas,'LLC April 6, 2015 Ms. Meredith Guhl Petroleum Geology Assistant Alaska Oil & Gas Conservation Commission RECEIVED 333 W. 7`h Avenue Suite 100 APR 0 6 2015 Anchorage, AK 99501 Re: Three Mile Creek#3—PTD-211-071 AOGCC Transmittal of Requested Data Dear Ms. Guhl: With this letter, Aurora Gas, LLC formally transmits the requested data for the Three Mile Creek#3 well (PTD-211-071)that was completed on October 27, 2011. Specifically,the following printed items are submitted: 1. Halliburton EOW Report 2. Directional Survey Let me know if you require any further information. Regards, `' , - eorge Pollock Manager, Production Operations&Engineering Aurora Gas, LLC cc: Patricia Bettis 4645 Sweetwater Boulevard, Suite 200 * Sugarland,TX 77479 * (832) 939-8991 1400 W Benson Blvd, Suite 410 * Anchorage, AK 99503 * (907) 277-1003 RECEIVED Ih, j APR PeOGCC Aurora Gas, LLC Cook Inlet Three Mile Creek Unit e 5 ;, TMCU#3 PH ! PN Ny I riServices Definitive Survey Report i5 i 16 November, 2011 4 ' i 1 HALLIBURTON amu , _ . . Sperry Drilling Services • Halliburton Company Definitive Survey Report Company: Aurora Gas,LLC Local Co-ordinate Reference: Well TMCU#3 Project: Cook Inlet TVD Reference: TMCU#3 081611 @ 303.50ft(287.5+16) Site: Three Mile Creek Unit MD Reference: TMCU#3 081611 @ 303.50ft(287.5+16) Well: TMCU#3 North Reference: Grid Wellbore: TMCU#3 Survey Calculation Method: Minimum Curvature Design: TMCU#3 }::Database: Sperry EDM.16 PRD Project Cook Inlet,COOK INLET BASIN Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor TMCU#3 Well Position +NI-S 0.00 ft Northing: 2,621,669.89ft Latitude: 61°10'12.894 N +E/-W 0.00 ft Easting: 285,834.57 ft Longitude: 151°12'47.03 W Position Uncertainty 0.00 ft Wellhead Elevation: 303.50ft Ground Level: 287.50ft "Wellbore TMCU#3 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (0) (0) (nT) L BGGM2011 10/1/2011 17.96 73.99 55,679 Design TMCU#3 Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 16.00 Depth From(TVD) +N/-S +E/-W Direction 16.00 0.00 0.00 296.91 Survey Program Date 11/16/2011 F� s � Survey (ft) l Su1. • ,a Description Start Date 93.00 993.05 TMCU#3(Blind)(TMCU#3) BLIND Blind drilling 09/27/2011 1,025.30 5,046.46 TMCU#3(MWD)(TMCU#3) MWD MWD-Standard 10/11/2011 Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +Et-W Northing Easting DLS' Section (1) (ft) (ft) (ft) (ft) (ft) (ft) (°(100') (ft) Survey Tool Name . 16.00 0.00 0.00 16.00 -287.50 0.00 0.00 2,621,669.89 285,834.57 0.00 0.00 UNDEFINED 93.00 0.00 0.00 93.00 -210.50 0.00 0.00 2,621,669.89 285,834.57 0.00 0.00 BLIND(1) 136.91 2.12 328.34 136.90 -166.60 0.69 -0.43 2,621,670.58 285,834.14 4.83 0.69 BLIND(1) 167.23 2.49 326.42 167.20 -136.30 1.72 -1.08 2,621,671.61 285,833.49 1.25 1.74 BLIND(1) 197.51 2.50 328.53 197.45 -106.05 2.83 -1.79 2,621,672.72 285,832.78 0.31 2.88 BLIND(1) 227.71 2.66 325.62 227.62 -75.88 3.97 -2.53 2,621,673.86 285,832.04 0.68 4.05 BLIND(1) 258.04 2.85 325.50 257.91 -45.59 5.17 -3.36 2,621,675.06 285,831.21 0.63 5.33 BLIND(1) 288.07 3.22 323.45 287.90 -15.60 6.46 -4.28 2,621,676.35 285,830.29 1.28 6.74 BLIND(1) 318.36 3.21 323.09 318.14 14.64 7.83 -5.30 2,621,677.71 285,829.27 0.07 8.27 BLIND(1) 348.85 3.36 322.58 348.58 45.08 9,22 -6.35 2,621,679.11 285,828.22 0.50 9.84 BLIND(1) 379.31 3.45 320.27 378.99 75.49 10.63 -7.48 2,621,680.52 285,827.09 0.54 11.48 BLIND(1) 409.48 3.75 321.27 409.10 105.60 12.10 -8.68 2,621,681.99 285,825.89 1.02 13.22 BLIND(1) 439.68 4.02 323.32 439.23 135.73 13.72 -9.93 2,621,683.61 285,824.64 1.01 15.06 BLIND(1) 11/16/2011 9:48:44AM Page 2 COMPASS 2003.16 Build 71 Halliburton Company • , Definitive Survey Report Company: Aurora Gas,LLC Locaaotdflate-‘°.... '401 Well TMCU#3 Project: Cook Inlet TVD Reference: TMCU#3 081611 @ 303.50ft(287.5+16) Site: Three Mile Creek Unit ,MD Reference: TMCU#3 081611 @ 303.50ft(287.5+16) Well: TMCU#3 North Reference: Grid Wellbore: TMCU#3 Survey Calculation Method: Minimum Curvature Design: TMCU#3 Database: .Sperry EDM.16 PRD Survey Map Map Vertical MD Inc Azi ND TVDSS +14/-S +e-W Northing Easting DLS Section (ft) (*) (*) (ft) (ft) (ft) (ft) (ft) (ft} (MOO') (ft) Survey Tool Name 469.19 4.31 322.01 468.66 165.16 15.42 -11.23 2,621,685.31 285,823.34 1.03 16.99 BLIND(1) 503.93 4.75 322.16 503.29 199.79 17.59 -12.92 2,621,687.48 285,821.65 1.27 19.48 BLIND(1) 534.33 5.08 323.72 533.58 230.08 19.67 -14.49 2,621,689.55 285,820.09 1.17 21.82 BLIND(1) 595.69 5.64 323.54 594.67 291.17 24.28 -17.88 2,621,694.17 285,816.69 0.91 26.94 BLIND(1) 627.13 5.62 322.05 625.96 322.46 26.74 -19.75 2,621,696.63 285,814.82 0.47 . 29.71 BLIND(1) 658.57 5.70 321.99 657.25 353.75 29.18 -21.66 2,621,699.07 285,812.91 0.26 32.52 BLIND(1) 689.97 6.09 322.77 688.48 384.98 31.74 -23.63 2,621,701.62 285,810.95 1.27 35.43 BLIND(1) 721.35 6.33 322.61 719.68 416.18 34.44 -25.68 2,621,704.32 285,808.89 0.77 38.49 BLIND(1) 752.75 6.41 322.97 750.88 447.38 37.21 -27.79 2,621,707.10 285,806.78 0.28 41.62 BLIND(1) 784.11 7.05 323.83 782.03 478.53 40.16 -29.98 2,621,710.05 285,804.59 2.07 44.91 BLIND(1) 815.55 7.06 323.22 813.23 509.73 43.27 -32.28 2,621,713.15 285,802.30 0.24 48.36 BLIND(1) 930.19 8.13 323.00 926.86 623.36 55.38 -41.37 2,621,725.27 285,793.20 0.93 61.96 BLIND(1) 961.59 8.17 323.14 957.94 654.44 58.94 -44.05 2,621,728.83 285,790.53 0.14 65.95 BLIND(1) 993.05 8.19 322.57 989.08 685.58 62.51 -46.75 2,621,732.40 285,787.82 0.27 69.98 BLIND(1) 1,025.30 8.14 323.43 1,021.01 717.51 66.17 -49.51 2,621,736.05 285,785.07 0.41 74.09 MWD(2) 1,055.88 8.34 321.57 1,051.27 747.77 69.64 -52.17 2,621,739.53 285,782.40 1.09 78.04 MWD(2) 1,087.38 8.32 319.33 1,082.44 778.94 73.16 -55.08 2,621,743.05 285,779.49 1.03 82.23 MWD(2) 1,118.86 8.51 317.10 1,113.58 810.08 76.60 -58.15 2,621,746.48 285,776.42 1.20 86.52 MWD(2) 1,150.30 8.82 314.30 1,144.66 841.16 79.98 -61.46 2,621,749.87 285,773.11 1.66 91.00 MWD(2) • 1,181.74 8.96 311.76 1,175.72 872.22 83.30 -65.01 2,621,753.18 285,769.56 1.33 95.67 MWD(2) 1,244.57 9.48 307.42 1,237.74 934.24 89.70 -72.77 2,621,759.59 285,761.80 1.38 105.49 MWD(2) 1,275.89 10.07 306.48 1,268.61 965.11 92.90 -77.02 2,621,762.78 285,757.55 1.95 110.72 MWD(2) 1,307.31 10.36 305.00 1,299.53 996.03 96.15 -81.54 2,621,766.03 285,753.03 1.24 116.23 MWD(2) 1,338.74 10.77 301.98 1,330.43 1,026.93 99.33 -86.35 2,621,769.21 285,748.23 2.19 121.95 MWD(2) 1,370.14 11.01 297.80 1,361.26 1,057.76 102.28 -91.49 2,621,772.16 285,743.09 2.63 127.87 MWD(2) 1,401.45 11.60 294.95 1,391.96 1,088.46 105.00 -96.99 2,621,774.89 285,737.59 2.59 134.01 MWD(2) 1,433.00 12.29 290.86 1,422.83 1,119.33 107.53 -103.00 2,621,777.42 285,731.57 3.46 140.52 MWD(2) 1,464.47 12.90 289.90 1,453.54 1,150.04 109.92 -109.43 2,621,779.81 285,725.14 2.05 147.33 MWD(2) 1,496.00 13.58 290.01 1,484.24 1,180.74 112.39 -116.22 2,621,782.27 285,718.35 2.16 154.50 MWD(2) 1,527.46 14.61 288.47 1,514.75 1,211.25 114.91 -123.46 2,621,784.79 285,711.12 3.48 162.09 MWD(2) 1,558.87 15.55 287.35 1,545.08 1,241.58 117.42 -131.23 2,621,787.30 285,703.34 3.13 170.16 MWD(2) 1,589.81 16.37 286.33 1,574.82 1,271.32 119.88 -139.38 2,621,789.77 285,695.20 2.80 178.54 MWD(2) 1,621.27 17.31 286.87 1,604.93 1,301.43 122.49 -148.11 2,621,792.37 285,686.47 3.03 187.51 MWD(2) 1,652.67 18.13 287.36 1,634.84 1,331.34 125.30 -157.24 2,621,795.18 285,677.34 2.65 196.92 MWD(2) 1,684.11 18.73 287.32 1,664.67 1,361.17 128.26 -166.73 2,621,798.15 285,667.85 1.91 206.72 MWD(2) 1,715.49 19.41 286.63 1,694.33 1,390.83 131.25 -176.54 2,621,801.14 285,658.04 2.28 216.82 MWD(2) 1,746.91 20.22 286.28 1,723.89 1,420.39 134.27 -186.75 2,621,804.15 285,647.83 2.61 227.30 MWD(2) 1,778.48 21.25 286.61 1,753.41 1,449.91 137.44 -197.47 2,621,807.32 285,637.11 3.28 238.29 MWD(2) 1,809.81 22.19 286.43 1,782.52 1,479.02 140.73 -208.59 2,621,810.61 285,625.99 3.01 249.69 MWD(2) 1,841.28 23.07 286.53 1,811.57 1,508.07 144.17 -220.20 2,621,814.05 285,614.38 2.80 261.60 MWD(2) 11/16/2011 9:48:44AM Page 3 COMPASS 2003.16 Build 71 • • Halliburton Company Definitive Survey Report ��� .,.... . ,,--- Companro Aurora Gas,LLC Local Co-ordinate Reference: Well TMCU#3 Project: Cook Inlet TVD Reference: TMCU#3 081611 @ 303.50ft(287.5+16) Site: Three Mile Creek Unit D Re . TMCU#3 081611 @ 303.50ft(287.5+16) Well• TMCU#3x y ;' Grid Wellbore TMCU#3 Survey Calculation Method: Minimum Curvature � ' \TMCU#3 Database .Sperry EDM.16 PRD Survey It. ) V ` ` Map y� - .%p Vertical mo 4 i t D WD- +N!-S +EI-W Northing Fasting DLS Section (f ( ,, `t,J (ft) (ft) (ft) (ft) (°11001 (ft) Survey Tool Name 1,872.67 23.45 285.81 1,840.40 1,536.90 147.62 -232.10 2,621,817.50 285,602.48 1.51 273.78 MWD(2) 1,903.94 23.61 286.09 1,869.07 1,565.57 151.05 -244.11 2,621,820.93 285,590.48 0.62 286.04 MWD(2) 1,935.28 23.39 286.15 1,897.82 1,594.32 154.52 -256.11 2,621,824.40 285,578.47 0.71 298.31 MWD(2) 1,966.66 23.33 286.37 1,926.62 1,623.12 158.00 -268.06 2,621,827.88 285,566.53 0.34 310.54 MWD(2) 1,998.13 23.34 285.56 1,955.52 1,652.02 161.43 -280.04 2,621,831.31 285,554.54 1.02 322.78 MWD(2) 2,029.52 23.45 285.81 1,984.33 1,680.83 164.80 -292.04 2,621,834.68 285,542.54 0.47 335.00 MWD(2) 2,060.95 23.35 286.17 2,013.17 1,709.67 168.24 -304.04 2,621,838.12 285,530.54 0.56 347.26 MWD(2) 2,092.43 23.30 286.09 2,042.08 1,738.58 171.70 -316.01 2,621,841.58 285,518.57 0.19 359.51 MWD(2) 2,123.89 23.28 286.21 2,070.98 1,767.48 175.16 -327.96 2,621,845.04 285,506.62 0.16 371.73 MWD(2) 2,155.26 23.20 285.44 2,099.80 1,796.30 178.54 -339.87 2,621,848.42 285,494.72 1.00 383.87 MWD(2) 2,186.64 23.12 285.71 2,128.65 1,825.15 181.85 -351.76 2,621,851.73 285,482.83 0.42 395.97 MWD(2) 2,217.98 23.20 285.05 2,157.47 1,853.97 185.12 -363.64 2,621,855.00 285,470.94 0.87 408.05 MWD(2) 2,249.22 23.91 284.94 2,186.10 1,882.60 188.35 -375.70 2,621,858.23 285,458.89 2.28 420.27 MWD(2) 2,280.63 24.80 285.09 2,214.72 1,911.22 191.71 -388.21 2,621,861.59 285,446.38 2.84 432.94 MWD(2) 2,312.17 25.71 284.84 2,243.24 1,939.74 195.18 -401.21 2,621,865.06 285,433.38 2.90 446.11 MWD(2) 2,343.56 26.62 284.94 2,271.42 1,967.92 198.74 -414.59 2,621,868.62 285,420.00 2.90 459.64 MWD(2) 2,375.00 27.40 284.82 2,299.43 1,995.93 202.40 -428.39 2,621,872.28 285,406.20 2.49 473.61 MWD(2) 2,406.42 28.05 284.36 2,327.24 2,023.74 206.09 -442.54 2,621,875.97 285,392.06 2.18 487.89 MWD(2) 2,437.85 28.27 284.35 2,354.95 2,051.45 209.76 -456.91 2,621,879.64 285,377.69 0.70 502.37 MWD(2) 2,469.24 28.34 284.55 2,382.59 2,079.09 213.48 -471.32 2,621,883.36 285,363.27 0.38 516.90 MWD(2) 2,500.41 28.75 283.78 2,409.97 2,106.47 217.12 -485.76 2,621,887.00 285,348.83 1.77 531.43 MWD(2) 2,531.84 29.31 283.78 2,437.45 2,133.95 220.75 -500.57 2,621,890.63 285,334.02 1.78 546.28 MWD(2) 2,563.24 29.17 283.80 2,464.85 2,161.35 224.41 -515.47 2,621,894.29 285,319.13 0.45 561.22 MWD(2) 2,594.69 29.15 284.08 2,492.31 2,188.81 228.10 -530.34 2,621,897.98 285,304.25 0.44 576.15 MWD(2) 2,626.05 29.17 284.85 2,519.70 2,216.20 231.92 -545.14 2,621,901.80 285,289.46 1.20 591.07 MWD(2) 2,657.52 29.00 283.80 2,547.20 2,243.70 235.70 -559.96 2,621,905.58 285,274.64 1.71 606.00 MWD(2) 2,689.00 28.68 285.55 2,574.78 2,271.28 239.55 -574.65 2,621,909.43 285,259.95 2.87 620.84 MWD(2) 2,720.42 28.58 286.17 2,602.35 2,298.85 243.66 -589.13 2,621,913.54 285,245.47 1.00 635.62 MWD(2) 2,751.77 28.51 286.99 2,629.89 2,326.39 247.94 -603.49 2,621,917.82 285,231.11 1.27 650.36 MWD(2) 2,783.09 28.40 286.93 2,657.43 2,353.93 252.29 -617.76 2,621,922.17 285,216.84 0.36 665.05 MWD(2) 2,814.56 28.33 286.26 2,685.12 2,381.62 256.56 -632.09 2,621,926.44 285,202.51 1.04 679.76 MWD(2) 2,845.86 28.41 286.79 2,712.66 2,409.16 260.79 -646.35 2,621,930.67 285,188.25 0.84 694.39 MWD(2) 2,877.27 28.08 288.79 2,740.33 2,436.83 265.33 -660.50 2,621,935.21 285,174.10 3.19 709.07 MWD(2) 2,908.71 28.04 290.33 2,768.08 2,464.58 270.28 -674.43 2,621,940.16 285,160.17 2.31 723.73 MWD(2) 2,940.17 27.79 291.53 2,795.88 2,492.38 275.54 -688.19 2,621,945.42 285,146.41 1.95 738.38 MWD(2) 2,971.60 27.53 291.78 2,823.71 2,520.21 280.93 -701.75 2,621,950.80 285,132.85 0.91 752.91 MWD(2) 3,002.98 27.77 291.72 2,851.51 2,548.01 286.32 -715.28 2,621,956.20 285,119.33 0.77 767.41 MWD(2) 3,034.44 27.83 292.12 2,879.34 2,575.84 291.80 -728.89 2,621,961.68 285,105.72 0.62 782.03 MWD(2) 3,065.88 27.82 291.72 2,907.15 2,603.65 297.28 -742.50 2,621,967.15 285,092.10 0.59 796.65 MWD(2) 3,097.27 27.74 291.86 2,934.92 2,631.42 302.71 -756.09 2,621,972.58 285,078.52 0.33 811.22 MWD(2) 11/16/2011 9:48:44AM Page 4 COMPASS 2003.16 Build 71 • • Halliburton Company Definitive Survey Report Company: Aurora Gas, LLC Local Co-ordinate Reference: Well TMCU#3 Project: Cook Inlet ; ND Reference: TMCU#3 081611 @ 303.50ft(287.5+16) Site: Three Mile Creek Unit ':MD Reference: TMCU#3 081611 @ 303.50ft(287.5+16) Well: '; TMCU#3 North Reference: ' '*'''`q Grid Weilbore: TMCU#3 Survey Calculation Method: Minimum Curvature Design: TMCU#3 Database: Sperry EDM.16 PRD Survey •wItamap Map Vertical MD 'Inc Pat, ND TVDSS + ,,,� 1 +EI•W Northing t Easting DLS Section (ft) (') ( (ft) (ft) (ft) ��; : � (ft) �F«� ...' (ft) (°/100') (ft) Survey Tool Name . „,, vim. 3,128.73 27.48 291.45 2,962.79 2,659.29 308.09 -769.64 2,621,977.96 285,064.97 1.02 825.74 MWD(2) 3,160.16 27.41 291.92 2,990.69 2,687.19 313.44 -783.10 2,621,983.32 285,051.51 0.72 840.17 MWD(2) 3,191.66 27.35 292.14 3,018.66 2,715.16 318.88 -796.53 2,621,988.75 285,038.08 0.37 854.60 MWD(2) 3,223.09 27.09 291.76 3,046.61 2,743.11 324.25 -809.86 2,621,994.12 285,024.75 1.00 868.92 MWD(2) 3,254.55 27.15 291.58 3,074.61 2,771.11 329.55 -823.19 2,621,999.42 285,011.42 0.32 883.20 MWD(2) 3,285.83 26.87 292.22 3,102.48 2,798.98 334.84 -836.37 2,622,004.72 284,998.24 1.29 897.36 MWD(2) 3,317.34 26.75 292.01 3,130.60 2,827.10 340.19 -849.54 2,622,010.07 284,985.07 0.49 911.52 MWD(2) 3,348.73 26.79 291.63 3,158.63 2,855.13 345.45 -862.66 2,622,015.32 284,971.95 0.56 925.60 MWD(2) 3,380.14 26.82 291.97 3,186.66 2,883.16 350.71 -875.81 2,622,020.58 284,958.80 0.50 939.71 MWD(2) 3,411.58 26.83 292.43 3,214.72 2,911.22 356.07 -888.95 2,622,025.94 284,945.66 0.66 953.85 MWD(2) 3,443.05 27.28 292.49 3,242.74 2,939.24 361.54 -902.18 2,622,031.41 284,932.44 1.43 968.12 MWD(2) 3,474.57 27.21 292.89 3,270.77 2,967.27 367.10 -915.49 2,622,036.98 284,919.12 0.62 982.51 MWD(2) 3,506.00 27.27 293.14 3,298.71 2,995.21 372.73 -928.73 2,622,042.60 284,905.88 0.41 996.86 MWD(2) 3,537.47 27.49 292.88 3,326.66 3,023.16 378.39 -942.05 2,622,048.26 284,892.56 0.80 1,011.30 MWD(2) 3,568.84 27.21 292.73 3,354.52 3,051.02 383.97 -955.34 2,622,053.84 284,879.28 0.92 1,025.68 MWD(2) 3,600.34 27.26 292.93 3,382.53 3,079.03 389.57 -968.62 2,622,059.44 284,865.99 0.33 1,040.06 MWD(2) 3,631.74 27.31 293.75 3,410.43 3,106.93 395.27 -981.84 2,622,065.14 284,852.78 1.21 1,054.42 MWD(2) 3,663.12 27.17 293.80 3,438.33 3,134.83 401.06 -994.98 2,622,070.93 284,839.63 0.45 1,068.76 MWD(2) 3,694.52 26.98 293.37 3,466.29 3,162.79 406.78 -1,008.08 2,622,076.65 284,826.54 0.87 1,083.03 MWD(2) 3,725.95 27.08 293.71 3,494.29 3,190.79 412.48 -1,021.18 2,622,082.35 284,813.44 0.59 1,097.29 MWD(2) 3,757.37 27.25 293.78 3,522.24 3,218.74 418.26 -1,034.31 2,622,088.13 284,800.31 0.55 1,111.61 MWD(2) 3,788.90 27.99 293.89 3,550.18 3,246.68 424.17 -1,047.68 2,622,094.04 284,786.94 2.35 1,126.21 MWD(2) 3,820.31 28.31 294.13 3,577.87 3,274.37 430.20 -1,061.21 2,622,100.06 284,773.41 1.08 1,141.01 MWD(2) 3,851.76 28.14 293.82 3,605.59 3,302.09 436.24 -1,074.81 2,622,106.11 284,759.82 0.71 1,155.86 MWD(2) 3,883.19 27.96 294.01 3,633.32 3,329.82 442.23 -1,088.32 2,622,112.10 284,746.31 0.64 1,170.62 MWD(2) 3,914.64 27.98 293.65 3,661.10 3,357.60 448.19 -1,101.81 2,622,118.06 284,732.81 0.54 1,185.35 MWD(2) 3,946.08 28.07 294.28 3,688.85 3,385.35 454.19 -1,115.31 2,622,124.06 284,719.32 0.98 1,200.11 MWD(2) 3,977.52 27.99 293.56 3,716.61 3,413.11 460.18 -1,128.81 2,622,130.05 284,705.81 1.11 1,214.86 MWD(2) 4,008.93 28.03 293.89 3,744.34 3,440.84 466.12 -1,142.32 2,622,135.98 284,692.31 0.51 1,229.59 MWD(2) 4,040.43 28.02 294.24 3,772.14 3,468.64 472.15 -1,155.83 2,622,142.02 284,678.79 0.52 1,244.37 MWD(2) 4,071.84 27.93 294.27 3,799.88 3,496.38 478.20 -1,169.26 2,622,148.07 284,665.36 0.29 1,259.09 MWD(2) 4,103.29 27.75 294.62 3,827.69 3,524.19 484.28 -1,182.64 2,622,154.15 284,651.99 0.77 1,273.76 MWD(2) 4,134.76 27.66 294.64 3,855.55 3,552.05 490.38 -1,195.94 2,622,160.25 284,638.69 0.29 1,288.38 MWD(2) 4,166.21 27.67 293.98 3,883.41 3,579.91 496.39 -1,209.24 2,622,166.26 284,625.39 0.97 1,302.97 MWD(2) 4,197.65 27.73 294.17 3,911.25 3,607.75 502.35 -1,222.59 2,622,172.22 284,612.04 0.34 1,317.57 MWD(2) 4,228.99 27.80 294.56 3,938.98 3,635.48 508.38 -1,235.88 2,622,178.24 284,598.74 0.62 1,332.15 MWD(2) 4,260.50 27.74 294.96 3,966.86 3,663.36 514.52 -1,249.22 2,622,184.39 284,585.41 0.62 1,346.82 MWD(2) 4,291.92 27.72 294.36 3,994.67 3,691.17 520.62 -1,262.50 2,622,190.49 284,572.13 0.89 1,361.43 MWD(2) 4,323.44 27.36 293.98 4,022.62 3,719.12 526.59 -1,275.80 2,622,196.46 284,558.83 1.27 1,375.99 MWD(2) 4,354.83 27.25 293.61 4,050.51 3,747.01 532.40 -1,288.97 2,622,202.27 284,545.66 0.64 1,390.37 MWD(2) 11/16/2011 9:48:44AM Page 5 COMPASS 2003.16 Build 71 • • Halliburton Company Definitive Survey Report Company: Aurora Gas,LLC ° Well TMCU#3 Project: Cook Inlet k$; TMCU#3 081611 @ 303.50ft(287.5+16) Site: Three Mile Creek Unit MD*tetitincii TMCU#3 081611 @ 303.50ft(287.5+16) Well: TMCU#3 North Reference: Grid Wellbore: TMCU#3 Survey Calculation Method: Minimum Curvature Design: TMCU#3 Database: .Sperry EDM.16 PRD Survey MD Inc Azi ND TVDSS Section '14 (ft) (`) ('} (ft) (ft) ' $ 3 3 (ft} Survey Tool Name 4,386.27 27.21 294.27 4,078.47 3,774.97 538.24 -1,302.12 2,622,208.10 284,532.51 0.97 1,404.73 MWD(2) 4,417.82 27.27 294.51 4,106.52 3,803.02 544.20 -1,315.27 2,622,214.07 284,519.36 0.40 1,419.16 MWD(2) 4,449.31 27.10 294.47 4,134.53 3,831.03 550.17 -1,328.37 2,622,220.03 284,506.27 0.54 1,433.53 MWD(2) 4,480.73 26.90 294.50 4,162.52 3,859.02 556.08 -1,341.35 2,622,225.94 284,493.29 0.64 1,447.78 MWD(2) 4,512.19 26.83 294.64 4,190.59 3,887.09 561.99 -1,354.28 2,622,231.85 284,480.36 0.30 1,461.99 MWD(2) 4,543.62 26.87 294.25 4,218.63 3,915.13 567.86 -1,367.20 2,622,237.73 284,467.43 0.57 1,476.17 MWD(2) 4,574.89 26.89 295.29 4,246.52 3,943.02 573.79 -1,380.04 2,622,243.65 284,454.60 1.51 1,490.30 MWD(2) 4,606.37 26.86 295.04 4,274.60 3,971.10 579.84 -1,392.92 2,622,249.70 284,441.72 0.37 1,504.52 MWD(2) 4,637.83 26.87 293.66 4,302.67 3,999.17 585.70 -1,405.87 2,622,255.56 284,428.77 1.98 1,518.72 MWD(2) 4,669.79 26.79 293.06 4,331.19 4,027.69 591.42 -1,419.11 2,622,261.28 284,415.53 0.88 1,533.12 MWD(2) 4,700.71 26.63 293.60 4,358.81 4,055.31 596.92 -1,431.87 2,622,266.78 284,402.77 0.94 1,546.99 MWD(2) 4,732.16 26.49 293.95 4,386.94 4,083.44 602.59 -1,444.74 2,622,272.45 284,389.90 0.67 1,561.03 MWD(2) 4,763.59 26.25 293.92 4,415.10 4,111.60 608.25 -1,457.50 2,622,278.12 284,377.14 0.76 1,574.97 MWD(2) 4,795.01 26.15 294.15 4,443.29 4,139.79 613.90 -1,470.17 2,622,283.77 284,364.47 0.45 1,588.83 MWD(2) 4,826.46 26.09 294.82 4,471.53 4,168.03 619.64 -1,482.77 2,622,289.50 284,351.87 0.96 1,602.66 MWD(2) 4,857.87 26.14 294.60 4,499.73 4,196.23 625.42 -1,495.33 2,622,295.28 284,339.31 0.35 1,616.48 MWD(2) 4,889.29 26.15 294.92 4,527.94 4,224.44 631.22 -1,507.90 2,622,301.08 284,326.74 0.45 1,630.31 MWD(2) 4,920.77 26.02 294.50 4,556.21 4,252.71 637.01 -1,520.48 2,622,306.87 284,314.17 0.72 1,644.15 MWD(2) 4,952.23 25.93 295.04 4,584.49 4,280.99 642.78 -1,532.99 2,622,312.64 284,301.66 0.80 1,657.91 MWD(2) 4,983.50 25.79 295.04 4,612.63 4,309.13 648.55 -1,545.35 2,622,318.41 284,289.30 0.45 1,671.55 MWD(2) 5,014.97 25.75 294.89 4,640.97 4,337.47 654.33 -1,557.75 2,622,324.19 284,276.90 0.24 1,685.22 MWD(2) 5,046.46 25.78 295.44 4,669.33 4,365.83 660.15 -1,570.14 2,622,330.01 284,264.51 0.77 1,698.90 MWD(2) 5,142.00 25.78 295.44 4,755.36 4,451.86 678.00 -1,607.66 2,622,347.85 284,226.99 0.00 1,740.44 PROJECTED to TD 11/16/2011 9:48:44AM Page 6 COMPASS 2003.16 Build 71 Three Mile Creek #3 iiii Be m Drilling 12 1/ SDL Crew Arrived i 11 1111 lill g' g 4"Section 1--i ��� 11111 TD 12 1/4"Surface Hole"Ill 11111111 * : 897r9o!!np lillill11111111 r, 1000NI - 111111.1 ' ' 111111OOH IIIPSiellit 915111/8A"CasingBegin Drilling 8850',660'TVD 1111 8 1/2" Section 177.7.:- -� R > LOT to 16.2 ppg 7 Oct 2011 @ 13:46 EMII i1111111111.1111!WI 1 2000 End of Run 300 1111111/1111 II ,10!11!2011 II 111 Drill to 3009,POOH@17:30 for Bit Trip -C a Iii Start Run 400 Q � 10/13/2011 @ 06:40 i iffiil11111111111111 111 II 11MI I II CD _ I ) I L 3000 U) RS 41) milimilitrimuummi 1 11111 111111i11111111111111111111111111111111111111111111111 TD Well 111111 '5142'MD,4755.44'ND III 1111111 maw4000iiimair On 10:01 ,18-Oct-2011 CBU,Short Trip to shoe IIIIIIIId 111111111 II ' POOH,R/U and Run E-LogsLogs. II in No go,Pull Out and RIH to clean hole. Ilona �-` kr111111111111111/1 Run E-Logs Jul € No I I iiiii zip Run 5 1 "production 5000 liner.and cement On 10/20(2011 @ 11:42 111116. Drill extra 15'for Casing. Off Location1112t2011 From 5142'MD to 5157'MD 1111111111=1111111111111111 ' 6000 1 1 l Rig Days HALLIBURTON Sperry Drilling Surface Data Logging After Action Review Employee Name: Mark Lindloff Date: 11/3/2011 Well: TMC #3 Hole Section: Production What went as, or better than, planned: Three Mile Creek Unit 3 went very well for the mudloggers. Phone communications was 100% better making it easier to contact resources and resolve issues as they arose. Difficulties experienced: None. Recommendations: Maybe put some thought on how we can track depth better. Innovations and/or cost savings: Saved Aurora thousands of dollars by providing rig monitor service therefore Aurora did not have to purchase a stand alone monitoring system. Guhl, Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Tuesday, March 31, 2015 11:26 AM To: George Pollock Cc: Bettis, Patricia K(DOA) Subject: Three Mile Creek 3, PTD 211-071, Data required George, During the final compliance review for Three Mile CK 3, PTD 211-071,completed 10/27/2011, 10-407 report received 8/4/2014, I noted that two paper items are required for the well to be in compliance: 1. A copy of the Halliburton EOW mudlogging report 2. A copy of the directional survey Please provide the two paper items listed above to the AOGCC, sent to my attention, by April 13, 2015. If you have any questions, please contact me. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W.7th Ave,Suite 100,Anchorage,AK 99501 meredith.guhl@alaska.gov Direct: (907)793-1235 CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information. The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. 1 Schwartz. Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Wednesday,August 06, 2014 2:17 PM To: 'George Pollock' Subject: RE:Three Mile Creek#3 (PTD 211-071) Thanks for quick turnaround. There is a USIT for the production casing so not as critical. .... But send me the vendor report when you get it anyway. I'll look at the daily report again and see if that will suffice for flowback info. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at (907-793-1226) or(Guv.schwartz@alaska.gov). From: George Pollock (mailto:gpollock@aurorapower.com] Sent: Wednesday, August 06, 2014 1:54 PM To: Schwartz, Guy L(DOA) Cc: McMains, Stephen E (DOA) (steve.mcmains(aalaska.gov); Guhl, Meredith D (DOA) Subject: RE: Three Mile Creek #3 (PTD 211-071) Guy, I have attached the frac report and the surface cement report. I do not have an electronic version of the production casing cement report. I have requested that from the vendor and will forward when it arrives. Should be within a day or so. Unfortunately,there is not much to summarize on the flowback. A total of 629 barrels were flowed back out of 10,000 barrels injected. The full details have been presented in the summary on the last two pages. George Pollock Manager, Production Operations as Engineering Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 (907) 277-1003 Main (907) 351-8286 Cell 1 From: Schwartz, Guy L(DOA) [mailto.yuy.schwartz@)alaska.gov] Sent: Wednesday, August 06, 2014 11:58 AM To: George Pollock Cc: McMains, Stephen E (DOA) (steve.mcmains(aalaska.gov); Guhl, Meredith D (DOA) Subject: Three Mile Creek #3 (PTD 211-071) George, I have the 10-407 in hand..could you please send the vendor cementing and hydraulic frac reports. Also, do you have some kind of summary sheet for the flowback? Guy Schwartz Senior Petroleum Engineer AOGCC 7- -4 90 301 533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226)or(Guy.schwartz@alaska.gov). 2 CEMENT JOB REPORT , JJ CUSTOMER AURORA GAS INC DATE 03-OCT-11 F.R.# 1001857059 SERV.SUPV. CECIL J JONES LEASE&WELL NAME LOCATION COUNTY-PARISH-BLOCK THREE MILE CREEK#3-API 50283201560000 34-13N-11W Tyonek Alaska DISTRICT DRILLING CONTRACTOR RIG# TYPE OF JOB Kenai Surtax:, SIZE&TYPE OF PLUGS LIST-CSG-HARDWARE I PHYSICAL SLURRY PROPERTIES Cement Plug,Rubber,Top 9-5/8 in Float Collar 9-5/8-8rd SACKS SLURRY SLURRY WATER PUMP Bbl Bbl OF WGT YLD GPS TIME SLURRY MIX Cement Plug, Rubber,Bottom 9-5/8 Float Shoe 9-5/8-8rd 1 CEMENT ppG FT3 HR:MIN WATER MATERIALS FURNISHED BY BJ Seal Bond12 20 Type I 417 14.5 1.50 7.08 04:13 111.4; 70.18 Mud 10{ 65.5; Available Mix Water 90 Bbl. Available Displ.Fluid 70 Bbl. TOTAL ( 196.91 70.18 HOLE TBG-CSG-D.P. COLLAR DEPTHS SIZE %EXCESS DEPTH SIZE WGT. TYPE 1 DEPTH GRADE SHOE II FLOAT STAGE 12.25 100 900 9.625 36 CSG 8851J-55 885 85 1 `` LAST CASING PKR-CMT RET-BR PL-IJNER PERF.DEPTH TOP CONN WELL FLUID SIZE WGT TYPE DEPTH BRAND&TYPEDEPTH ; TOP BTM SIZE THREAD TYPE WGT. 13.38 72ICSG 93 No packer 01 0 0 9 625 8RND WATER BASED ML 10 DISPL VOLUME DISPL.FLUID CAL.PSI (CAL.MAX PSI OP.MAXI MAX TBG PSI MAX CSG PSI MIX VOLUME UOM TYPE WGT. I BUMP PLUG' TO REV. SQ.PSI RATED I Operator I RATED Operator WATER 65.5 BBLS Mud 10 168 0 0 0 0 3520 2816 vacuum truck EXPLANATION:TROUBLE SETTING TOOL,RUNNING CSG,ETC.PRIOR TO CEMENTING: Rig Intended TD was in coal bed-drill ahead to 900ft l difficulty runn ing casing. PRESSURE/RATE DETAIL EXPLANATION TIME 1 PRESSURE-PSI I RATE 1 BbI.FLUIDFLUID SAFETY MEETING: BJ CREW PX I CO.REP. I X, HR:MIN. I PIPE I ANNULUS BPM PUMPED I TYPE TEST LINES 2050 PSI CIRCULATING WELL - RIG I X I BJ 09 30 I Leave Redskii airport.(Oct 1,11 w/crew C. Jones,J. Baldwin,J. Wellborn,J.Cress,J.Naga) 10.00 1 Arrive Shirliyville. 10:20 I I Arrive Beluga.Get in truck and drive to Moquawkie to retrieve pump unit L C873. I — — 11:42 1 _ Arrive 3 Mile Creek location. _ 11:45 I I I I Speak to company man Garry Gorelic concerning spotting equipment, well status,etc. 11:52 I III 1 Hold safety meeting regarding moving/spotting units. 12:07 I I I Spot cmt pump and confirm with trucking superintendent where to spot sacksavers. 12:18Leave location for Beluga camp to check in and grab bite to eat. I i 13:25 I I Return to location,hold rig up meeting and walk location with crew to familurize ourselves with hazards. 13:32 I 1 1 T —1 !Rig up water line,steel line,washup line,sack saver 2 w/sweep.Did not rig up bulk truck at this time to avoid blocking entrance to location. 16:20 I I I I I I Prime pump truck,test mixing system and do internal pressure test to confirm truck is holding pressure. 16:30 I I — I Asked company man Garry if he would like to run both plugs and would like to watch us load the head. 16:3.5 i1 I Company man Garry witness loading of head with BOTTOM plug. I 1 I I Drilling continues as intended TD point is in coal bed. Desision made to drill til exiting coal bed. I I 1 Company man express concern over sufficient quantity of cmt on location.(340sks orginally called for out of possiable 417sks) Disision made to run 417 sks or 111.6 bbl 14.5 cmt. 02:30 I (Oct 2)Return to camp. - Lai; CEMENT JOB REPORT j1 PRESSURE/RATE DETAIL EXPLANATION TIME • PRESSURE-PSI RATE Bbl.FLUID FLUID SAFETY MEETING: BJ CREW I X I CO.REP. X HR:MIN. PIPE ANNULUS _ BPM PUMPED TYPE TEST LINES 2050 PSI J 1 CIRCULATING WELL - RIG LX_I BJ 07:30 j Leave camp for rig to check progress 08:00 Check in with rig. Will start running casing in 30-60 minutes 08:15 . Leave loc for camp. 08:55 '11Arrive camp 15:00 al 11111111111Leave camp to check progress 15:35 Arrive location. Three joints in hole. Company man Garry said He intended to call in hours,might as well stay. 17:30Start up cmt pump to warm up,pre stage bulk truck. 20:00 Y Rig up stand pipe and circulation iron/Rig circulate till hole conditioned 20:30 Hold pre-job safety meeting with BHI,Vacuum truck, Rig crews and company man 20:50 Rig down swedge and rig up 9 5/8 inch cement head,hook up circl iron. Turn well over to BHI Pressure Pumping. ***START SURFACE JOB*** 21:09 83 0 2.7 2 7 WATER Prime lines/break circl I drop bottom plug with 3 bbl fresh water 21:10 18 0 0 2 7 WATER Shut in head and reload with top plug 21:19 2057 0 0 3 WATER Test lines @ 2000psi. Hold for 5 minutes. Lost PSI test good 21:23 I 1836 0 0 I_ 3 WATER Bleed off pressure 1 open bottom valve on head manifold. 21:28 I — 18 0 0 1— _ 31 SPR Batch up spacer @ 12 ppg 21:36 i 63 0 1.4 1 3 8' SPR Start down hole w/spacer 21:39 127_ 0 2 6 1 10 1 SPR 10 bbl spr away 21:43 64 0 2 _ 19.7 SPR 20 bbl spr away 21:43 25 0 0 ! 19.7 SPR Shut down and batch up CMT @ 14.5ppg 21:56 67 0 1 6 20.7 CMT Start down hole w/CMT 21:57 227 0 3 9 30 4 CMT 10 bbl cmt away 22:00 264 0 4 40.8 CMT 20 bbl cmt away 22:03 206 0 3 5 50.2 CMT 30 bbl cmt away 22:05 276 0 4 7 _ 59.7 CMT 40 bbl cmt away 22:07 165 0 _ 4.5 71.1 CMT_ 50 bbl cmt away 22:10 145 01 4.4 80.2 CMT 60 bbl cmt away 22:12 196 0 I 4.7 L 99.4 CMT 70 bbl cmt away 22:14 300 0 4.6 I 109 CMT 80 bbl cmt away 22:17 390 0 4.8 1 111 CMT 90 bbl cmt away 22:23 125 0 1 3 128.5 CMT 108 bbl cmt away out of mix water. 22:28 65 0 0 128 CMT Shut down 22:28 65 0 0 1 128 MUD close bottom valve open top valve on head I pick up WBM to displace with. 22.33 T 21 01 3 1281 MUD Drop Top Plug @ 3bpm. only able to pull mud on @ just over 3bpm from vac truck. 22:36 2291 0 _ 3 I 139' MUD 10 bbl displacement away 22:40 2321 0 _- 31 149 MUD 20 bbl displacement away 22:43 , 269 0 3 159.41 MUD i 30 bbl displacement away 22:47 320 0 3 170 jMUD - j 40 bbl displacement away 22:50—n— 350 0 3 179.31 MUD displacement bbl dis lacement awaY - — _ 22:51 303 0 3 184.4 MUD 155 bbl displacement away/slow down to 2 bpm for last 10 bbl 22:54 309 0 2 1 189 MUD 160 bbl displacement away 22:55 • 347 0 2 1 191.4 MUD 62 bbl displacement away/displacement to float 22:56 1 352 0 2 I 194.4 MUD 65 bbl displacement away/shut down/did not bump _ _ 22:59 I 169 0 0 1 194.4 MUD Speak with company man,pick up extra water. 23:03 1 310 0 1 195 MUD Pump final 1/2 bbl attempting to bump plug. CEMENT JOB REPORT L - , PRESSURE/RATE DETAIL EXPLANATION TIME PRESSURE-PSI RATE Bbl.FLUID FLUID SAFETY MEETING: BJ CREW X CO.REP. X IIR:MIN. I PIPE ANNULUS BPM PUMPED TYPE TEST LINES 2050 PSI CIRCULATING WELL - RIG X BJ 23:03 _J 203 0 0 1951 MUD I Shut down/did not bump. shut in valve at head. 23:05 205 0 0 195 MUD I Speak with company man. Get ok to knock loose and wash up 23:13 J 0 0 0 ! 195 MUD Hold post job w/crew and vac truck driver. 23:20 __ I Wash up truck and prepare for possiable top out. 01:27 ' I Released by company man. PSI TO TEST T BBL.CMT OTAL PSI SPOT BUMPED BUMP FLOAT ,. RETURNS! BBL. LEFT ON TOP OUT SERVICE SUPERVISOR SIGNATURE: PLUG PLUG EQUIP. ; REVERSED PUMPED CSG CEMENT Y N 1400 Y N '30 195 205 V Nr— rt1�_. d (6dd) (Alen) xnd s N O LO O o r c If) O y -T I I i i I I , ,` 1� I , , , I c (isd) Zssaad I o 0 0 0 `° 0 0 0 Ir- CD Coco ON O p0 CN cn 0 o tu o n CO C u c O - c m75 co 0 co w 0 2 N N 0 V = v■.. -0p O a N �- 0L `' '. -. r' Lift __cn J_I ____ -o a, - f_ o w ` J �O _ c a. o `,� w N V .._ sCD7 E co Z toc' L 0) w o P. ` coCD i< a a 00 ._ L.. N01 U ` ) —._. - -c ~ o0 0 Ci SI co o m _ _ NOQti 0 - m 0 p. d — — 1 IEEE QOin O 4:2y ? (wdq) Z+� nnolA -- I L—_-_l 0 0 0 0 0 0cu 34 M N ( isd) I. ssaad 0 r CEMENT JOB REPORT ri.( • 1 CUSTOMER AURORA GAS INC DATE 24-OCT 11 F.R.# 1001662566 SERV.SUPV. David Waanptord LEASE&WELL NAME LOCATION COUNTY-PARISH-BLOC( THREE MILE CREEK 03-API 50283201560000 34-13N-11W Tyonek Alaska DISTRICT DRILLING CONTRACTOR RIOT TYPE OF JOB NUPora n Shi SlIZE &TYPE OF PLUGS 1 LIST-CMG-HARDWARE I PHYSICAL SLURRY PROPEf;j7ES Cement Plug,Rubber,Top 5-1/2 in Float Shoe 5-1/2 8rd SACKS SLURRY SLURRY WATER PUMP ' Bbl Bbl OF WGT YLD GPS TIME I SLURRY MIX Cement Plug,Rubber,Bottom 5-1/2 CEMENT ppG FT3 1 HR:MIN j WATER MATERIALS FURNISHED BY BJ j Seal Bond Spacer I 11 5 40' Clean Brine 9 2 119 82 12 ppg Lead 178 12i 2.83 16.46 89 61 69.78 14.8 Tail Cement 710, 14,8 1.35I 6.26 170 91 105.83 Available Mix Water 300 Bbl. Available Okapi.Fluid 150 Bbl. TOTAL I 420.351 175.61 HOLE 1 TBG-CSG-D.P. COLLAR DEPTHS "" SIZE 19L EXCESS DEPTH SIE i WGT. TYPE DEPTH i GRADE ' SHOE FLOAT ST AGE 8.5 5115 5.5 15,5 CSG 5115 LAST CASING_ PKR-CMT RET-BR PL-UNER I PERE.DEPTH 1 TOP CONN I WELL FLUID SIZE War_ TYPE DEPTH IRMO&TYPE DEPTH TOP . BTM SIZE THREAD I — WGT 9.625 36 800 5 1 8 RND WATER BASED ML 9 5 DISPL VOLUME DISPL FLUE i CAL PSI ,CAL MAX PSI OP.MAX . MAX TBG PSI MAX CSG PSI MIX - — WATER VOLUME UOM TYPE WGT. BUMP PLUG TO REV. 1 SQ.PSI RATED Operator RATED Operator 119.8 BBLS Clean Brine 9.2 Fresh EXPLANATION:TROUBLE SETTING TOOL,RUNNING CSG,ETC.PRIOR TO CEMENTING: PRESINNIVRATE DETAIL EXPLANATION TIME PRESSURE.;PSI RATE Bbl.FLUID FLUID SAFETY MEETING: B.1 CREW X CO.REP. X HR:MIN. RPM PUMPED TYPE '_ PIPE. ANNULUS ' TEST LINES 3100 PSI CIRCULATING WELL - RIG X BJ 08:00 I I Flew to location.Harold,James,Marcus,Jordan,David Tested Van 2 to 4000 during prime up. 19.00Safety Meeting 20:41 2 WATER Fill Lines 2043 31_00 ,Test Lines PLUG I Drop first plug 1 WATER I Kick plug out — 1 Reload next plug 20:58 - SWEEP .Start Sweep 21:12 46 SWEEP end of Sweep ..1 -- —^ Batch Tail Swum/ 21:16 I I — i LEAD Start lead — 21:30 98 3.6 i 50 21 40 1, 89 End of Lead,Start Tail — 2150 1041 ! 4 L 40 TAIL 22.18 1621 5.3 L 187 TAIL End of Tail — 22 19 I I PLUG Drop Plug —� ,�_ 22:20 1_ 5 WATER Kick out plug Tum over to rig to disp with Brine Bumped Plug,some cement to surface PM TO TEST BBLCMT TOTAL ! PSI SPOT SERVICE SUPERVISOR SIGNATURE: BUMPED BUMP FLOAT RETURNS! BBL LEFT ON TOP OUT PLUG PLUG I EQUIP. I REVERSED PUMPED CSG CEMENT Y N 700 Y j N 5 i 335 0 Y N CD Ryon Pomo]e,. OCT.xs,,00.2O3 Page 1 ,►1014 r- (Bdd) (A18a) xnd (wdq) Z+I. mold , N 0 . CNI �n o CVV'''. N"'" O O rn e-- 0 i. G = 0 C 45 O 0 y j Y aC) V IW Y � c CD la„..... ...,- .,_ �ige �...----- _. W N 1 ji: _) \IN ,c:, v... c lk ______ +ft tate — ��7 ,. _ 1I c L 1 CL Co [ . "a it 0 o ID Ista 13 .5.‘,"---- "'"-- _ 03 _ _of C 14J, C1 L.....7- _ 1 o (7in In Zto °a Ocn CU — '� .-a) . m � F fig , m m '� V3 0 I O O O O O CO 0 0 0 0 0 LO NI- (lsd) ISd IIeM Z sseAdp 13 (Isd) ISd dwnd I. ssaadEco )st Coast Area Laboratory Repo( BAKER HUGHES Resort#: CMT053411 B Client/Well Information: Company: Aurora District: Kenai Depth MD: 5100 Field: Three Mile Creek Job Type: Production Depth TVD: 5100 Well: #3 Hole Size: 7.875 BHST: 79.92 Prepared for: Ed Jones Casing Size: 5.5" BHCT 90 Submitted by: Joshua Herald Cement: Type I Water: Fresh Water- Tap Tested b : Joshua Doom Lot#: Date: 8/30/11 Slurry Design: Static Free 0.05 % BWOC A-9 (KCI) 2 % BWOW Base 1 Type I 1 100 I % FP-6L _ 1 9al/100sacl A-2 (SMS) 0.3 % BWOC Additives FL-63 0.1 % BWOC ASA-301 0.1 % BWOC BA-10 0.4 % BWOC MPA-1 20 % BWOC CD-32 0.3 % BWOC Slurry Properties: Density: 12 ppg Yield: 2.83 ft3/sack Mix Water: 16.439 gal/sack Rheology: 600 rpm 300 rpm 200 rpm 100 rpm 6 rpm 3 rpm PV YP Bingham Ambient Plastic 90 39 30 28 24 15 14 9 21 Gel ' 10 sec 10 min 100 lb/sqft 500 Ib/sgft Free Water: 90 deg 0.64 Strength Fluid Loss: 787 cc/30min Consistometer Recording of Bearden Consistency(Time is in hrs:min): Machine: Ace 30 bc: 50 bc: 70 bc: 4:43 100 bc: 400 1 100 360- 90 320-' - 70 _ 280- _ 60 tC 240_ g 50 200; 1 40 .. 160- 30 _ - ,._ I120 Q ..._ _ I BO --1 0 -20 0-00 1:00 2:00 3:00 4:00 .... -1-5-no(1-61:506/8 Compressive Strength Data: Temp 8:16 36:38:00 8 hr 12 hr 24 hr 48 hr 72 hr 96 hr 80 1 F 50 psi 500 psi 109 301 662 899 400- 20- 2000- 360- 18- 1800-' -- -- 320— 16- 1600 ---- - - 280- 5{14- 1400-- _ -- - - X240- 12- £1200 - - _ fip¢ -I} 200- O 10- 1000= Ft _----V F 160_ 1 8- 800= f 120- I, 6- 600- V 80- 4- 400-_--------- --__. _. --__. _._- 40- 2 7 200- 0 0 0 ' 0 18 36 54 z[ TOe 08-0 Comments: Notice:This report is presented good faith based upon present day technology and information provided:but because of variable conditions and other information which must be relied upon,BJ Services makes no warranty,express or implied,as to the accuracy of the data or of any calculations or opinons expressed herein. You agree that BJ Services shall not be liable for any loss or damage,whether due to negligence or otherwise,arising out of or in connection with such data,calculations,or opinons. %..._ 9st Coast Area Laboratory Repor BAKER HUGHES Re.ort#: CMT053511 E Client/Well Information: Company: Aurora District: Kenai Depth MD: 5100 Field: Three Mile Creek Job Type: Production Depth TVD: 5100 Well: #3 Hole Size: 7.875 BHST: 113 Prepared for: Ed Jones Casing Size: 5.5" BHCT 90 Submitted by: Joshua Herald Cement: Type I Water: Fresh Water- Tap Tested b : Joshua Herald Lot#: Date: 8/30/11 Slurry Design: Static Free 0.05 % BWOC A-9 (KCI) 2 % BWOW Base i Type I 100 I % FP-6L 1 ,gal/100sack A-2 (SMS) 0.3 % BWOC Additives R-3 0.1 % BWOC BA-10 1 % BWOC CD-32 1 % BWOC Slurry Properties: Density: 14.8 ppg Yield: 1.35 ft3/sack Mix Water: 6.254 gal/sack Rheology: 600 rpm 300 rpm 200 rpm 100 rpm 6 rpm 3 rpm PV YP Bingham Ambient Plastic 90 144 81 56 30 3 2 77 5 Gel 10 sec 10 min 100 lb/sqft 500 lb/sqft Free Water: 90 deg 0 Strength Fluid Loss: 10 cc/30min Consistometer Recording of Bearden Consistency(Time is in hrs:min): Machine: Sponge 30 bc: 50 bc: 70 bc: 3:48 100 bc: 600 , 40000-- 100 540'— 36000 H. 90 480 - 32000— 80—' 420- 28000- 70 - _ .. _ _ ._ - - -_. _- - - _ E 360 1 24000- g 60 300_ i 20000 H. - -" I-240- }1'II�.� 16000- I 40-- w -- - "' {. 180 1 12000- aS 30 1 120- I 8000— �I" 20—10 -_ _ _ .. TTTT 0:00 0330 1:00 1:30 2:00 2:30 3:00 3:30 4:00 ' Tyre(H1-1:1VTd) Compressive Strength Data: Temp 3:12 6:46 8 hr 12 hr 24 hr 48 hr 72 hr 96 hr 113 I F 50 psi 500 psi 770 1362 2148 2414 2642 4007 207 60007 ',I 360— 18— 4500 320— 16— 4000_ 280— 14— ^^^^6$6$63$p3500__. 6 240- 12- 3000 \ 1* 200j.10- 2500 7: `,-.. _. - 4',. JI-160— 1 8_ E 2000-__. ___ ........ _. _ _. __ .. y 120 F 8= (f 1500 ____— _ _____ _ _' __.__ _. _.____. _.fes— _ _. 80 T 4 7 1000 0 18 36 54 72 Trne(HI-0 Comments: Notice:This report is presented good faith based upon present day technology and information provided:but because of variable conditions and other information which must be relied upon,BJ Services makes no warranty,express or implied,as to the accuracy of the data or of any calculations or opinons expressed herein. You agree that BJ Services shall not be liable for any loss or damage,whether due to negligence or otherwise,arising out of or in connection with such data,calculations,or opinons. VA/ vv••av�.•s vvY/s1�i.71.Gi 1 1'4./W1 Q111 V GI Q01110111 J.VV Job Number ' c # Customer Au Gas Inc .-4:,''-;t1''". Well Name: Three Mile Creek#3 • Time Elapsed Press Press Flow F1+F2 Fl+F2 Aux of Time 1 2 1+2 Total Stage (DBIV) Day Pump Well (bpm) (bbl) (bbl) (ppg) PSI PSI (psi) (psi) Monday, October 24. 2011 20:38:15 0:00:00:00 0 0 0.0 0 0 0.0 0.00 20 38.45 0:00'00:30 0 1 0.0 0 0 0.0 0.00 20:39:16 0:00.01:01 1 0 0.0 0.0 0.0 0.00 20:39.47 0:00 01:32 0 0 0.0 0.0 0.0 0.00 20:40:17 0:00:02:02 0 0 0.0 0.0 0.0 0.00 20:40:47 0:00.02:32 1 2 1 1 0 1 0.1 0.00 _ 20'41:17 0:00 03:02 217 188 1.3 1.0 1.0 0.00 20:41:47 0:00:03:32 224 217 1.3 1.6 1.6 0.00 20:42:18 0:00:04:03 92 87 0.0 1.9 1.9 0.00 20:42:48 0:00 04:33 82 81 0.0 1.9 1.9 0.00 20:43-18 0:00.05:03 82 82 0 0 1.9 1.9 0.00 20:43:48 0:00.05:33 634 665 0 0 1 9 1.9 0.00 1. 20:44:18 0:00 06:03 3027 3073 0.0 1 9 1.9 0.00 1 20:44:48 0:00 06:33 2996 3027 0.0 1.9 1.9 0.00 20:45:18 0:00:07:03 2979 3005 0.0 1.9 1.9 0.00 20:45:48 0:00'07:33 1826 1837 0,0 1.9 1.9 0.00 1\'"� 20:46'18 0:00:08:03 0 0 0.0 1.9 1.9 0.00 L 20:46'48 0 00:08:33 64 69 0 0 1.9 1.9 0.00 20:47:18 0.00:09:03 210 225 1.0 2.3 2.3 0.00 �p „.ta 20:47:48 0:00:09:33 197 208 1.0 2 8 2.8 0.00 Y" 20:48:18 0:00:10:03 0 2 0 0 2.9 2.9 0.00 20:48.48 0:00:10:33 0 0 0 0 2 9 2.9 0.00 20:49:18 0.00:11:03 0 0 0.0 2.9 2.9 0.00 20:49:49 0:00:11:34 0 0 0.0 2.9 2.9 0.00 20:50:20 0.00:12:05 0 0 0.0 2.9 2.9 0.00 20 50:51 0:00:12:36 0 0 0.0 2.9 2.9 0.00 20.51:22 0'00:13:07 0 0 0 0 2.9 2.9 0 00 20.51:53 0.00:13:38 1 0 0.0 2.9 2.9 0.00 20:52:24 0:00:14:09 2 0 0.0 2.9 2.9 0.00 20.52:55 0:00:14:40 2 1 0.0 2.9 2.9 0.00 20.53:26 0:00:15:11 2 1 0.0 2.9 2.9 0.00 20 53:57 0: 0:15: 0 42 1 0 0 0 2.9 0.0 0.00 20.54:27 0:00:16:12 2 2 0.0 2.9 0.0 0.00 20 54:57 000:16:42 2 2 0.0 2.9 0.0 8.83 20 55:27 0.00:17:12 3 0 0.0 2.9 0.0 9.22 20.55:57 0 00:17:42 3 1 0.0 2.9 0.0 9.28 20 56:27 0 00:18:12 1 1 0.0 2.9 0.0 9 31 20:56:57 0:00:18:42 4 2 0.0 2.9 0.0 9.38 2057:27 0:00:19:12 2 1 0.0 2.9 0.0 9.44 257:57 0:00:19:42 2 1 0.0 2.9 0.0 14.80 20:58:27 0:00:20:12 2 0 0.0 2.9 0.0 14.80 20.58 57 0:00:20:42 194 207 1 1 3 4 0,5 15.80 20 59:27 0'00:21:12 210 210 1.1 3.9 1.0 14.70 20:59:57 0 00:21:42 198 201 1.1 4.5 1.6 13.30 21:00:27 0:00:22:12 400 392 4.5 6.6 3.6 12.70 21:00:57 0:00:22 42 368 361 4.5 8.8 5.8 11.60 21.01:27 0.00:23:12 316 321 4.6 11.2 8 3 11.30 21-01:57 0 00:23.42 299 294 4.1 13.2 10.3 10.90 21 02:27 0:00:24:12 326 323 4.0 15.3 12.4 11.10 21:02:57 0'00:24:42 279 273 3 8 17.2 14.3 11.40 21:03:27 0.00:25.12 265 260 3 6 19.0 16.1 11.40 BJ Services Job Start Monday, October 24, 2011 y a" ` vv v.., v ova... vvY :Ga . • . Ot. I •WWI ULM V GI OI VU J.JU 1 Job Number: Customer Au. Gas Inc Well Name: Three Mile Creek k3 Time Elapsed Press Press Flow F1+F2 F1+F2 Aux of Time 1 2 1+2 Total Stage (DBIV) Day Pump Well (bpm) (bbl) (bbl) (ppg) PSI PSI (psi) (psi) Monday, October 24,2011 21:03:57 0:00:25.42 274 267 3.6 20.8 17.9 11.30 21:04:27 0:00:26:12 260 248 3.3 22.6 19.7 11.40 21:04:57 0:00:26:42 258 243 3.3 24.2 21.3 10.90 21:05:27 0:00:27:12 261 245 3.6 25.9 23.0 10.30 21:05:57 0:00:27:42 273 255 3.7 27.8 24.9 11.00 21:06:27 0:00:28:12 269 243 3.7 29.7 26.8 10.80 21:06:57 0:00:28:42 277 252 3.2 31.4 28.5 11.20 21:07:27 0:00:29:12 210 188 2.7 32.9 30.0 11.90 21:07:57 0:00:29:42 297 277 4.2 34.4 31.5 11.40 21:08:27 0:00:30:12 277 248 4.3 36.6 33.6 11,20 21:08:57 0:00:30.42 260 229 3.7 38.5 35.5 11.50 21:09:27 0:00:31:12 189 155 2.9 40.1 37.2 11.30 21:09:57 0:00:31:42 171 139 2.7 41.5 38.6 11.40 �aA 21:10:28 0:00:32:13 259 228 4.2 43.1 40.2 10.80 �J 21:10:59 0:00:32:44 163 114 2.8 44.9 42.0 12.30 9 21:11:30 0:00:33:15 208 242 5.2 47.3 44.3 10.40 LL 21:12:01 0:00:33:46 17 0 0.0 49.5 46.6 9.10 21:12:32 0:00:34:17 3 0 0.0 49.5 0.0 9.43 f 1 21:13:03 0:00:34:48 5 0 0.0 49.5 0.0 10.20 21:13:34 0:00:35:19 9 0 0.0 49.5 0.0 11.00 21:14:05 0:00:35:50 10 0 0.0 49.5 0.0 12.20 Ao � CJ' 21:14:36 0:00:36:21 9 0 0.0 49.5 0.0 12.10 21:15:07 0:00:36:52 10 0 0.0 49.5 0.0 12.20 21:15:38 0:00:37:23 9 0 0.0 49.5 0.0 12.20 21:16:09 0:00:37:54 80 81 1.1 49.8 0.3 11.80 21:16:40 0:00:38:25 238 128 3.9 51.1 1.6 9.20 ii, eA 21:17:11 0:00:38:56 234 108 4.2 53.3 3.8 9.40 21:17:42 0:00:39:27 194 108 3.8 55.4 5.9 12.00 �L/� 21:18:13 0:00:39:58 279 218 5.1 57.4 7.9 11.60 n. 21:18:44 0:00:40:29 201 189 4.7 60.4 10.9 13.80 VAC tAir 21:19:15 0:00:41:00 194 160 4 6 62.8 13.3 10.70 21:19:46 0:00:41:31 74 57 3.5 65.1 15.6 11.40 21:20:17 0:00:42:02 62 16 2.9 66.7 17.2 12.20 21:20:48 0:00:42:33 71 24 2.9 68.2 18.7 12.30 21:21:19 0:00:43:04 141 85 4.5 70.2 20.7 11.10 21:21:50 0:00:43:35 66 3 3.0 72.2 22.7 12.80 21:22:21 0:00:44:06 63 0 3 0 73.7 24.3 12.00 21:22:52 0:00:44:37 62 0 3.0 75.3 25.8 12.10 21:23:23 0:00:45:08 67 0 3 0 76.8 27.3 12.20 21:23:54 0:00:45:39 68 0 2.9 78.3 28.8 12.10 21:24:25 0:00 46:10 69 0 3.0 79.9 30.4 11.80 21:24:56 0:00.46:41 62 0 3 0 81.4 31.9 11.70 21:25:27 0:00:47:12 61 0 2.9 82.9 33.4 11.50 21:25:58 0:00:47:43 63 0 2.9 84.4 34.9 11.40 21:26:29 0:00:48:14 128 48 5.1 86.3 36.9 10.80 21:27:00 0:00 48:45 0 24 5 5 89.3 39.8 11.00 21:27:31 0:00:49:16 102 44 4.2 91.6 42.1 11.60 21:28:02 0:00:49:47 102 26 4.2 93.7 44.2 11.70 21:28:33 0:00:50:18 89 3 3.7 95.7 46.2 12.10 21:29:04 0:00:50:49 93 11 3.6 97.6 48.1 12.50 21:29:35 0:00:51:20 96 22 3.6 99.5 50.0 12.50 BJ Services Job Start: Monday, October 24, 2011 , Li illie.... .1, .4 A vv vs...•iVVJ alVIIIIIIIGIQPIIMII IF IIOW a4U YGI0W11 J.JV Job Number: Customer: Au. Gas Inc Well Name: Three Mile Creek#3 Time Elapsed Press Press Flow F1+F2 F1+F2 Aux of Time 1 2 1+2 Total Stage (DBIV) Day Pump Well (bpm) (bbl) (bbl) (ppg) PSI PSI (psi) (psi) Monday. October 24,2011 21:30:06 0:00:51:51 69 1 2.9 101.0 51.6 12.10 21:30'37 0:00:52:22 65 0 3.0 103.0 53.1 12.40 21:31:08 0:00:52:53 82 1 3.4 104.0 54.9 12.50 21:31:39 0:00:53:24 82 2 3.4 106.0 56.6 12.40 21:32 10 0:00:53:55 86 8 3.4 108.0 58.3 11.80 21:32 41 0:00:54:26 90 15 3.3 110 0 60.0 12.30 21:33 12 0:00:54:57 87 12 3.3 111.0 61.8 12.00 21:33 43 0:00:55:28 84 11 3.3 113.0 63.5 12.20 21:34 14 0:00:55:59 82 11 3.3 115 0 65.2 11.90 21:34.45 0:00:56:30 84 11 3.3 116.0 67.0 12.20 21:3516 0:00:57:01 87 14 3.3 118.0 68.7 12.10 21:35 47 0:00:57:32 91 21 3.3 120.0 70.4 12.00 21:36 1 B 0:00:58:03 88 15 3.4 122.0 72.1 12.00 21:36.49 0:00:58:34 86 14 3.3 123.0 73.9 12.30 21:37.20 0:00:59:05 91 20 3.3 125.0 75.6 12.70 21:3751 0:00:59:36 120 62 3.3 127.0 77.3 13.50 21:3822 0:01:00:07 102 48 3.3 128 0 79.0 13.50 21:38 53 0:01:00:38 88 20 3.3 130 0 80.7 12.10 1,.. 21:39 24 0:01:01:09 81 11 3.3 132.0 82.4 11.60 21:39.55 0:01:01:40 69 0 2.9 134.0 84.1 12.50 4L 3 21:40:26 0:01:02:11 79 0 3.8 136.0 86.0 10.80 21:40 57 001:02:42 89 0 3.8 137.0 88.010.50 v� 21:41:28 0.01:03:13 14 0 4.7 140.0 0.5 9.16 21:41:59 0.01:03:44 53 0 4.6 142.0 2.9 10.00 21:42:29 0:01:04:14 86 0 4.1 144.0 5.0 11.20 i•-e t 21:43:00 0:01:04:45 131 77 5.2 147.0 7.6 11.50 21:43.31 0:01:05:16 127 73 4 3 149 0 10.1 14.10 21:44:02 0:01:05:47 104 54 3 4 151.0 11.9 15.10 21:44:33 0:01:06:18 89 26 2.9 153.0 13.5 15.20 21:45:04 0.01:06:49 166 104 4.2 155.0 15.5 14.80 21:45 35 0:01:07:20 150 99 4.2 157.0 17.6 14.70 21:46.05 0 01:07:50 147 99 4.1 159 0 19.7 14.60 21:46:35 0 01:08:20 145 100 4.1 161.0 21.8 14.80 21:47:05 0:01:08:50 169 124 4.4 163.0 23.9 15.10 21:47:35 0.01:09:20 199 166 4.4 165.0 26.2 16 80 21:48.05 0:01:09:50 32 221 5 9 168 0 28.8 14.80 21:48:35 0:01:10:20 0 144 5.5 171.0 31.6 14.10 21:49.05 0 01:10:50 161 138 4 6 173.0 34.1 14 30 21:49.35 0 01:11:20 128 99 3 9 175.0 36.0 14 40 21:50 05 0 01:11:50 138 108 3.9 177.0 38.0 15.00 21:50.35 0:01:12:20 140 104 4.0 179.0 39.9 14.50 21:51:05 0:01:12:50 149 114 4.0 181.0 41.9 14.80 21:51:35 0.01:13:20 160 122 4 2 183.0 44.0 15.30 21:52:05 0 01:13:50 233 199 5 0 185.0 46.2 16.10 21:52:35 0:01:14:20 229 214 4.8 188.0 48.6 16.60 21:53 05 0:01:14:50 189 175 5.0 190.0 51.0 13.10 21:53 35 0 01:15:20 0 26 5.4 193 0 53.7 11 40 21:54.05 0.01:15.50 0 19 5.4 196.0 56.4 8.21 21:54:35 0:01:16:20 0 38 5.3 198.0 59.0 10.80 21:55.05 0:01:16.50 0 0 5.4 201.0 61.8 11.30 21:55:35 0.01:17:20 0 0 5.4 204.0 64,5 10.60 BJ Services Job Start: Monday, October 24, 2011 iir .4 i.ry vii vs‘,. NvuauOawI I`I'OW 0111 VCIWO/1 1.1.0U Job Number: Customer: Au , Gas Inc Well Name: Three Mile Creek#3 Time Elapsed Press Press Flow F1+F2 F1+F2 Aux of Time 1 2 1+2 Total Stage (DSIV) Day Pump Well (bpm) (bbl) (bbl) (PM) PSI PSI (Psi) (Psi) Monday, October 24,2011 21:56:05 0 01:17:50 70 0 4.7 206 0 67.1 11.50 21:56:35 0 01:18:20 0 12 5.6 209.0 69.8 12.40 21:57:05 0 01:18:50 0 49 5.3 212.0 72.5 12.80 21:57:35 0.01:19:20 0 29 5.5 214.0 75.3 12.70 21.58:05 0.01:19:50 0 84 5.5 217.0 78.0 13.50 21:58:35 G01:20:20 25 184 6.0 220.0 81.0 14.90 21.59:05 0.01.20:50 50 225 6.4 223.0 84.1 14.20 21:59:35 0:01:21:20 66 253 6.3 226.0 87.2 15.10 22 00:05 0:01:21:50 13 201 5.5 229.0 90.2 15.20 22:00:35 0 01 22:20 0 168 5.3 232.0 92.8 14.90 22 01:05 001 22:50 10 189 5.7 235 0 95.5 14.90 22 01:35 0:01.23:20 33 221 6.1 238.0 98.4 14.80 22 02:05 0.01 23:50 61 255 5.9 241.0 101.0 16.20 22:02:35 0:01:24:20 95 302 5.9 243.0 104.0 16.10 22.03:05 0.0124:50 41 243 5.8 246.0 107.0 14.90 2203:35 0.01:25:20 4 191 5.9 249 0 110.0 13.80 22-04:05 0:01:25:50 22 149 5.3 252.0 113.0 14.30 22.04:35 0:01:26:20 217 197 5.1 255.0 116.0 14.70 2205:05 0:01:26:50 221 200 5.0 257.0 118.0 15.00 22.05:35 0.0127:20 227 205 5.0 260.0 121.0 14.40 22 06:05 0:01.27:50 229 208 5.1 262.0 123.0 15.00 22 06:35 0 01 28:20 205 187 5.2 265.0 126.0 13.20 22:07:05 0:01:28:50 198 175 5.3 268.0 128.0 13.50 22-07:35 0:01:29:20 208 180 5.2 270.0 131.0 13.90 22:08:05 0:01:29.50 222 191 5.2 273.0 134.0 14.40 22:08:35 0:01:3020 42 158 5.3 275.0 136.0 14,60 22:09:05 0 01:30:50 4 174 5 5 278 0 139.0 15.00 22:09.35 0:01:31.20 0 175 5.4 281.0 142.0 15.00 22:10:05 0:01:31.50 0 172 5.4 284.0 144.0 15.00 22:10:35 0:01:32:20 0 166 5.5 286,0 147.0 15.10 22:11:05 0 01:32:50 0 171 5.5 289.0 150.0 15.20 22:11:35 0:01:3320 0 166 5.4 292.0 153.0 15.20 22.12:05 0 01:33 50 0 156 5.4 294.0 155.0 15.10 22.12:35 0.01:34:20 211 189 5.1 297.0 158.0 14.80 22.13:05 0:01:34:50 211 184 5.1 300.0 161.0 14.60 2213.35 0.01.35:20 207 180 5.2 302.0 163.0 14.20 22:14:05 0:01.3550 210 177 5.1 305.0 166.0 14.30 2214:35 0:01-36-20 214 184 5.1 307.0 168.0 14.70 22:15:05 0:01:3650 217 181 5.0 310.0 171.0 14.90 . 22:1535 0.01 37:20 214 176 5.0 312.0 173.0 15.00 ��► 22:16:05 0 01:37.50 225 188 5.0 315.0 176.0 15.10 22:16:35 0:01.38 20 0 148 5.3 317.0 178.0 15.10 \ � 22.17:05 0:01:38:50 0 161 5.3 320.0 181.0 15.30 //.� ,e) 61. 22:17:35 0:01:39:20 0 162 5.3 323.0 184.0 14.40 (1, 22.18:05 0:01:39:50 0 85 5.3 325.0 186.0 12.20c' 22'18:35 0:01.40.20 6 0 0.0 327.0 188.0 9.56 /�T¢ 22:19:05 0.01.40:50 5 0 0 0 327.0 0.0 11.00 22:19:35 0 01-41:20 125 0 5.7 328 0 1.0 11.80 sof t, 22:20:05 0:01:41.50 126 0 5.7 331.0 3.8 12.10 4.4 b/ 22.20:35 0:01:42:20 12 0 0.0 332.0 5.1 11.60 y a 22:21:05 0:01:42 50 5 0 0.0 332.0 5.1 11.80 1 -70 BJ Services Job Start Monday,October 24, 2011 - .4 i ry v... ..vv.i VV.R/..14.7 tu I I IW 10111 V WI*I1.01 I J•JV Job Number: Customer: Aa, Gas Inc Well Name: Three Mile Creek#3 Time Elapsed Press Press Flow F1+F2 F1+F2 Aux of Time 1 2 1+2 Total Stage (D1311.0 Day Pump Well (bpm) (bbl) (bbl) (ppg) 'ecb PSI PSI J (psi) (psi) Jc © � �.1 Monday, October 24, 2011 4,,� 22:21:35 0:01:43 20 11 0 0 0 332.0 5.1 12 00 t} `C 22:22:05 0:01:43.50 139 103 3 7 332.0 5.4 12 40 22:22:35 0:01:44:20 280 154 5 4 335 0 8.0 12 50 (i.-(1"" 22:23:05 0:01:44:50 14 0 0.0 335.0 8.2 12.30 22:23:35 0:01:45:20 13 0 0.0 335 0 8.2 12.40 (i‘n t' is' .,A 1;, ,.., x re , > 4, 4,..,-- Md 5 - Li- 40 BJ Services Job Start: Monday, October 24, 2011 WI December 2", 201 I POST TREATMENT REPORT Aurora Three Mile Creek # 3 Treatment dates: November 9th Mr. Chad Helgeson Aurora Gas LLC (907) 277-1003 Bus Mr. Helgeson, Please find attached our well report of the five gravel pack treatments on the Three Mile Creek, Well#: 3. The proppant and fluid used to complete each zone of the completion are displayed in the following table. Sand lbs Fluid Fluid Stage type Mesh psa Sand type Volume White 20/40 83,072 24,696 #1 Flex 12/20 2-8 12,000 3% KCI gal White 20/40 84,500 23,310 #2 Flex 12/20 2-8 12,000 3% KCI gal BJ Services appreciates the opportunity to perform pumping services for you in a cost- effective manner that focuses on safety, quality and the enhancement of your property's value. Please let me know if you have any questions ;,,/,/ Field Engineer Kenai, Alaska (907) 398-8303 ri- BAKER HUGHES Proposal No: 685251051A AURORA GAS INC THREE MILE CREEK UNIT#3 API # 50-283-20117-0000 THREE MILE CREEK Field 34-13N-11W Tyonek County, Alaska December 2nd, 2011 Fracturing - Post Treatment Report Prepared for: Prepared by: Chad Helgeson Joshua Herald Aurora Gas LLC Field Engineer Bus Phone: 907.277.1003 Kenai, Alaska Service Point: Service Representatives: KENAI Rod Edwards Bus Phone: 907-776-4084 Account Manager (907)659-2329 Kenai, Alaska Fax: 99611 Bus Phone: 907-349-6518 Mobile: 907-229-6536 Powered by PowerVision Gr4105 ( STIMULATION TREATMENT REPORTLil Date 08-NOV-11 District Kenai F.Receipt 1001865610 Customer AURORA GAS LLC Lease THREE MILE CREEK UNIT#3 Well Name THREE MILE CREEK UNIT#3 Field THREE MILE CREEK Location 34-13N-11W County Tyonek State Alaska Stage No 1 Well API -API 50283201170000 WELL DATA Well Type: NEW Well Class: GAS Depth TD/PB: 5159 Formation: Geometry Type Tubular Type OD Weight ID Grade Top Bottom Perf Intervals TUBULAR CSG 5.5 15.5 4.95 0 5800 Top Bottom SPF Diameter TUBULAR TBG 2.875 6.5 2.441 0 4630 3926 3946 6 .375 3966 3986 6 .375 Packer Type ArrowPack Mechanic Packer Depth 4100 FT TREATMENT DATA LIQUID PUMPED AND Fluid Type Fluid Desc Pumped Volume(Gals)J Prop.Description Volume Pumped(Lbs) CAPACITIES IN BBLS. PAO 3%KCL 3.318 FlexSand MSE,12/20 mesh 12,000 Tubing Cap. 22.6 TREATMENT FLUID 20#Liahtnina/3%KCL 21.378 Sand,White,20/40 83,072 Casing Cap. 1.6 PAD 3%KCL 4,200 FlexSand MSE,12/20 mesh 12,000 TREATMENT FLUID 20#Liahtnina/3%KCL 18.270 Sand,White,20/40 84,500 Annular Cap. 64.2 PAD FRESH WATER FLUSH 840 Total Prop Qty: 191,572 Open Hole Cap. 0 Fluid to Load 3 Pad Volume 150 Previous Treatment N/A Previous Production N/A Treating Fluid 762 Hole Loaded WithTubingCasing 9.4#Brine Treat Via: Anul. &Anul. ❑ � I Tubing Flush 49 Ball Sealers:_ 1 _In 2 Stages Type_ Overflush 0 Auxiliary Materials XLW-32,BF-8L,CLAYMASTER SC,BC-3,FLO-BACK 30,ENZYME"G",GBW-18,XCIDE-207,20/40 WHITE SAND,12/20 FLEX SAND MSE.POTASSIUM CLORIDE.GLFC50 Fluid to Recover 961 PROCEDURE SUMMARY Time Surface Slurry Slurry Rate AM/PM Treating Pressure-Psi BBLS.Pumped BPM Comments STP Annulus Stage Total 08:00 • YARD CALL FOR TRIP ACROSS TO LOCATION 09:30 • LEAVE YARD FOR AIRPORT 09:45 ARRIVE AIRPORT FOR FLIGHT 10:00 DEPART ON FLIGHT ACROSS INLET TO BELUGA AIR STRIP 10:30 ARRIVE PEAK MAN CAMP TO CHECK IN FOR STAY 11:30 LEAVE MAN CAMP HEADED TO LOCATION 12:15ARRIVE LOCATION 12:30 LOCATION STILL BEING DRESSED UP AND TANK MANIFOLDING STILL GOING ON 13:00 HEADING TO TYONEK BARGE LANDING WITH CREW TO _ ,DRIVE TRUCKS FROM BARGE LANDING TO LOCATION 14:30 i _ CRANE STILL NOT ARRIVED AT LOCATION 15:00 i CRANE ARRIVED TO LOCATION/SPOTTING HYDRATION UNIT TO PICK SKID UNIT OFF FOR PLACEMENT 16:00 HYDRATION UNIT SPOTTED LINING OUT BLENDER FOR ;SKID PICK 16:30 1 _ _..._ _._ _�. w __.___- (BLENDER SPOTTED 16:45 1 _ _ .SPOTTING FRAC PUMPS 17:30 SPOTTING SAND KING AND SAND BOX 18:00I.__ DONE FOR DAY HEADED TO MAN CAMP 18:30 ARRIVE MAN CAMP OFF FOR NIGHT 00:00 11/6/2011 07:00 _ YARD CALL AT MAN CAMP TO HEAD TO LOCATION 07:30 'i ARRIVE LOCATION 07:45 _ _ _ _ SAFETY MEETING 08:00 I I CONTINUE SPOTTING REMAINING EQUIPMENT AND BEGIN RIGGING UP IRON 08:00 .REMAINING CREW YARD CALL FOR TRIP ACROSS INLET 10:00 _ 4 __ REMAINING CREW FLIGHT ACROSS INLET 10:45 1CREW ARRIVES ON BELUGA SIDE OF INLET AND PICKED UP 11:00 REMAINING CREW CHECKS INTO MAN CAMP 11:30 'REMAINING CREW LEAVES MAN CAMP FOR LOCATION / Uli Treatment Report-Supplement \ ) Date 08-NOV-11 District Kenai F.Receipt 1001865610 Customer AURORA GAS LLC Lease THREE MILE CREEK Uf Well Name THREE MILE CREEK L Field THREE MILE CREEK Location KENAI County Tyonek State Alaska Stage No 1 Well API -API 50283201170000 TIME Treating Pressure-Psi Surface Slurry Slurry Rate Comments BBLS.Pumped BPM STP Annulus Stage Total 00;00 'TRIPPED ALL WEAVER BULK TRUCKS TO LOCATION 13:00 SAND KING LOADED WITH 20/40 WHITE SAND 13:30 WAITING ON WATER TANKS TO GE HEATED SO THAT WE CAN KCL TANKS 14:30 STILL WAITING ON DEFUSER AND FLOW BACK TANK TO BE SPOTTED SO THAT BLEED OFF CAN BE RAN • 18:30 LOCATION RIGGED UP WITH EXCEPTION OF BLEED OFF AND TMV DUE TO NEEDING ROME FOR BLEED OFF TANKS 20:30 DONE FOR DAY ON LOCATION STILL WAITING ON WATER TO BE HEATED AND BLEED OFF TANKS TO BE SPOTTED 21:00 ARRIVE MAN CAMP OFF FOR NIGHT 00:00 11/07/2011 07:30 ARRIVE LOCATION 07:00 YARD CALL AT MAN CAMP TO COME BACK OUT TO LOCATION 07:45 SAFETY MEETING 08:00 BROUGHT CEMENT VAN TO LOCATION AND RIGGED INTO BACKSIDE 08:30 LOADED FLEX SAND INTO SAND BOX AND REMAINING . 20/40 FROM FLOAT 09:00 CEMENT VAN RIGGED UP TO BACKSIDE 09:30 BEGAN TRIPPING WEAVER BULK TRUCKS TO TYONEK BARSzE_LANDING 14:30 'S : •• ► : . : 0 BARGE LANDING 15:00 POLLARD WIRELINE CREW ARRIVES LOCATION TO BEGIN . HELPING ALASKA HEATER NEAT TANKS 16:00 STILL NO HEATED WATER DONE FOR DAY ON_LOCATION_. 16:30 ARRIVE MAN CAMP OFF FOR NIGHT _00:00 11/08/2011 06:00 YARD CALL LEAVE MAN CAMP 05;30 ARRIVE LOCATION 06:45 2 TANKS HEATED UP SAFETY MEETING PRIOR TO KCL OF TANKS 07:00 BEGIN KCL OF TANKS 09:30 1_ iDONE WITH FIRST TANK 1000 ._� _.. STARTING SECOND TANK 12:00_.__. — .FINISHED WITH SECOND TANK 12:30 WAITING ON CRANE TO FINISH STANDING FLARE STACK SO THAT WE CAN BEGIN KCL OF THIRD TANK 14:00 _ _ —_ —._ (STARTING THIRD TANK 14:30 DISCUSSED WITH CUSTOMER OPTION OF DROPPING THE _ _ __ ___ - MINI FRAC AND DIAGNOSTICS DUE TO FRAC PRO NOT WOI 15:00 I CUSTOMER DECIDED TO DROP MINI FRAC AND DIAGNOSTICS 16:30 _ __ _ __ . — ,FIN SHED WITH THIRD TANK 17:30 READY FOR SAFETY MEETING FOR PRE FRAC _17:00 REALIGNING OPERATION FOR DOWN HOLE TREATMENT 18:00 _ _ I__ _ _ SAFETY MEETING Treating Pressure Injection Rates Shut In Pressures Customer Rep. Ed Jones Minimum 2300 Treating Fluid 16.5 ISDP 1810 1BJ Rep. RAYMOND C DYSON Maximum 4454 Flush 12.5 5 Min. 1727 Job Number 1001865610 . Average 3381 Average 16.5 10 Min. 1702 Rec.ID No. Operators Max.Pressure 15 Min. 1698 Distribution 7000 Final 1698 In Min. 15 Flush Dens.Ib./gal. 8.34 i (-- Treatment Report-Supplement Liu J Date 08-NOV-11 District Kenai F.Receipt 1001865610 Customer AURORA GAS LLC Lease THREE MILE CREEK UP Well Name THREE MILE CREEK L Field THREE MILE CREEK Location KENAI County Tyonek State Alaska Stage No 1 Well API -API 50283201170000 TIME Treating Pressure-Psi Surface Slurry Slurry Rate Comments BBLS. Pumped BPM STP Annulus Stage Total 18:30 BEGIN PULLING WATER ONTO HYDRATION UNIT FOR TESTING. 18:45 SHUTDOWN WITH 90 BBLS ON HYDRATION DUE TO ISSUE WITH UNIT 18:56 LOVE JOY FOR SUCTION PUMP BROKE UNIT DOWN FOR . NIGHT,MAKING CALLS TO FIND PARTS FROM SHOP. 20:00 DISCUSSED WITH MAINTANCE SUPERVISOR AND CUSTOMER VIA SPEAKER PHONE IN REGARDS TO PART Al 21:00 FURTHER DISCUSSION WITH CUSTOMER RECOMMENDED THAT WE GEL TANKS TO AVOID FURTHER DELAY OF JOB t 21:30 DONE GETTING ALL FLUID OUT OF HYDRATION UNIT AND BLENDER TO PREVENT FREEZE UP 22:00 ARRIVE BACK AT MAN CAMP WITH EXCEPTION OF CHEM ADD CREW WHO FINISHED CLEANING OUT PRIMED_UP CHE 23:00 JOSH PAYNE AND JORDAN WATERS BOTH STAYED ON LOCATION OVER NIGHT AS FIRE WATCH SO THAT EQUIPMI 00:00 .11/09/2011 06:30 . YARD CALL AT MAN CAMP TO HEAD TO LOCATION 0700 ARRIVE LOCATION 07:15 DOUBLE CHECK EQUIPMENT PRIOR TO START OF . GELLING TANKS 07:30 ;SAFETY MEETING 08:00 BEGIN GELLING UP TANKS 08:40 GEL IN ON FIRST TANK AND BEGIN ROLLING TANK VOLUME TO VERIFY VISCOSITY 09:15 FINISHED GELLING UP FIRST TANK VISC IS 27CP SETTING . UP FOR SECOND 09:30 BEGIN GELLING UPANK SECOND TANK ___ 09:45 GEL IN_AND ROLLING j 10:46 FINISHED ROLLING TANK VISC IS 30CP SETTING UP FOR THIRD TANK 11:05 BEGIN ROLLING IN GEL TO THIRD TANK 11:22 . .GEL IN AND ROLLING 12:20 FINISHED ROLLING TANK VISC IS 25CP SETTING UP FOR i .THE FRAC 12:4 _. -L __ —. . .SAFETYMEETING 13:20 ' BEGIN LOADING UP LINES AND PUMPS AND START __ _ PRESSURE TEST OF MAINLINE AND BACKSIDE 13:21 1 I FIXING_LEAK ON LOW PRESSURE,.IDE OF A PUMP 13:29 t I DONE REPAIRING LEAKS AND ATTEMPTING TO PRIME UP __ -- AGAIN 13.42 _.____ POP OFFSET AT 7320 PSI I 13:44 _ __ —. _, _., LEAK ON THE MAIN LINE 3"IRON I 13:50_ tt ___ ;LEAK FIXED RE-PRESSURE TESTINGMAINLINE_ 13:52 __ — —. t RETESTING LINES TESTED TO 8290 PSI GOOD TEST 13:5.3— 1 TESTING BACKSIDE LINE TO 3500 PSI 13:55 PRESSURE TESTED TO 3465 PSI 13:58___;_ L PRESSURING UP BACKSIDE TO 1966 PSI Treating Pressure Injection Rates I Shut In Pressures Customer Rep. Ed Jones Minimum 2300 Treating Fluid 16.5 ISDP 1810 BJ Rep. RAYMOND C DYSON !Maximum 4454 _i Flush 12.5 1 5 Min. 1727 Job Number 1001865610 11, 'Average 3381 1 Average 16.5 10 Min. 1702 Rec. ID No. Operators Max Pressure 15 Min. 1698 Distribution 7000 Final 1698 In Min. 15 Flush Dens.Ib./gal. 8.34 Treatment Report-Supplement Ul ..) Date 08-NOV-11 District Kenai F.Receipt 1001865610 Customer AURORA GAS LLC Lease THREE MILE CREEK UI Well Name THREE MILE CREEK L Field THREE MILE CREEK Location KENAI County Tyonek State Alaska Stage No 1 Well API -API 50283201170000 Surface Slurry Slurry Rate -11ME Treating Pressure-Psi 1 BBLS.PumpedgpM Comments STP Annulus Stage Total 14:00 DISCONNECTING ALTERNATOR FROM 0206 FRAC PUMP AND CONNECTING CHARGER TO MAINTAIN VOLTAGE 14:05 CLOSING UP 0206 FRAC PUMP AND WILL USE IT AS A ___. _._, _.- •BACK UP PUMP VIC CLAMP ON SUCTION MANIFOLD RUBBE 14:11 175 1937 -._ OPEN UP WELL 14:11 2233 3.BREAK 14:19 3033 2077 0 79 15.2 START 2.0#20/40-12.5%FLEX 14:21 2871 2039 25.6 104 14.6 2,0#20/40-12.5%FLEX ON FORMATION 14:26 2852 2065 - 0 171 14.6 START 4.0#20/40- 12.5%FLEX 14:27 2820 2122 25.6 196 14.6.4.0#20/40-12.5%FLEX ON FORMATION 14:33 2827 2086 0 270 15 START 6.0#20/40- 12.5%FLEX 14:34 _.. 2894 2083 25.6 296 14.5.6.0#20/40-12.5%FLEX ON EOORMATION .__ 14:44 2876 2093 0 439 14,8 START 8.0#20/40- 12.5%FLEX 14:46 3079 2092 25.6 465 14 4 8.0#20/40-12.5%FLEX ON FORMATION _ 14:54 3083 2.052 0 588 14.5 START FLUSH/SWAP VALVE ALIGNMENT AND DROP BALL FOR SLEEVE SHIFT 14:55 3247 2073 14 602 15.BALL DROPPED __ 14;56 4436 2123 22 610 14.8.BALL HIT SLEEVE SHIFTED. 14:56 3192 2154 0 616 15:START PAD 14:57 3838 2118 20 636 17.4 PAD ON FORMATION _ 15:01 3828 2041 0 688 _ 18.4 START 2.0#20/40-12.5%FLEX _ __ 15:02 3640 2066 20 . __ 708; .-_____. 18.4 2.0#20/40..-_12.5%FLEX ON FORMATION _ I 15:04 3621 2098 0 . _. 7.53_1- _ 18.2 START 4.0#20/40-12.5%FLEX I ._1.5;05 3557. 2098 20._ -..__7.73..1.___ 18.1.4.0#20/40-12.5%FLEX ON FORMATION _____ _-__ . 15:08 3433 2075 0 8241 18.3 START 5.0#20/40-12.5%FLEX 15:Q9 . 3463. 2067 . 20_. 844. 18.1 5.0#20/40-12.5%FLEX ON FORMATION 15:13_ 3518 2043 0 898 18.2.START 6.0#20/40-12.5%FLEX 15:13 3635 2043 20 918 18.3 6.0#20/40_12.5%FLEX 15:20 3786. 1993 0 1036 18.1 .START 8.0#20/40-12.5%FLEX 15:21 3966 1985 20 1056 18.3 8.0#20/40-12.5%FLEX ON FORMATION 15:22 3986 1971 36 1072 17.8 LOST SUCTION RATE AT BLENDER DUE TO ONE OF THE 3 TANKS BEING EMPTY 15:24 3284 1892 _ 51 1088 12 REGAINED PRIME AT_BLENDER RESUME.SANDAND RATE 15:25- 3567 _ 1994 . 71 . 1108 _18.1 ;8.0#20/40-12.5%FLEX BACK ON FORMATION-_ 15:25 1822 1933 83 I 1119 8 LOST WATER AGAIN AT BLENDER ANOTHER TANK EMPTY .__. ..__I SWAPPING VALVES TO REMAINING FRESH WATER TANKA ._ __ :START FLUSH WITHFRESIiWATER._ __- 15:29 . .1836 1883 ___19.5_.__ 1143. 0:SHUTDOWN _ _. ____. 15:27 2578 . __1935 I -0_ 1123 10.5. 15:29 . 1810. j ISDP_ ____ _ --- jl 15:34 1727 511AIN PRESS r- - j. 15:39 . 1702. _ _10 MIN PRESS 15:44 . 1698, .15 MIN PRESS 15:45 CLOSE IN WELL AND TURN OVER FOR FLOW BACK. SAND :LEFT IN SAN KING WAS 3,000 . - OX.OF 20/40 WHITE ANC l TreatingPressure Rates Shut In PressuresCus • =r Rep. I Injection ep Ed Jones Minimum 2300Treating Fluid 16.5 ISDP 1810 BJ ' P. RAYMOND C DYSON Maximum 4454 ______iFlush 12.5 5 Min. 1727 Job Number 1001865610 Average 3381 Average 16.5 10 Min. 1702 i Rec.ID No Operators Max. Pressure __ _ 15 Min. 1698 I Distribution 1 7000 Final 1698 In Min. 15 Flush Dens.Ib./gal. 8.34 Repotl Pnnle6 on n.ovor,c,n p''0;i e.:^PM 311101 FA/ BAKER HUGHES Proposal No: 685251051A AURORA GAS INC THREE MILE CREEK UNIT#3 API # 50-283-20117-0000 THREE MILE CREEK Field 34-13N-11W Tyonek County, Alaska December 2nd, 2011 Fracturing - Post Treatment Report Stage #1 Prepared for: Prepared by: Chad Helgeson Joshua Herald Aurora Gas LLC Field Engineer Bus Phone: 907.277.1003 Kenai, Alaska Service Point: Service Representatives: KENAI Rod Edwards Bus Phone: 907-776-4084 Account Manager (907)659-2329 Kenai, Alaska Fax: 99611 Bus Phone: 907-349-6518 Mobile: 907-229-6536 Powered by PowerVision Gr4105 (wdq) awj N ,-r O Lt) O O 1 ! ! 1 I m E > 0 V) z a) 1— m a) 'V U) C o u) c U) a) a) 0_ a) in m U CO _. N O c •J c u) o_ O) a) C LLE h - TY h a n L. ea h a m ow c o O 12 L m m m E M U O �' L � X11. L L i ill o U • ao co C i dy N O o ✓ u o d d J n' � v � .3 / 1hhh1h1 ' hhh1hh10 LO (isd) sninuuv (!sd) d1S m (esd) age}j pue5 HS (esd) VSd ipul8 0 0o c0 N O ai I ) I I I I I I r,. o C-, ai c0 E U) > 0 z N T co (6 a co ,,`= C _0 .0 (n CLS _ O O CO s---- N- -si co as co _oini- is- -.1011110/1100"-- _ -41111 C -_r CO cy w - E H CU 4.0 cD V) T_" a (150 -"Al - CZ co _ w D `h 0 O — o (23. CEI In Q at m v T E _" gt � U O 1 m - L a N r ..' o V N E 4D CO M n V. i d - O c o a - - ci d Z p Z 1 1 1 1 1 1 I 1. 1 1 1 1 1 n »r z co LU CD co o - ,c z m n >° Vs (Ludq) aleN 3 1 I I I 1 1 1 I 1 1 o I I III o 0 o 0 0 o0 cpU (isd) snlnuu�y (isd) dig co m Operator Name: AURC ;AS INC Well Name: THREE MILE CREEK UNIT#3 BAKER ' Job Description: Stage 1 of 2 HUGHES Date: October 27, 2011 Proposal No: 685251051A JOB AT A GLANCE Surface Treating Pressure(max) 1,341 psi Total Rate (max) 15.00 bpm Estimated Pump Time (HH:MM) 00:47 KCI Water 4,200 gals 3% KCI Frac Fluid 21,600 gals Lightning 2000 Proppants 78,750 lb Sand, White, 20/40 11,250 lb FlexSand MSE, 12/20 mesh • Repo l Printed on December 2 2011 4 38 PM G14111 Have more questions? You can find us at: http://www.bakerhughes.com/products-and-services/pressure-pumping Operator Name: AURORA 3 INC r� Well Name: THREE CREEK UNIT#3 BAKER Job Description: Stage 1 of 2 HUGHES Date: October 27, 2011 Proposal No: 685251051A WELL DATA RESERVOIR DATA MD Depth to Middle Perforation 3,956 ft TVD Depth to Middle Perforation 3,698 ft Reservoir Pressure 1,818 psi Bottom Hole Static Temperature 100 ° F PERFORATED INTERVAL DEPTH(ft) Shots per Foot Perf Diameter Total Perfs MEASURED TRUE VERTICAL (in) 3,926- 3,946 I 3,671 - 3,671 I 6 I 0.38 I 120 3,966 - 3,986 I 3,725 - 3,725 I 6 I 0.38 I 120 Total Number of Perforations 240 Total Feet Perforated 40 ft TUBULAR GEOMETRY Top Bottom Casing 5 1/2" O.D. (4.950" .I.D) 15.5# 0 5,800 Tubing 2 7/8" O.D. (2.441" .I.D) 6.5# 0 4,630 End of Tubing 4,630 ft Pump Via Tubing Report Printed on: December 2,2011 4:38 PM Have more questions? You can find us at: http://www.ba kerh ug hes.c om/prod ucts-and-services/press ure-pumping Operator Name: AURORA '\S INC r� Well Name: THREE Il . CREEK UNIT#3 BAKER , Job Description: Stage 1 of 2 HUGHES Date: October 27, 2011 Proposal No: 685251051A FLUID SPECIFICATIONS KCI Water: 3% KCI 4,200 Gallons Components: 250 ppt Potassium Chloride Salt 0.5 gpt Flo-Back 30 Surface Tension Reducer 0.4 ppt Xcide-207 Bacteria Control Product Frac Fluid: Lightning 2000 21,600 Gallons Components: 250 ppt Potassium Chloride Salt 5 gpt GLFC-5D Gelling Agent 5 ppt GBW-18 Gel Breaker 2 gpt Enzyme G-I Gel Breaker 1.7 gpt BF-8L Buffers/Ph Control Product 1 gpt Clay Master-5C Clay Stabilization Product 0.8 gpt XLW-32 Crosslinker 0.5 gpt BC-3 Gel Breaker 0.5 gpt Flo-Back 30 Surface Tension Reducer 0.4 ppt Xcide-207 Bacteria Control Product Proppants 90,000 lb 87.5% Sand, White, 20/40 12.5% FlexSand MSE, 12/20 mesh Fluids are subject to change based on new information or testing. Report Printed on Decemhei 2 2011 4 38 PM Gr4127 Have more questions? You can find us at: http://www.bakerhughes.com/products-and-services/pressure-pumping Operator Name: AURORP \S INC IM Well Name: THREE I. _ CREEK UNIT#3 BAKER Job Description: Stage 1 of 2 HUGHES Date: October 27, 2011 Proposal No: 685251051A FRACTURE TREATMENT SCHEDULE INPUT PARAMETERS TVD Depth (Mid Perforation) 3,698 ft MD Depth (Mid Perforation) 3,956 ft Perforations Number 240 Perforation Diameter 0.375 in Bottom Hole Static Temperature 100 ° F Top Bottom Casing 5 1/2" O.D. (4.950" I.D.) 15.5# 0 5,800 Tubing 2 7/8" O.D. (2.441" I.D.) 6.5# 0 4,630 CALCULATED RATES, PRESSURES & HHP REQUIREMENTS Maximum Minimum Average Surface Treating Pressure (psi) 1,342 1,342 1,342 Slurry Rate(bpm) 15.0 15.0 15.0 Proppant Rate (lbs/min) 3,636 1,150 2,657 Slurry Hydraulic Horsepower 494 494 494 PROCEDURE Fluid Proppant Type Volume Conc. Type Stage Cum Stage (gal) (ppa) (lbs) (lbs) 1 13% KCI 21001 Injection Test 2 'Lightning 2000 10501 Minifrac 3 13% KCI 21001 Miniflush 4 'Lightning 2000 25001 Pad 5 (Lightning 2000 35001 2.000 87.5%Sand, White, 20/40 6125 112.5%FlexSand MSE, 12/20 8751 7000 6 'Lightning 2000 35001 4.000 87.5%Sand, White, 20/40 12250 12.5%FlexSand MSE, 12/20 1750 21000 7 'Lightning 2000 55001 6.000 87.5%Sand, White, 20/40 28875 12.5%FlexSand MSE, 12/20 4125 54000 8 'Lightning 2000 45001 8.000 87.5%Sand, White, 20/40 31500 12.5%FlexSand MSE, 12/20 4500 90000 9 'Lightning 2000 10501 0.000 Flush - Lightning 2000 0' 90000 Total 25800 90000 Report Printed on December 2,2011 438 PM G41 a 1 Have more questions? You can find us at: http://www.bakerhughes.com/products-and-services/pressure-pumping Operator Name: AURORF - \S INC NIP- Well Name: THREE I. _ CREEK UNIT#3 BAKER Job Description: Stage 1 of 2 HUGHES Date: October 27, 2011 Proposal No: 685251051A FRACTURE TREATMENT SCHEDULE TREATMENT SCHEDULE Surface _ Rates Volume Stage Treating Slurry Clean Prop. Rate Slurry Fluid Pump Pressure (bpm) Fluid (lb/min) Stage Cum. Stage Cum. Time Stage (psi) (bpm) 1 (bbls) (bbls) (bbls) (bbls) hh:mm:ss 1 1341 15.0 15.0 50.0 50.0 50.0 50.0 00:03:19 2 -361 15.0 15.0 25.0 75.0 25.0 75.0 00:01:40 3 1341 15.0 15.0 50.0 125.0 50.0 125.0 00:03:19 4 -361 15.0 15.0 59.5 184.5 59.5 184.5 00:03:58 5 -536 15.0 13.7', 1149.0 91.4 275.9 83.3 267.9 00:06:05 6 -705 15.0 12.6 2112.0 99.4 375.3 83.3 351.2 00:06:37 7 -855 15.0 11.6 2930.8 168.9 544.2 131.0 482.1 00:11:15 8 -982 15.0 10.81 3635.4 148.5 692.8 107.1 589.3 00:09:54 9 -361 15.0 15.0 25.0 717.8 25.0 614.3 00:01:40 Total Pump Time: I 00:47:51 Report Peeled on. December 2,2011 4.38 PM Gi4141 Have more questions? You can find us at: http://www.ba kerh ug hes.com/produ cts-a nd-services/press ure-pumping ri- BAKER HUGHES Proposal No: 685251051A AURORA GAS INC THREE MILE CREEK UNIT#3 API # 50-283-20117-0000 THREE MILE CREEK Field 34-13N-11W Tyonek County, Alaska December 2nd, 2011 Fracturing - Post Treatment Report Stage #2 Prepared for: Prepared by: Chad Helgeson Joshua Herald Aurora Gas LLC Field Engineer Bus Phone: 907.277.1003 Kenai, Alaska Service Point: Service Representatives: KENAI Rod Edwards Bus Phone: 907-776-4084 Account Manager (907)659-2329 Kenai, Alaska Fax: 99611 Bus Phone: 907-349-6518 Mobile: 907-229-6536 Powered by PowerVision Gr4105 (esd) opell pUeS H8 (esd) VSd apul8 0 •• a0 CO �t c� O 1oS ,15 o_ o doo a) v �� o =w L 1 z o -o J (n O C — •- 0O co S O 7 Q a) ,r, ,..„ _ (A O cc O I .0. - I 00to C .a N — o E CD G1 1 E I - - - a �� w L 0 C U- - / -=--, E N v. _ r a - — ?CD Ct 5) , L ca - 1 Q> r v. 7 C O.oc0 �' d \ t y C) d •• '• co i 1) w Z o Z I ;--P-- - _I. ! I I I 1 1 I I I :/) w -- o LU o_ LU o n o 3 N (uadq) abed 3 I1 I I1 1 1 1 1 I 1 1 1 1 1 1 1 0 0 0 0 0 0 71- CO O O O O O v Nc. u�y (Isd) snlnu ( isd) d1S co co Operator Name: AURC GAS INC I VI Well Name: THREE MILE CREEK UNIT#3 BAKER Job Description: Stage 2 of 2 HUGHES Date: October 27, 2011 Proposal No: 685251051A JOB AT A GLANCE Surface Treating Pressure (max) 3,537 psi Total Rate (max) 15.00 bpm Estimated Pump Time (HH:MM) 00:47 Estimated Gross Frac Height 211 ft Estimated Propped Length 176 ft KCI Water 4,200 gals 3% KCI Frac Fluid 21,530 gals Lightning 2000 Proppants 77,088 lb Sand, White, 20/40 11,013 lb FlexSand MSE, 12/20 mesh Report Pnnled on Decemlre,2 2011 4 38 PM G,4111 Have more questions? You can find us at: http://www.bakerhughes.com/products-and-services/press ure-pumping Operator Name: AURORA 3 INC EP— Well 'Well Name: THREE CREEK UNIT#3 BAKER ' Job Description: Stage 2 of 2 HUGHES Date: October 27, 2011 Proposal No: 685251051A WELL DATA RESERVOIR DATA MD Depth to Middle Perforation 3,391 ft TVD Depth to Middle Perforation 3,197 ft Reservoir Pressure 1,450 psi Fracture Gradient 0.75 psi/ft Bottom Hole Fracture Pressure 2,397 psi Bottom Hole Static Temperature 96 ° F Net Fracture Height 185 ft Gross Fracture Height 211 ft Desired Prop Length 176 ft PERFORATED INTERVAL DEPTH(ft) Shots per Foot Perf Diameter Total Perfs MEASURED TRUE VERTICAL (in) 3,362 - 3,372 I 3,170- 3,170 I 6 0.38 I 60 3,410 - 3,420 3,223 - 3,223 6 I 0.38 I 60 Total Number of Perforations 120 Total Feet Perforated 20 ft TUBULAR GEOMETRY Top Bottom Casing 5 1/2" O.D. (4.950" .I.D) 15.5# 0 5,800 Tubing 2 7/8" O.D. (2.441" .I.D) 6.5# 0 3,515 End of Tubing 3,515 ft Pump Via Tubing Report Printed o, Have more questions? You can find us at: http://www.bakerhughes.com/products-a nd-services/pressure-pumping Operator Name: AURORA 'S INC r� Well Name: THREE n . CREEK UNIT#3 BAKER Job Description: Stage 2 of 2 HUGHES Date: October 27, 2011 Proposal No: 685251051A FLUID SPECIFICATIONS KCI Water: 3% KCI 4,200 Gallons Components: 250 ppt Potassium Chloride Salt 0.5 gpt Flo-Back 30 Surface Tension Reducer 0.4 ppt Xcide-207 Bacteria Control Product Frac Fluid: Lightning 2000 21,530 Gallons Components: 250 ppt Potassium Chloride Salt 5 gpt GLFC-5D Gelling Agent 5 ppt GBW-18 Gel Breaker 2 gpt Enzyme G-I Gel Breaker 1.7 gpt BF-8L Buffers/Ph Control Product 1 gpt Clay Master-5C Clay Stabilization Product 0.8 gpt XLW-32 Crosslinker 0.5 gpt BC-3 Gel Breaker 0.5 gpt Flo-Back 30 Surface Tension Reducer 0.4 ppt Xcide-207 Bacteria Control Product Proppants 88,100 lb 87.5% Sand, White, 20/40 12.5% FlexSand MSE, 12/20 mesh Fluids are subject to change based on new information or testing. Report Peeled on December 2 2011 4 38 PM G14127 Have more questions? You can find us at: http://www.ba kerh ug hes.com/products-an d-services/press u re-pumping Operator Name: AURORPAlS INC FA Well Name: THREE W CREEK UNIT#3 BAKER , Job Description: Stage 2 of 2 HUGHES Date: October 27, 2011 Proposal No: 685251051A FRACTURE TREATMENT SCHEDULE INPUT PARAMETERS TVD Depth (Mid Perforation) 3,197 ft MD Depth (Mid Perforation) 3,391 ft Perforations Number 120 Perforation Diameter 0.375 in Bottom Hole Frac Pressure 2,397 psi Bottom Hole Static Temperature 96 ° F Top Bottom Casing 5 1/2" O.D. (4.950" I.D.) 15.5# 0 5,800 Tubing 2 7/8" O.D. (2.441" I.D.) 6.5# 0 3,515 CALCULATED RATES, PRESSURES & HHP REQUIREMENTS Maximum Minimum Average Surface Treating Pressure(psi) 3,538 1,542 2,015 Slurry Rate(bpm) 15.0 15.0 15.0 Proppant Rate(lbs/min) 3,636 1,150 2,714 Slurry Hydraulic Horsepower 1,301 567 741 Report Ported 00 December 2,2011 4 38 PM Gr4141 Have more questions? You can find us at: http://www.bakerh ughes.com/products-and-services/press ure-pumping Operator Name: AURORigriekS INC is - Well Name: THREE 11111E CREEK UNIT#3 BAKER Job Description: Stage 2 of 2 HUGHES Date: October 27, 2011 Proposal No: 685251051A FRACTURE TREATMENT SCHEDULE PROCEDURE Fluid Proppant Type l ) (pp )j Type T e Volume Conc., T e Stage Cum Stag al a (lbs) (lbs) 1 13% KCI 21001 Injection Test 2 'Lightning 2000 10501 Minifrac 3 13% KCI 1 21001 Miniflush 4 'Lightning 2000 30001 Pad 5 (Lightning 2000 2500 2.000 87.5%Sand, White, 20/40 1 4375 12.5%FlexSand MSE, 12/20 625 5000 6 Lightning 2000 2500 4.000 87.5%Sand, White, 20/40 I 8750 12.5%FlexSand MSE, 12/20 1250 15000 7 (Lightning 2000 2500 5.000 87.5%Sand, White, 20/40 10938 12.5%FlexSand MSE, 12/20 1563 27500 8 (Lightning 2000 4500 6.000 87.5%Sand, White, 20/40 1 23625 12.5%FlexSand MSE, 12/20 3375 54500 9 Lightning 2000 I 4200 8.000 87.5%Sand, White, 20/40 29400 12.5%FlexSand MSE, 12/20 I 4200 88100 10 Lightning 2000 1280 0.000Flush - Lightning 2000 0 88100 Total 25730 I 88100 TREATMENT SCHEDULE Surface Rates Volume _ Stage Treating Slurry I Clean I Prop. Rate Slurry Fluid Pump Pressure (bpm) Fluid (lb/min) Stage Cum. Stage Cum. Time Stage (psi) (bpm) (bbls) (bbls) (bbls) (bbls) hh:mm:ss 1 3537 15.0 15.01 50.0 50.0 50.0 50.0 00:03:19 2 2078 15.0 15.0 25.0 75.0 25.0 75.0 00:01:40 3 3537 15.0 15.0 50.0 125.0 50.0 125.0 00:03:19 4 2078 15.0 15.0 71.4 196.4 71.4 196.4 00:04:45 5 1927 15.0 13.7 1149.0 65.3 261.7 59.5 256.0 00:04:21 6 1781 15.0 12.6 2112.0 71.0 332.7 59.5 315.5 00:04:44 7 1714 15.0 12.1 2537.3 73.9 406.6 59.5 375.0 00:04:55 8 1651 15.0 11.6 2930.8 138.2 544.8 107.1 482.1 00:09:12 9 1541 15.0 10.8 3635.4 138.6 683.4 100.0 582.1 00:09:14 10 2078 15.0 15.0 30.5 713.9 30.5 612.6 00:02:01 Total Pump Time: 00:47:35 Report Printed on: December 2,2011438 PM G14141 Have more questions? You can find us at: http://www.bakerh ughes.com/products-and-services/pressure-pumping BAKER HUGHES CONDITIONS BJ Services' performance of services and sale of materials is expressly conditioned upon the applicability of the Terms and Conditions contained in the current BJ Services Price Book. The Terms and Conditions include, among other things, an indemnity in favor of BJ Services from Customer for damage to the well bore, reservoir damage, loss of the hole, blowouts and loss of control of the well, even if caused by the negligence or other fault of BJ Services. The Terms and Conditions also limit the warranties provided by the BJ Services and the remedies to which Customer may be entitled in the event of a breach of warranty by BJ Services. For these reasons, we strongly recommend that you carefully review a copy of the Terms and Conditions. If you do not have a copy of the BJ Services Price Book, you can view the Terms and Conditions on BJ Services Web Site,www.bjservices.com. By requesting that BJ Services perform the services described herein, Customer acknowledges that such Terms and Conditions are applicable to the services. Further, by requesting the services, Customer warrants that its representative on the well location or other service site will be fully authorized to acknowledge such Terms and Conditions by executing a Field Receipt or other document presented by BJ Services containing such Terms and Conditions. In the event that Customer and BJ Services have executed a Master Services Agreement covering the work to be performed, such Master Services Agreement shall govern in place of the Terms and Conditions. If you are interested in entering into Master Services Agreement with BJ Services, please contact us through the "Go BJ" button on the BJ Services Web Site. Repod Printed on: DEC-02-11 0138 Fi- BAKER • HUGHES Proposal No: 685251051A AURORA GAS INC THREE MILE CREEK UNIT#3 API # 50-283-20117-0000 THREE MILE CREEK Field 34-13N-11W Tyonek County, Alaska December 2nd, 2011 Fracturing - Post Treatment Report Quality Control Prepared for: Prepared by: Chad Helgeson Joshua Herald Aurora Gas LLC Field Engineer Bus Phone: 907.277.1003 Kenai, Alaska Service Point: Service Representatives: KENAI Rod Edwards Bus Phone: 907-776-4084 Account Manager (907)659-2329 Kenai, Alaska Fax: 99611 Bus Phone: 907-349-6518 Mobile: 907-229-6536 Powered by PowerVision Gr4105 (add) 81,-M8J N Ln ,f Co (N rn I 1 1 1 1 1 1 1 1 1 I I I I m (id6) 0£-)3egMolI (0d6) 18-38 o Ln z -- - -----7-----,.----7"11.1 ."11.116* 6 CD0 1 C U) 4 II: 0 0 •••ft. i - E RS E E CD I cin o •L d o M . V • Z O L d a mo m I � � -- .0L - d O C 2 i d L Q •V -a L d O d E V � .r Z p Z N Q y = 1 p p d 1 I 1 1 1 m > Us rn co co v N o 3 06) 0 awlczu3 (06) £-38 d d' co (N (0d6) iaisew �(eIO (06) Z£-MN 1X ` m 1 I BREAKER TEST REPORT DATE: 11/8/2011 FIELD REC#: 1001865610 CUSTOMER: Auroa WELL NAME: TMC#3 SYSTEM: Lightning 2000 ADDITIVE LOADING I ADDITIVE LOADING ADDITIVE LOADING KCL 3.0% 30.5g/L X-cide 0.4 ppt In Tank Clay-5c 1 gpt Pilot Test gpt Test No: 1 gpt Test No:2 gpt Gellant Loading: GLFC-5d 5 gpt Gellant Loading: GLFC-5d 5 gpt Gellant Loading: GLFC-5d Buffer Loading: BF-8L 2 gpt Buffer Loading: BF-8L 2gpt Buffer Loading: BF-8L 2gpt Crosslinker Loading: XLW-3: 1.5 ppt Crosslinker Loading: XLW-32 1.5 ppt Crosslinker Loading XLW-32 1.5 ppt Other Loading: BC-3 0.5 gpt Breaker Loading: BC-3 0.5 gpt Breaker Loading: BC-3 0.5 gpt Other Loading: Flo-back 0.5 gpt Breaker Loading: Flo-back 0.5 gpt Breaker Loading: Flo-back 0.5 gpt Breaker Loading: EnzymeG 2 gpt Breaker Loading: EnzymeG 2 gpt Breaker Loading: EnzymeG 2gpt Breaker Loading: GBW-18 5 ppt Other Loading: GBW-18 5ppt 11/8/2011 GBW-18 3ppt Visc. 26 BC-3 Visc. 24 '5 gpt Visc. 64 BC-3 0.5gpt Clos. 20 Clos. 25 Clos. 25 Cro. �25 Cro. 37 Cro. 35 Xlinked:ph Broken:ph Xlinked:ph Broken:ph 9.5 Xlinked:ph 1 8 Broken:ph Time.Min Bob Size Reading Temp.F Time.Min Bob Size Reading Temp.F Time.Min Bob Si Reading Temp.F 2 120 .. 2 B ,L 2 r b 70 5 115 75 5 132 36 5 54 103 10 91 90 10 B2 09 10 2 53 108 15 28 108 15 74-2 '09 15 82 49 108 20 26 108 0 `09 "0 B2 42 108 25 B2 26 108 5 'OP B2 108 30 B2 18 108 30 B, B2 29 108 35 8? 9 108 35 B2 B2 26 108 40 F 40 B2 40 B2 21 108 45 B, 45 B2 45 13 108 50 B2 50 B'2 50 7 108 5t B2 55 B2 55 3 108 60 B? 60 B2 60 7n p- -,0 rv� 70 Remarks: bad xlw 32 TEST 1 *—TEST 2 TEST 3 140 120 100 c 80 \ ..__ w 60 20 0 0 10 20 30 40 50 60 Time,Minuts Well Site Proppant Quality Control Proppant Quality Control Date November 7,2011 Customer: Aurora Sample Description 20/40 White Well TMC#3 Worked By Harold Henley Field TRUCK Truck number No. No. 2 No. Trucking company Sample taken P1 YES I—I NO Weight slip available?Attach all. n YES rl NO Nominal size from list below n YES [1 NO Is total weight for each size appropriate for job requirements? n YES ❑ NO Is the truck content acceptable? n YES I-1 NO SIEVE ANALYSIS ❑ Brady' "Type Sand If Resin Coated Sand ❑ Sintered Bauxite I] "Ottowa"Type Sand ❑ Ceramic Proppant 0 Other(specify) Nominal size from list below: Is total weight for each size appropriate for job requirement Fl yes rl No 2 Correct Color IU Low Dust IU Correct Appearance IU Oversize<0.1% 0 Fines<1.0% IU In Size>90% 2 Sample Acceptable? Sample 1 Sample 2 Sample 3 Sample 4 Size: 20/40 Size: 20/40 Size: 20/40 Size: Type: White _Type: White Type: White Type: Mesh Grams % Mesh Grams % Mesh Gramd % Mesh 3ram: 16 0.0 0.00% 16 0.00% 16 0.0 0.00% 16 #DIV/0! 20 0.3 0.66% 20 0.2 0.48% 20 0.2 0.31% 20 #DIV/0! 30 25.1 48.91% 30 31.8 63.64% 30 24.5 47.67% 30 #DIV/0! 35 18.5 36.07% 35 14.3 28.62% 35 17.5 34.02% 35 " #DIV/0! 40 5.5 10.700/s 40 2.1 4.20% 40 5.9 11.50% 40 #DIV/0! 50 1.20 2.33% 50 1.40 2.80% 50 3.20 6.24% 50 #DIV/0! Pan 0.7 1.32% Pan 0.1 0.26% Pan 0.1 0.25% Pan #DIV/0! Total 51.4 Total I 50.01 Total 51.3 Total 0.0 In Size: 95.68% In Size: 96.46"x„ In Size: 93.20% In Size: #DIV/0! Recognized proppant or gravel sizes:6/12,8/16, 12/20, 16/30,20/40, 30/50,40/70,50/70 Signature: rT 0 • Z 0 Q O J • W > H 0 0 Q c a) I a) 7) • T 0 Z H _ - 0 o } } a W H CO 0 J Z J a" Do < OW 0 O W > H CD,_ _ N 0O O CW Q N r: O cp O W y� N CO N Z - LO .0 C Q1 a a) O H Q oo0U o - Z •• z _ .2 Q w * o y.. E 0 Q W J = j 0 0 0 - 0 N J o 2 o o W W 0 ai -N cq Np O O O O O O in N a<Q W NC O O 71- -1. N (.6 h N N p arra UN- rr V W '4.4 Cr) a o I=v � )(N 0 Cl T 0 J m N Q O O O O R L Q 0 (V Q cn p 0 VVU M co n — N CO N N p E r O a a O LL C_ C C_ C Z oN R EEEE 6 r, Q o O co N J O co C a co -i) '- o OL 2 a U h Q H J m W E E o u E w W2 \ 2 a N ,— N2 aa)i • 2 W n a T - D' u a2 c HZ >- k r O(S5 ii V a w_ r) — J arc 3 = arai a) f) 0_ U 0 W > U) U) °a aL ' a) a --- a E rn o c E Q m rY r< C • H D a o E as i o E _ 9 3 U H - = N E U) rn d o arH cpo a ° o = y @ili> O 6 E2 0 a E L .0 (0 p C a) C U Cl a C E a°) .� a o _a w a o -8 5 co E E E E IL C _Ne c � o H E p co if_ c0 n3 co Q 0 L c6 7 c0 t a) co m co a) c0 c0 D J J J 0 N i J a) 0 a) H UU) u) — OOU) 1dim Z0U) U) mXXX cn > aXH Q tY Operator: AURORA G JC IG Well Name: THREE MILE CREEK UNIT#3 BAKER Date: October 27, 2011 HUGHES Proposal No: 685251051A PRODUCT DESCRIPTIONS BC-3 BC-3 is a clear, colorless liquid that is designed to assist the degradation of alkaline pH fracturing fluids. Usage can be from 70 deg F to 300 deg F (21 deg C- 149 deg C)when proper testing is performed. It can be used with enzyme breakers to lower pH of the system and allow the enzymes to work more effectively without damaging the enzymes. BF-8L A liquid pH control agent used to adjust fracturing gels into the pH range of 8.5 to 10.5. This product was designed to retain its buffering capacity at high temperatures. Clay Master-5C A concentrated low molecular weight polyamine used in water, brine or acids to protect the formation against damage due to clay swelling, sloughing and migration. Enzyme G-1 A patented, polymer specific enzyme breaker custom formulated to degrade polymer into non-damaging components. Flo-Back 30 Recovery of aqueous fracturing fluids can pose special problems, particularly in tight reservoirs with low bottomhole pressures. Flo-Back 30, a non-ionic liquid surfactant, relieves those problems by substantially increasing the fluid recovery rate for all aqueous fracturing fluids, including foamed, gelled and crosslinked systems, as well as matrix acidizing fluids. GBW-18 An oxidative breaker formulated to degrade polymers used in fracturing, workover and remedial treatments. It is used in moderate temperatures. An additional catalyst allows its use at low temperatures. GLFC-5D A high yield guar gum gelling agent slurried in an environmenatlly friendly carrier. Used to prepare hydraulic fracturing fluid systems. Potassium Chloride A granular salt used to reduce clay swelling caused by water-base stimulation fluids. Sand,White,20/40 An excellent quality, well rounded quartz sand, commonly known as "Ottawa". Color variation, which has been construed as less than desirable, is common for these sands and has no apparent impact on their strength. It is used in low to moderate closure pressure situations. XLW-32 A liquid Borate crosslinker(Boric Acid) used in gel systems. Xcide-207 A non-ionic isothiasolin bacteriacide in a convenient, solid granular form. It provides broad spectrum control of slime forming and sulfate-reducing bacteria in oilfield waters. Repoli Punted on December 2 2011 4 38 PM G,4163 Have more questions?You can find us at: http://www.bakerh u g hes.com/products-and-services/press ure-pumping Operator Name: AURORA GAS Nu • Well Name: THREE MILE CREEK UNIT#3 HUGHES Date: October 27, 2011 "' S Proposal No: 685251051A End of Report Repoli Panted on December 2 2011 4 Grlast Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent: Wednesday,August 06,2014 11:58 AM To: gpollock@aurorapower.com Cc: 'McMains, Stephen E (DOA) (steve.mcmains@alaska.gov)'; Guhl, Meredith D (DOA) Subject Three Mile Creek#3 (PTD 211-071) George, I have the 10-407 in hand..could you please send the vendor cementing and hydraulic frac reports. Also, do you have some kind of summary sheet for the flowback? Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226)or(Guy.schwartz@alaska.gov). 1 Aurora Gas, LLC August 1, 2014 ®r���`I ED Mr. Steve McMains i�►G V Alaska Oil and Gas Conservation Commission AUG 0 4 2014 333 West 7th Avenue, Suite 100 Anchorage,AK 99501 AOGCC Re: Three Mile Creek#3 Well Completion Report AOGCC PTD 211-071 & Sundry Approval 311-333 Dear Mr. McMains: Aurora Gas, LLC (Aurora)drilled the Three Mile Creek#3 (TMC3)development gas well in late 2011. This well is not tied into production facilities nor has it produced any significant quantity of gas. The well was spud on September 29,2011 under Permit to Drill 211-071 and total depth was reached on October 20,2011.Aurora's application for Sundry Approval(311-333)to conduct a two stage frac was approved on November 7,2011 and executed on November 9, 2011. Aurora attempted to flow back and test the well; however,these efforts were not successful. This submittal includes the Well Completion Report(Form 10-407),the daily operations summary the final well bore diagram. All required logs and technical reports have been previously submitted. Let me know if any further information is required for AOGCC files to close this matter. Regards, orge Pollock Manager, Production Operations&Engineering Enclosures: Form 10-407 Operations Summary Well Bore Diagram 4645 Sweetwater Boulevard, Suite 200 * Sugarland,TX 77479 * (832) 939-8991 1400 W Benson Blvd, Suite 410 * Anchorage, AK 99503 * (907) 277-1003 RECEIVED STATE OF ALASKA ALASK,- OIL AND GAS CONSERVATION COMMI,,.,ION AUG 0 4 2014 la.WeIlStaWOil ELL COMPLETION OR RECOMPLETION REPORT AND LOGS P ❑ Gas Q' SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ 1 b.Well Class: 20AAC 25.165 20AAC 25.110 Development 2• Exploratory ❑ GINJ ❑ WINJ ❑ WAG ❑ WDSPL❑ No.of Completions: p.) Service ❑ Stratigraphic Test ❑ 2.Operator Name: 5.Date Comp.,Susp.,or 12. Permit to Drill Number: Aurora Gas, LLC Aband.: /C/2.7/Z01I 211-071• 3.Address: 6.Date Spudded: 13.API Number: 1400 W Benson Blvd,Suite 410,Anchorage,AK 99503 9/29/2011 50-283-20156-00-00' 4a.Location of Well(Governmental Section): 7. Date TD Reached: 14.Well Name and Number: Surface: 367'FEL,1244'FSL,Sec.34 T 13N,R 11W SM 10/20/2011 Three Mile Creek#3• Top of Productive Horizon: 8. KB(ft above MSL): 304' 15. Field/Pool(s): 540'FEL&1374'FSL,Sec.34,T13N,R11W,SM GL(ft above MSL): 288' Three Mile Creek Field Total Depth: 9.Plug Back Depth(MD+TVD): Beluga Gas Pool 1981'FEL&1925'FSL,Sec.34,T13N,R11W,SM 5040'MD/4665'TVD 4b.Location of Well(State Base Plane Coordinates,NAD 27): 10.Total Depth(MD+TVD): 16. Property Designation: Surface: x- 285,835 y- 2,621,670 Zone- 4 5159'MD/4771'TVD ADL-388233 _ TPI: x- 285,662 y- 2,621,800 Zone- 4 11.SSSV Depth(MD+TVD): 17. Land Use Permit: Total Depth: x- 284220 y- 2622351 Zone- 4 NA Lease Agreement 18. Directional Survey: Yes 0 No ❑ 19.Water Depth,if Offshore: 20.Thickness of Permafrost MD/TVD: (Submit electronic and printed information per 20 AAC 25.050) NA (ft MSL) NA 21. Logs Obtained(List all logs here and submit electronic and printed information per 20AAC25.071): 22.Re-drill/Lateral Top Window MD/TVD: f Previously submitted. LAs!r1 neuJ.�esc t Kprt FMt , P X NA 23. CASING,LINER AND CEMENTING RECORD WT.PER SETTING DEPTH MD SETTING DEPTH TVD AMOUNT CASING FT GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE CEMENTING RECORD PULLED 13 3/8" 72# K-55 15' 80' 15' 80' Driven NA NA 9 5/8" 36# - J-55 Surface 800' Surface 800' 12 1/4" 12 ppg,Type 1 216 sx 5 1/2" 15.5# J-55 Surface 5116' Surface 4706' 7 7/8" 12/14.8 ppg,Class G 656 sx 24.Open to production or injection? Yes 0 No ❑ 25. TUBING RECORD If Yes,list each interval open(MD+TVD of Top and Bottom; Perforation SIZE DEPTH SET(MD) PACKER SET(MD/TVD) Size and Number): 2 7/8" 3560' 1)4987'-4992'MD/4610'-4615'TVD;2)4384'-4394'MD/4080'-4090'TVD;3) 3966-3986'MD/3728'-3748'TVD;4)3626-3646'MD/3416'-3436'TVD;5) 26. ACID,FRACTURE,CEMENT SQUEEZE,ETC. 3410'-3420'MD/3217'-3227'TVD;6)3362'-3372'MD/3146'-3156'TVD;7) Was hydraulic fracturing used during completion? Yes 0 No ❑ 3079'-3084'MD/2894.-2899'TVD;8)2616'-2626'MD/2510'-2520'TVD:9) DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED 2512'-2532'MD/2398'-2418'TVD; 10)2386-2416' MD/2310'-2340'TVD; 11) 2188'-2208'MD/2128'-2148'TVD; 12)2112'-2132'MD/2083'-2103'TVD; 13) 3926-3986' 79k#20/40 sand+11k#12/20 flexsand 1773'-1778'MD/1759'-1764'TVD' 14 1704'-1724'MD/1683'-1703'TVD 3362'-3420' 77k#20/40 sand+11k#12/20 flexsand QQMPI.Mit n e 27. 1 ,r PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): Never flowed • - NA Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: Test Period Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 24-Hour Rate - 28. CORE DATA Conventional Core(s)Acquired? Yes ❑ No 0 Sidewall Cores Acquired? Yes ❑✓ No ❑ If Yes to either question,list formations and intervals cored(MD+TVD of top and bottom of each),and summarize lithology and presence of oil,gas or water (submit separate sheets with this form,if needed).Submit detailed descriptions,core chips,photographs and laboratory analytical results per 20 AAC 25.071. Previously submitted l RBDMS AUG - 6 20141 Form 10-407 Revised 10/2012 2- y r CONTINUED ON REVERSE -ham 8')414' Submit original only 6 , .,- /. /cf. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? 0 Yes ❑ No If yes,list intervals and formations tested, BELUGA briefly summarizing test results.Attach separate sheets to this form,if Tsuga 2-4.1 2156' 2097' needed,and submit detailed test information per 20 AAC 25.071. Tsuga 2-4.2 2320' 2245' Well test attempted. Never flowed.Well has never flowed or produced to Tsuga 2-4.3 2492' 2398' date. Tsuga 2-4.4 2582' 2460' Tsuga 2-4.5 3010' 2873' Tsuga 2-5.1 3348' 3161' Tsuga 2-5.2 3394' 3225' Tsuga 2-5.3 3622' 3408' Tsuga 2-5.4 3882' 3631' Tsuga 2-6 4050' 3781' Tsuga 2-7 4770' 4421' Formation at total depth: Belgua Tsuga 2-7 I 31. List of Attachments: 32. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: / Email: •.ollock • aurora.ower.com Printed Name: George Pollo j ' Title: Manager, Production Operations&Engineering Signature: Phone: 907-277-1003 Date: 8/1/2014 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1b: Classification of Service wells: Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection,Observation,or Other.Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI(Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced,showing the data pertinent to such interval). Item 27: Method of Operation: Flowing,Gas Lift,Rod Pump,Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-in,or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 10/2012 AURORA GAS, LLC THREE MILE CREEK NO. 3 AOGCC Permit To Drill No. 211-071 (API No. 50-283-20156-00) OPERATIONS SUMMARY 9/24/2011—Level pad. Set rig containment liner and lay rig mats on liner. 9/25/2011—MI and RU AWS#1 rig. 9/26/2011—Continue MI and RU AWS#1. Raise derrick. 9/27/2011—Continue RU AWS#1. 9/28/2011—Finish RU AWS#1 including gas detectors and test. Berm containment around rig. Conduct diverter draw down test. Mix 200 bbls 10 ppg mud. 9/29/2011—RU Sperry equip and MU bit/motor. Strap and drift casing. RIH to drivepipe shoe and pump to surface test equip. PU swivel & 1 jt HWDP.Tag at 93' and break circ. Drill to 116'. 9/30/2011—Drill to 178'. Circ hole clean, lay down HWDP, and set swivel back. MU 2 flex collars and jars, MU swivel. Drill to 542' with coal seam at 451'. 10/1/2011— Drill to 667' and work on shaker. Resume drilling to 900' at lower rate with coal seam 790'to 859'. Circ bottoms up, pump weighted high visc sweep. Back ream out 4 singles & set swivel back. POOH to conductor shoe. f�;-,, A- 10/2/2011— RIH MU swivel. Circ hole clean 600 BPM at 800 psi. Set swivel back, POOH, and lay '5':-::19 down motor. Run 21 jts 9 5/8" casing to 886'. Circ hole clean 6 BPM at 800 psi while thinning c-ef back mud for cement. RU BJ cement unit. Pump 20 BBL spacer 12 ppg, 106 BBL 14.5 ppg cement, 65 BBL displacement mud. Good cement back to surface, 30 BBL returns. SI well with 350 psi. 10/3/2011—Clean out diverter and flowline. RD cement lines, GBR, 12" vent line & knife valve. ND diverter. Final cut on 9 5/8" casing and weld casing head. RU choke.Test weld &0-ring seat to 1500 psi 15min. 10/4/2011— NU spool, double gate, annular, flow nipple, kill line, degasser. PU test joint &test plug. Test BOP. Pull test plug. 10/5/2011—Set back swivel, RU fill up hose,floor&set mouse hole. MU BHA &surface test MWD. RIH circ casing clean.Test casing. Fail.Troubleshoot leak. Stand back Kelley. POOH. PU RTTS RIH to 785'. Set RTTS. 10/6/2011—RU to test (below RTTS). Fail. Change out test pump bleeder valve.Test 9 5/8" casing to 1500 psi for 30 min. Good test. RD test equipment. POOH & lay down RTTS. PU BHA& RIH. Tag @ 790'. Drill cement and shoe track from 790'to 875'. 10/7/2011—Continue drill cement and shoe track from 875'to 900'. Circ&clean hole. Pull into shoe & clean pits. Displace spud mud from hole. Circ to even out weight. Drill from 900' to 920' & circ hole clean. LD 2 jts & pull into shoe. RU and perform LOT. EMW= 16.22. RIH to 902'. Drill to 963'. 10/8/2011—Drill to 1408'. Circ hole clean. Make wiper trip to shoe. RIH from 880'to 1340' & wash to 1408'. Drill to 1533' with scattered coal seams with clay. 10/9/2011—Drill to 1910' &survey. Circ hole clean. POOH to 1426' & make 500' wiper trip (tight @ 1630'). Drill to 2066' &survey. 10/10/2011—Drill to 2312' &survey. Circ&clean hole. POOH & make 500' wiper trip (tight @ 1900' & 2100'). Wash 2 jts to bottom. Drill to 2600'. 10/11/2011—Drill to 3008' & survey. Pump 25 BBL high visc sweep & circ to clean hole. POOH from 3008' to 2376'. Pull slow to swab. Tight @ 2750', 2590', 2500', 2400' & 2376'. 10/12/2011—Swivel up& ream 2376'to 2314'. Pull 2 jts &set back. POH 2251'to 1937' ( tight @ 1926'). Swivel up& ream 1926'to 1874'. Set back swivel. POOH. LD motor& bit. MU BHA. RIH to 869'.Test pump#2 & MWD. Service liners & swabs on mud pump#1. 10/13/2011—RD circulating head. RIH from 869'to 3008' working through tight spots 2750' & 2590'. Circulate &condition mud. Drill to 3390' &survey. 10/14/2011—Drill to 3511' &survey. Pump 18 BBL high visc sweep &circ to clean hole. POOH & make 500' wiper trip. Drill to 3822' &survey. 10/15/2011—Drill to 4011' & survey. Circ high visc sweep (100%cuttings increase) & make 500' short trip to 3565'. Swivel up &work through tight spot at 3565'. POOH to 3511'. Circ hole clean & RIH to 4011'. Drill to 4220' &survey. 10/16/2011—Drill to 4319' & survey. Drill to 4487' &survey. Pump sweep around & make short trip to 3980'. RIH to 4420'. Kelley up &wash from 4420'to 4487'. Drill to 4580' & survey. 10/17/2011—Drill to 5021' &survey.TVD =4652'. 10/18/2011-Drill to 5112' &survey. Circ to condition mud. Drill to 5142' &survey. Make short trip to 4300'. Circ to condition mud. Pump sweep&set back swivel. POOH from 5142' to 3839' (pump dry job). POOH from 3839'to 2942' (pull slow not to swab, wipe back thru 10 spots with 15-20k overpull). 10/19/2011-POOH from 2942' to 558'. POOH BHA#5 from 558'.Set test plug. Full BOP test. Pull test plug. RU Schlumberger wireline. RIH. Stopped at 1910'. POOH. Attempt RIH past tight spots (NO GO). LD AIT&add stubby holefinder. RIH &work thru 1960. RD wireline. PU BHA. RIH to 160'. 10/20/2011-RIH with clean out assembly to 2000'. POOH from 2000'to 1855'. Swivel up and ream from 1855'to 1981'. Set back swivel and continue RIH to 5124'. Swivel up &wash to 5142'. Circ to condition mud. Drill to 5159'. Circ hole clean. Ream out 2 singles & rack swivel back. POOH to 2781'. Circ to clean hole. RD circulating head. POOH from 2781'. LD bit, stab, bumper sub. 10/21/2011-LD float sub, motor, stab. Clean floor. RU Schlumberger wireline. MU & RIH 1) triple combo log, 2) FMI log 3) XPT log. 10/22/2011-finish XPT log run. Rehead. Run sidewall core samples. RD wireline. MU BHA. RIH to 5119'. Swivel up &wash from 5119'to 5159'. Circ thick mud. Pump 20 BBL high visc sweep to clean up hole. Pump dry job. LD swivel. POOH from 5159'to 4900'. 10/23/2011-Continue POOH. LD drill pipe. LD BHA. Remove equip from rig floor. Change pipe rams to 5 %" and test. RU GBR equip. RIH 5 1/2" casing. Check floats. RIH to 846'. RU circulate casing volume. Continue RIH from 846'to 2284'. 10/24/2011-Continue to RIH from 2284'to 3664'. Circulate annulus volume. RIH from 3664'to 5149'. RD GBR equip. Circulate &condition, clean pits, build brine. Pump 2 BBL water, test lines to 3000 psi. Drop plug kick out with 1 BBL water. Pump 40 BBL SealBond sweep 11.5 ppg. Pump (1Ili 89,BBL 12 ppg lead cement (type 1, 0.3%A-2, 0.1%ASA-301, 20% MPA-1, 2% KCI, 0.05%Static -' free+ 1 ghs FP-6L, 1% FL-63, 0.4% BA-10). Pump 189 BBL 14.8 ppg tail cement (type 1, 0.1%R-3, 1%CD-32, 1% BA-10, 0.3%SMS, 2% KCI +0.05%Static free + 1 ghs FP-6L). Drop second plug-- kick out with 5 BBL water. Displace 116.25 BBL. Bump plug with 1950 psi. Check floats. RD cement equip. Rinse and flush stack. 10/25/2011-Lift stack&set slips. Rough cut 5%" casing. LD spacer spool. Final cut 5 Y" casing & dress. NU 7 1/16"tubing spool. NU BOP. Change pipe rams to 2 7/8". Clean out blind rams. Set test plug.Test to 3000 psi. Set wear ring and mouse hole. RU to run tubing. RU floor to run tubing. MU BHA. RIH 2 7/8" tubing, bit&scraper to 449'. 10/26/2011—PU 2 7/8"tubing. RIH to 5040'. Circ hole volume.Test casing to 2000 psi 30 min. Build 30 BBL 10.6 ppg brine. RU filter unit. Filter brine with 25 micron, 10 micron & 5 micron filters successively. Circulate hole volume. POOH with tubing from 5040'to bit. RU Schlumberger wireline. 10/27/2011—RIH. Run USIT logs. RD flow nipple. RU shooting flange. RU lubricator. Rehead wireline. PU lubricator. MU gun #1. RIH to 300'.Test lubricator to 2000 psi. RIH gun#1 & perf from 4987'to 4992' (0 BBL). RIH gun #2 & perf from 4384'to 4394' (0 BBL). RIH gun #3 & perf rL` ,� from 3966'to 3986' (0 BBL ). Rr T10/28/2011—RIH gun #4& perf from 3626'to 3646' (0 BBL). RIH gun #5 & perf from 3410'to 3420' (0 BBL). RIH gun #6& perf from 3362'to 3372' (0 BBL). RIH gun #7 & perf from 3079' to 3084' (0 BBL). RIH gun #8& perf from 2616'to 2626' (0 BBL). RIH gun #9 & perf from 2512' to 2532' (OBBL). RIH gun #10 & perf from 2386' to 2406' (0 BBL). RIH gun #11 & perf from 2406' to 2416' (0 BBL). RIH gun #12 & perf from 2188'to 2208' (OBBL). RIH gun #13 & perf from 2112' to 2132' (0 BBL). RIH gun #14 & perf from 1773'to 1778' (0 BBL). RIH gun #15 & perf from 1704' to 1724' (1/2 BBL). RIH gauge ring/junk basket with 4.6" OD. 10/29/2011—POOH gauge ring&junk basket. MU Arrowpack packer with tailpipe. RIH set at 4100'. POOH. RD Schlumberger wireline. RD shooting flange. RU flow nipple and trip tank lines. Set wear ring. MU 4%" bit, scraper and XO.RIH 2 7/8"tubing to 4087'. LD 15 stands. Circ hole clean using 25 micron filter. POOH. Drift tubing, LD bad joints and pull wear ring. MU completion assembly. 10/30/2011—Continue RIH 2 7/8"tubing&completion assembly. MU tubing hanger. Pump 26 BBL corrosion inhibited brine down annulus.Attempt to land hanger, rejected 1' high in 11" by 7 1/16" DSA. Order RTTS packer with storm valve. LD hanger. Set PLS packer at 3490'. Release off XL on-off tool. LD jt 108, 8' & 2' pups, and jt 107. MU RTTS with storm valve. RIH & set RTTS at 20' hang off string. ND flow nipple and BOP. Change out 11" by 7 1/16" DSA.Test run tubing hanger. NU flow nipple & BOP.Test flanges to 250 and 3000 psi. Pull RTTS & unseat PLS packer. MU hanger&space out. Set PLS packer at 3534'. Land hanger. RU Pollard slickline. RIH set PX plug at 3302'. POOH. Test tubing to 1500 psi_Bled off. Retest. Bled to 0 psi. Thr 10/31/2011—RU Pollard. Pull & reset new PX plug.Test tubing to 1500 psi. Good test. Pull PX plug. RD Pollard. 11/1/2011— RD AWS#1 • AOGCC Sundry Approval No. 311-333 (Issued November 7, 2011) STIMULATION ACTIVITY SUMMARY 11/8/2011— MI Baker frac equip & begin RU. 11/9/2011—Continue RU frac equip. Conduct job safety meeting. Conduct pressure test of mainline and backside.Test mainline to 8290 psi. Good test.Test backside to 3500 psi. Good test. Frac stage 1:40'total perf interval (3926'to 3946' and 3966'to 3986'), surface treating pressure 13 14 psi max, total rate 15 BBL/min max, pump time 47 minutes, 4200 gallons of 3% KCI, frac fluid 21600 gallons lightning 2000, proppant 90000 pounds total, 78750 pounds 20/40 white sand & 11250 pounds 12/20 Flexsand MSE. Drop ball &shift sleeve for frac stage 2. Frac stage 2: 20' total perf interval (3362' to 3372' and 3410'to 3420'), surface treating pressure 3537 psi max, total rate 15 BBL/min max, pump time 47 minutes, 4200 gallons of 3% KCI,frac fluid 21530 gallons lightning 2000, proppant 90000 pounds total, 77088 pounds 20/40 white sand & 11013 pounds 12/20 Flexsand MSE. RD Baker frac equip. 11/10/2011—MO Baker frac equip. RU Pollard slickline. RIH pull frac door at 3399'. 11/11/2011—RIH close frac door. POOH. Pin sheared. Set PX plug in X-nipple at 3296'. Open sleeve at 2317'. Swab down to 780'. No flow. Zs71, - 11/12/2011—Continue swab down to 1000'. No flow. Close sleeve at 2317' &open sleeve at 1742'. Swab down to 750'. No flow. Close sleeve at 1742'.Tag sand at 3260'. Bail sand from 3260' to 3273'. 11/13/2011—Continue to bail sand from 3273'to 3294'. Slickline parts with GS latched attempting to pull PX plug. 11/14/2011-125 psi on well. Retrieve wire from well. 11/15/2011—No pressure on well. Fish tool string&GS out of well. RIH with GS & pull PX plug. 11/16/2011—Swab down to 490'. 36BBL to surface. 11/17/2011-160 psi on well, bled off. Swab down to 970'.46 BBL to surface.Total fluid to surface 430 BBL. 11/18/2011—Tag fluid at surface. Swab down to 32'. Open frac door at 3399'. Swab down to 710'. Fluid rising. 11/19/2011—Tag fluid at 76'. Swab down to 870'.48 BBL to surface. 11/20/2011—Tag fluid at 60'. Swab down to 800'.45 BBL to surface. 11/21/2011 — 25 psi on well. Tag fluid at 240'. Swab down to 570. 8 BBL to surface. Close frac door at 3399'. Open sleeve at 2317'. Tag fluid at 320'. Swab down to 500'. Gas kicks return 18 BBL to surface. Tag fluid at 400'. Swab down to 770'. 43 BBL to surface with limited flowback. Set PX plug at 2601'. 110 psi on well. Attempt to flow well thru separator. Bled off. SI well. 11/22/2011 — 452 psi on well. Attempt to flow well thru separator. Pressure bled off in 15 minutes. 1 BBL flowback.Total fluid to surface since frac 629 BBL. RD Pollard slickline. t. 2 7/8 6.5#8rd EUE J-55 Tubing Aurora Gas, LLC • Three Mile Creek#3 PTD#:211-071 13-3/8"72#Structural API#-50-283-20156-00-00 , Conductor driven to 80GL RKB 14ft (Oct 31,2011) 9-5/8"36#Surface Casing set at 886' Cement w/12.0 ppg Type I Accelerated Drill 12-1/4"Hole to 901' 2-7/8" x 5-%2"annulus displaced with 9.6#inhibited brine Hydraulic Packer @ 1663' 1704-24' 1773-78' -"— Sliding Sleeve XD @ 1742',x-nipple Hydraulic Set Packer @ 1943' Weatherford Expansion joint 6ft travel @ 2112-20&2126-2132 �� 2081' 2188-2208' El/ 2386-2416' —i Sliding Sleeve XD @ 2312'MD w/x-nipple Hydraulic Packer @ 2484' 2512-32' 2616-26' Sliding Sleeve XD @ 2594'w/x-nipple El§ Sliding Sleeve XD @ 3075'w/x-nipple 3079-84' Hydraulic Packer at 3,182' 3362-72'&3410-20'Frac with X-Nipple 2313"ID @ 3,288' 2 i.)`, 88,000 lb of sand Frac door @ 3,391',1.5"ball seat Mechanical Packer @ 3532'w/On- Off Tool w/2.31 profile X nipple 3926-46'&3966-86'Frac with i W/L Entry Guide @ 3577' 90,000 I b of sand Black Cat Mechanical Packer @ 4,100'w/2313 profile X nipple at 4384-94' g ��— 4,110',ceramic burst disk @ 4,120' 4987-92' PBTD @ 5,040' 5'A"15.5#J-55 Casing to 5149'(MD) Drilled 8-1/2"Hole to 5,159'MD -Aurora Gas, LLC www.aurorapower.corn April 16, 2012 Makana Bender Natural Resource Technician Alaska Oil and Gas Conservation Commission 333 W. 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Well Data Submittal, Three Mile Creek#3 Aurora Gas, LLC has included in this package the following documents and electronic files for Alaska Oil and Gas Conservation Commission for the Aurora Gas LLC Three Mile Creek #3 Well, API#API# 50-283-20156-00. Paper Logs (TMC#3) 1) Schlumberger Formation Micro-Imager Electronic Documentation(TMC#3) 2) Schlumberger—Formation Micro-Imager(PDS Graphics) If you have any questions or require additional information, please contact me or Ed Jones at (907) 277-1003. Sincerely, AURORA GAS, LLC /1//1#1‘- Chad Helgeson Manager—Production Operations & Engineering enclosures 1400 West Benson Blvd.,Suite 410 •Anchorage,AK 99503 •(907) 277-1003 •Fax: (907) 277-1006 6051 North Course Drive, Suite 200 •Houston, TX 77072 •(713) 977-5799 •Fax: (713) 977-1347 � 1/ - 6-7 I Aurora Gas, LLC 21�42�3 www.a urora po wer.corn 4111 March 20, 2012 v Makana BendercPQ Natural Resource Technician �� Alaska Oil and Gas Conservation Commission `< c."0,c."0,/c, 333 W. 7th Ave., Suite 100 < . Anchorage, Alaska 99501 �. RE: Well Data Submittal, Three Mile Creek#3 Aurora Gas, LLC has included in this package the following documents and electronic files for Alaska Oil and Gas Conservation Commission for the Aurora Gas LLC Three Mile Creek #3 Well, API#API# 50-283-20156-00. Paper Logs (TMC#3) 1) Schlumberger Xpress Pressure Tool (2 logs) 2) Schlumberger Ultra-sonic Imaging Tool—Cement Evaluation 3) Schlumberger Platform Express 4) Schlumberger Perforating Record 5) Halliburton 2"TVD Formation Evaluation Log 6) Halliburton 2"MD Formation Evaluation Log 7) Halliburton 2"MD Drilling Evaluation Log 8) Halliburton 5"MD Formation Evaluation Log Electronic Documentation(TMC#3) 9) Schlumberger a. Perf, PEX, USIT,XPT Long, XPT Short(PDS Format) b. USI, FMI, PEX(LAS Format) 10) Halliburton a. End of Well Report b. Final Log Files c. ASCII LAS Files d. ADI Database e. Log Viewers 11) Halliburton Surface Data Logging End of Well Report(CD Enclosed) 6051 North Course Drive, Suite 200•Houston,Texas 77072•(713)977-5799•Fax(713) 977-1347 1400 West Benson Blvd., Suite 410•Anchorage,Alaska 99503• (907)277-1003•Fax(907)277-1006 March 20th,2012 Page 2 If you have any questions or require additional information, please contact me or Ed Jones at (907) 277-1003. Sincerely, AURORA GAS, LLC Chad Helgeson Manager—Production Operations & Engineering enclosures 07 1 Aurora Gas, LLC www.a urora po wer.corn March 20, 2012ee Makana Bender �triQ Natural Resource Technician Alaska Oil and Gas Conservation Commission �� ®e 333 W. 7th Ave., Suite 100 'e' Anchorage,Alaska 99501 RE: Well Data Submittal, Three Mile Creek#3 Aurora Gas, LLC has included in this package the following documents and electronic files for Alaska Oil and Gas Conservation Commission for the Aurora Gas LLC Three Mile Creek #3 Well, API#API# 50-283-20156-00. Paper Logs (TMC#3) 1) Schlumberger Xpress Pressure Tool (2 logs) 2) Schlumberger Ultra-sonic Imaging Tool—Cement Evaluation 3) Schlumberger Platform Express 4) Schlumberger Perforating Record 5) Halliburton 2"TVD Formation Evaluation Log 6) Halliburton 2"MD Formation Evaluation Log 7) Halliburton 2"MD Drilling Evaluation Log 8) Halliburton 5"MD Formation Evaluation Log Electronic Documentation(TMC#3) 9) Schlumberger a. Perf, PEX, USIT,XPT Long, XPT Short(PDS Format) b. USI, FMI, PEX(LAS Format) 10) Halliburton a. End of Well Report b. Final Log Files c. ASCII LAS Files d. ADI Database e. Log Viewers 11) Halliburton Surface Data Logging End of Well Report (CD Enclosed) 6051 North Course Drive, Suite 200•Houston,Texas 77072•(713) 977-5799•Fax(713) 977-1347 1400 West Benson Blvd., Suite 410•Anchorage,Alaska 99503• (907)277-1003•Fax(907)277-1006 • Page 1 of 1 Regg, James B (DOA) From: Chad Helgeson [chelgeson@aurorapower.com] dire'?re C!'ee-k `3 Sent: Tuesday, October 11, 2011 4:58 PM P71, 2(( 67( C To: 'Aurora Company Man'; 'Ed Jones'; Regg, James B (DOA) Cc: jbwest@q.com; 'David Boelens'; Borenin@mtaonlie.net Subject: annular piston leak I talked with Jim Regg at the state about the leaking piston on the annular. The state is okay with us leaving this annular on the stack with the valve to the piston in Neutral. When we are done drilling this Three Mile Creek#3 well and rig down the stack we need to repair it before we start another well. The annular must be in a functioning mode, and if there is any reason that the annular will not close properly or in the required amount of time we will need to fix it. Thanks Chad Helgeson 10/12/2011 ,. c= �,O A ._..,ASEA 1S ._ [1, SEAN PARNELL,GOVERNOR ALASKA. OIL A1VI) GAS 333 W.7th AVENUE,SUITE 100 CONSERVATION COMDIISSION ANCHORAGE,ALASKA 99501-3539 PHONE (907)279-1433 FAX (907)276-7542 J. Edward Jones President Aurora Gas, LLC ` ( 0 7/ 1400 West Benson Blvd., Suite 410 1 Anchorage, AK 99503 Re: Three Mile Creek Gas Field, Beluga Gas Pool, Three Mile Creek #3 Sundry Number: 311-333 Dear Mr. Jones: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, 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. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, .e—v)..„70 .______ Daniel T. Seamount, Jr. Chair DATED this , day of November, 2011. Encl. 47 Page 1 of/ Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Friday, October 28, 2011 1:26 PM To: 'Ed Jones' Subject: RE: RE: TMC 3 Stimulation (211-071)CORRECTION That does make some difference. I will examine the proposal. I will be out Monday and Tuesday, but I don't think that will affect getting the approval finished. We will look forward to the hard copy. I will advise regarding the BJ design. ` Tom � L S- �r�\v From: Ed Jones [mailto:jejones@aurorapower.com] Sent: Friday, October 28, 2011 12:23 PM To: Maunder, Thomas E (DOA) Cc: 'David Boelens'; 'Chad Helgeson'; 'Aurora Company Man' Subject: RE: RE: TMC 3 Stimulation (211-071) CORRECTION Tom, We are scheduled for Monday, November 7th, not the 11th' so we would appreciate approval before time. Sorry about that. Regards, Ed J. Edward Jones Executive Vice President, Eng. &Ops. Aurora Gas, LLC 6051 North Course Dr.,Ste 200 Houston,TX 77072 281-495-9957 (0) 713-899-8103 (C) From: Ed JsrLes [mailto:jejones@aurorapower.com] Sent: Friday, Ottober 28, 2011 2:21 PM To: 'Maunder,Thom. (DOA)' Cc: 'David Boelens'; 'Chao .elgeson'; 'Aurora Company Man' Subject: RE: TMC 3 Stimulati.• 211-071) Tom, As per your email to David Boelens o I/7/2011 regarding the frac stimulation of Three Mile Creek#3 (211-071),attached is a Sundry Approval request o e work, along with a well-bore diagram of the planned completion (to be run this weekend), and a detailed pro s ure for the frac.The plan is very similar to the frac done on the TMC#2 last fall, except that we are planning onl tages, using one frac sleeve (HES Frac Door). Please let me know if you need more information (e.g., the BJ desig heets)or have any questions (by return email is best today, as I have only the rig sat. phone, but by cell phone [ -899-8103] or email after today). We have scheduled the frac for Monday, Nov. 11th, due to the Baker BJ equipmen :-ing available now and the need for it elsewhere in the immediate future. Thus, we request prompt approval. I am in the field (well site today), but we will hand deliver a hard-copy original o to the AOGCC on Monday, Oct. 31st. We are perforating the well today, and the frac design was not finalized unti -sterday, knowing the actual perfs, so we were unable to get a firm procedure to you until now—we apologize •r the 11/2/2011 Page 1 of 1 Maunder, Thomas E (DOA) From: Ed Jones [jejones@aurorapower.com] Sent: Friday, October 28, 2011 11:21 AM To: Maunder, Thomas E (DOA) Cc: 'David Boelens'; 'Chad Helgeson'; 'Aurora Company Man' Subject: RE: TMC 3 Stimulation (211-071) Attachments: TMC 3 Stimulation Application for Sundry Approval.pdf; TMC#3 Proposed completion diagram rev.doc; 2011 Frac Procedure TMC 3 V 1.1 102811.doc Tom, As per your email to David Boelens of 10/7/2011 regarding the frac stimulation of Three Mile Creek#3 (211-071),attached is a Sundry Approval request for the work, along with a well-bore diagram of the planned completion (to be run this weekend), and a detailed procedure for the frac.The plan is very similar to the frac done on the TMC#2 last fall, except that we are planning only 2 stages, using one frac sleeve (HES Frac Door). Please let me know if you need more information (e.g.,the BJ design sheets)or have any questions (by return email is best today, as I have only the rig sat. phone, but by cell phone [713-899-8103] or email after today). We have scheduled the frac for Monday, Nov. 11th, due to the Baker BJ equipment being available now and the need for it elsewhere in the immediate future. Thus,we request prompt approval. I am in the field (well site today), but we will hand deliver a hard-copy original of this to the AOGCC on Monday, Oct. 31St. We are perforating the well today, and the frac design was not finalized until yesterday, knowing the actual perfs, so we were unable to get a firm procedure to you until now—we apologize for the short time frame, but we request an expedited approval. Thank you. Ed J. Edward Jones President Aurora Gas,LLC 6051 North Course Dr.,Ste 200 Houston,TX 77072 281-495-9957(0) 713-899-8103 (C) 11/2/2011 vl STATE OF ALASKA 11- `I ALASKA OIL AND GAS CONSERVATION COMMISSION Of FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request: Abandon❑ Plug for Redrill❑ Perforate New Pool❑ Repair Well❑ Change Approved Program ❑ Suspend❑ Plug Perforations❑ Perforate❑ Pull Tubing❑ Time Extension❑ Operations Shutdown❑ Re-enter Susp.Well❑ Stimulate 0 • Alter Casing❑ Other: ❑ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Aurora Gas, LLC Development 0 • Exploratory ❑ 211-071 • 3.Address: Stratigraphic ❑ Service ❑ 6.API Number: 1400 West Benson Blvd.Ste.410,Anchorage,AK 99503 50-283-20156-00-00 • 7.If perforating,closest approach in pool(s)opened I op 8.Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes E No ❑ Three Mile Creek#3. 9.Property Designation(Lease Number): 10.Field/Pool(s): ADL-388233 • Three Mile Creek Gas Field, Beluga Gas Pool • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD,(ft1,Z J,Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 15e� 11' 1 4771 5040, 4665 Casing Length Size MD ND Burst Collapse Structural Conductor 95' 13-3/8" 95' 95' 3700 psi 2230 psi Surface 886' 9-5/8" 886' 883' 3520 psi 2020 psi Intermediate Production 5049' 5-1/2" 5049' 4762' 4810 psi 4040 psi Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 1704'-4992' (14 interval;1683'-4620' 2-7/8" J-55 3560' Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): from top:4-HES PHL pkrs,HES PLS pkr,Black Cat mechanical—no SSSV Pkrs @ 1672',1959',2473',3204',3517',4100'MD;no SSSV 12.Attachments: Description Summary of Proposal ❑ 13.Well Class after proposed work: Detailed Operations Program Q BOP Sketch ❑ Exploratory ❑ Development 0 • Service ❑ 14.Estimated Date for 11/7/2011 15.Well Status after proposed work: Commencing Operations: Oil ❑ Gas ❑., . WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Ed Jones at 713-899-8103 Printed Name J. Ed and Jones Title President Signature y____. Phone 713-899-8103 Date 10/28/2011 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3 I'-- 33 3 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: RECEIVED Subsequent Form Required: %,iOL\ 4 \_\,a lis,I ` 1 ?OP —77"-7 / \ APPROV ;a Oil & Gas Cons.Commissi n Approved by: v. / L/ COMMISSIONER THE COMMISSION gnCnor$ ` 7/( - , 'MS Nov 7201 K1A I Form 10-403 Revised 1/2010 \ I Q I I! /., , Submit in Duplicate , " 2 7/8 6.5#8rd EUE J-55 Tubing Aurora Gas, LLC Three Mile Creek#3 PTD#: 211-071 • 13-3/8"72#Structural API#: 50-283-20156-00-00 . , Conductor driven to 80GL RKB—14ft - (to be run on Oct 29,2011) 9-5/8"36#Surface Casing set at 886' Cement w/12.0 ppg Type I Accelerated Drill 12-1/4"Hole to 901' 2-7/8" x 5-'/2"annulus displaced with 9.6#inhibited brine Hydraulic Packer @ 1672' 1704-24' •- ', 1773-78' Sliding SleeveSetPXD @ 1757' Hydraulic acker@-11975597''@ 1959' Weatherford Expansion joint 6ft travel @ 2112-20&2126-2132 - –2094' 2188-2208'1 .II 2386-2416' Sliding Sleeve XD @–2302'MD Hydraulic Packer @–2473' 2512-32' 2616-26' Sliding Sleeve XD @–2583' Sliding Sleeve XD @–3064' 3079-84' –.on • Hydraulic Packer at 3204' 3362-72'&3410-20'Frac with X-Nipple 2313"ID @ 3,339' of sand I Frac door @–3408',1.5"ball seat Mechanical Packer @ 3517'w/On- Off Tool w/231 profile X nipple 3926-46'&3966-86'Frac with W/L Entry Guide @–3560' of sand 4384-94' Black Cat Mechanical Packer @ 4100'w/2313 profile X nipple at 4110',ceramic burst disk 4120' 4987-92' PBTD @ 5,040' , 5'/2"15.5#J-55 Casing to 5149'(MD) Drilled 8-1/2"Hole to 5,159'MD / Aurora Gas, LLC THREE MILE CREEK #3 2011 POST-COMPLETION FRAC PROCEDURE Version 1.1 (10/28/11) CAPACITIES: 2-7/8"Tubing: 0.00579 bbl/ft and 5-1/2" 15.5# Casing: 0.0238 bbl/ft 5-1/2" Casing X 2-7/8"Annular Volume: 0.0158 bbl/ft. Casing ID/Drift ID is 4.950'/4.825" ; Casing vol. to deepest perf: 116.4 bbl. 8.45 ppg brine left in tbg-csg annulus. KB= 14' above GL (all depths from KB). PBTD=5040' MD/4664' TVD; TD=5159'MD/4771' TVD PROPOSED TUBING/COMPLETION: Tubing ID=2.441". Drift ID=2.347" HES Hydraulic Packer at 1650' HES XD Sliding Sleeve at 1750'-2.313"X profile--Closed HES Hydraulic Packer at 1950' Weatherford Expansion Joint at 2000' (6' of travel) HES XD Sliding Sleeve at 2250'-2.313"X profile--Closed HES Hydraulic Packer at 2470' HES XD Sliding Sleeves at 2650'and 3050'-2.313"X profile--Closed HES Hydraulic Packer at 3200' HES Frac Door at 3390'—w/ 1.5"ball seat--Closed HES Mechanical Packer at 3850' w/On-Off tool w/2.313" X profile in stinger above and w/6' stinger w/WLE guide at 3860' (NOTE: there is a 6' 2-7/8"tubing pup above and below all the above packers and sliding sleeves [and on-off tool)). ArrowPack Mechanical seal-bore Packer at 4100' w/6' pup, 2.313"X nipple, 6' pup, MagnumDisk 10,000-psi double ceramic disk, and WLE guide . EXISTING PERFS (MD): 1704-23'. 1773-78',2112-20', 21126-32', 2188-2208', 2326- 2416', 2512-32', 2616-26', 3079-84', 3362-72', 3410-20', 3926-46', 3966-86', 4384-94', and 4987-92'. 1) Release AWS rig and rig down after completion, move out. Pull BPV from tree. 2) Move in 4 ea 400-bbl frac tanks and fill with fresh, clean water. Stage on east end of location. Filter water to 5 micron. 3) RU AHR boiler and heat frac water to+/- 80 degrees (2 days of heating to keep fluid about 70 deg when mixed). BJ will add X-cide biocide to water at appropriate time. Then BJ to premix 3% KC1 and other additives not"mixed on the fly,"using crane to pick supersacks. 4) Schedule mobilization of Coiled Tubing Unit w/ 1-1/4" CT to be on location the day of the frac. Also, schedule manlift if necessary for coiled tubing operation. 5) RU Aurora Gas Test Unit as follows: a) set test choke manifold close to rig choke skid and connect to w/ 1502 hard line; b) install 24/64"positive choke in manifold(left side)-- use 2" 1502 target tees upstream of choke skid; c) run AG 2" 1502 hard line from choke manifold to test separator; d) set flare stack 100' or as far as reasonable from the frac equipment, trees and well,raise stack; e) lay AG 3" 1502 hard line from separator skid to flare stack, and connect propane bottle to flare stack. 6) RU AWS Workover pits to Choke skid outlet and install hose to gas buster as needed. Be sure to have transfer pump and tiger tank between test skid and AWS pits. 7) RU BJ to frac. Install frac valve, and manifolding, (Note: Vetco tree is 10,000 psi rated above tubing hanger). Pressure test lines (to frac valve)to 7000 psi (max expected surface pressure to be less than 5300 psi). Install PRV on casing set at 3000 psi. Pressure casing to 2000 psi. 8) Pump frac at 15 BPM keeping pressure below 5000 psi (expected max-4400 psi): A. First stage (perfs at 3926-86'--40' perfs/60' gross interval) (1) 2100 gal 3%KC1 water injection test (2) 1050 gal Lightning 2000 mini frac (3) 2100 gal 3%KC1 miniflush (4) 2,500 gal Lightning 2000 Pad (5) 3,500 gal Lightning 2000 w/2 ppg proppant blend (87.5% white 20/40 sand and 12.5% 12/20 FlexSand MSE) (6) 3500 gal Lightning 2000 w/4 ppg proppant blend (7) 5,500 gal Lightning 2000 w/6 ppg proppant blend (8) 4500 gal Lightning 2000 w/ 8 ppg proppant blend (9) 1050 gal (25.0 bbl) Lightning 2000, dropping 1.75" ball (to serve as start of pad for next stage)—slow rate to 10-12 BPM after 19-20 bbl pumped to watch for ball to seat. Stage Total=25,800 gal (614.3 bbl) and 90,000#proppant B. When ball seats, increase pressure to 1000 psi to open Frac Door at 3390' (frac door opens with a 1000 psi differential). Begin pumping Stage 2 at 15 bpm at less than 5500 psi (expected pressure is less than 5211 psi)—perfs at 3362-72' and 3410-20', 20' of perfs/58' gross interval) 1. 1950 gal (balance of 3000 gal) Lightning 2000 Pad 2. 1050 gal Lightning 2000 w/ 1 ppg proppant blend (87.5% white 20/40 sand and 12.5% 12/20 FlexSand MSE) 3. 2500 gal Lightning 2000 w/2 ppg proppant blend 4. 2500 gal Lightning 2000 w/4 ppg proppant blend 5. 2500 gal Lightning 2000 w/5 ppg proppant blend 6. 4500 gal Lightning 2000 w/6 ppg proppant blend 7. 4200 gal Lightning 2000 w/8 ppg proppant blend 8. 824 gal (19.6 bbl)Lightning 2000 displace to frac door, Stage Total=20,024 gal (476.8 bbl) and 88,100#proppant. Frac Total=45,824 gal (1091 bbl) and 178,100# proppant C. SD pumps, record ISIP, 5-, 10-, and 15-minute SIP's. SI tree. Start RD BJ. RU to flow back to mud pit over shaker w/ball catcher in flowline—line should be 3"to ball catcher. Be prepared to transfer fluid to frac tank (and haul to Aspen disposal). 9) Open well to pit—monitor gas and sand return. If gassy and little sand—put thru gas buster. 10) Prepare for test: a) Take and record initial measurements of brine levels in all tanks to which swabbed/flowed back brine will go—know exact volume of brine is in all tanks; b) Record test separator water level reading; c) install new chart on Barton recorder; d) install fresh nitrogen bottle onto skid for instrumentation; e) install new 5000 psi pressure gauge near test head, isolated with needle valve (upstream from valve that will shut in well for buildup—will want it to record and show SI pressures), Install AWS test chart recorder on needle valve to record SI well pressure, put on AG stand, and f) confirm electric clock on chart recorder is on and set to 12 hrs and chart is appropriate for clock time. 11)If/when well dies, RU Pollard with 1.125" sinker bar, RIH and tag sand. If sand fill is encounter, run bailer in hole and attempt to work thru any bridges--get sample. If ball is still in seat, RIH with pulling tool and pull the seat. If sand fill is encountered above all frac zones more than 200ft, RU CTU. 12) If needed, RU 1-1/4" CTU w/N2, RIH and clean out sand, Pump 8.5 ppg 3% KCl water(or clean returned frac fluid),viscosify and/or nitrify as necessary. PU 2.0"jet nozzle and RIH on CT thru end of tubing at 3560', circulating while RIH. RIH to tag sand—attempt to circ clean to ceramic disk+/-4119'. 13) Pull up hole with nozzle on CT and jet well in if it is not flowing. Jet/Unload as necessary to flow back frac fluid. When water diminishing and/or gas becomes strong, go to next step and test well. 14) Flow test well as follows until clean and stable, as follows: a)jet in w/N2 as necessary, unloading fluid to shaker/possum belly until well is gassing and/or kicks off to flow; b)when significant gas is at surface (whether swabbing or flowing) or the well is flowing, divert flow to test separator: i) shut down momentarily to light flare stack,then bring back on,adjusting choke size until well is flowing strongly to cleanup, but holding some back pressure on it(probably start at 14/64's and adjust accordingly, target flow at 75% of SIP. ii) Flow until rate and pressure have stabilized for 15 minutes, . increasing slightly is OK, but dropping is not—wait until fluctuations tend to be up, not down) and water has dried up (all of tubing volume+ casing volume to 3000' has been recovered, 19 bbl at a minimum) or rate has stabilized . Flow for a minimum of 1 hour. Probably more (2-3 hours), depending upon water production and cleanup. Watch for sand production in water. If producing any sand or much water, shut in and call. iii) Start w/ 1" orifice in test meter. Flow rate in mcf/day= static reading(blue)X differential reading(red)X 31, If red chart reading is below 3, change to 0.75" orifice; if it is above 8 change to 1.5", then 2.0"orifice. Meter factors change to 17.4, 70,or 130,respectively. Orifices may be changed by experienced operator while flowing w/the Daniel Sr. orifice fitting. iv) Catch water samples thru out(downstream of test separator)—have tested with mud kit for weight—record with time of sample. Produced water should have weight is less than 8.4 ppg—if water is trending in that direction, continue to flow until these properties have stabilized. Keep last sample of produced water to send to lab in Anchorage—label thoroughly. v) Shut in well for buildup twice as long as flow period (could build up to about 2000 psi). Report test results to me (Ed)—including email report of flow and buildup tests. 15) When test is completed, evaluate tests—may leave all zones open. Put well on production to compressor from that zone. Ed Jones 10/28/11 Wi Proposal No: 685251051A AURORA GAS INC THREE MILE CREEK UNIT#3 API# 50-283-20117-0000 THREE MILE CREEK Field 34-13N-11W Tyonek County,Alaska October 27,2011 Well Proposal Prepared for: Prepared by: Chad Helgeson DEPESH A PATEL Aurora Gas LLC Region Engineer Bakersfield,California Bus Phone: (661)328-6104 Email: depesh.patel@bakerhughes. Mobile: (661)805-9131 POWERVISION® POWLRPRO • POWERTRAX • POWERLINK Service Point: Service Representatives: KENAI Rod Edwards Bus Phone: 907-776-4084 Account Manager (907)659-2329 Kenai,Alaska Fax: 99611 crams • Operator Name: AURORA GAS INL,Well Name: THREE MILE CREEK UNIT#3EVA Job Description: Stage 1 of 2 Date: October 27,2011 Proposal No: 685251051A JOB AT A GLANCE Surface Treating Pressure(max) 1,341 psi Total Rate(max) 15.00 bpm Estimated Pump Time(HH:MM) 00 47 Frac Fluid 21,600 gals Lightning 2000 KCI Water 4,200 gals 3%KCI Proppants 78,750 lb Sand,White,20/40 11,250 lb FlexSand MSE,12/20 mesh STIMULATION o CEMENTING o COMPLETION SERVICES o SERVICE TOOLS o COILED TUBING o PRODUCTION CHEMICALS CASING AND TUBING RUNNING SERVICES o PIPELINE SERVICES o WELL CONTROL o CHEMICAL SERVICES Ope Well Na Name: THREE GAS INC. Well Name: THREE MILE CREEK UNIT#3 .� Job Description: Stage 1 of 2 Date: October 27,2011 Proposal No: 685251051A WELL DATA RESERVOIR DATA MD Depth to Middle Perforation 3,956 ft TVD Depth to Middle Perforation 3,698 ft Reservoir Pressure 1,818 psi Bottom Hole Static Temperature 100 °F PERFORATED INTERVAL DEPTH(ft) Shots per Foot Perf Diameter Total Perfs MEASURED TRUE VERTICAL (in) 3,926- 3,946 I 3.671- 3,671 I 6 I 0.38 I 120 3,966- 3,986 I 3,725- 3,725 I 6 I 0.38 I 120 Total Number of Perforations 240 Total Feet Perforated 40 ft TUBULAR GEOMETRY Top Bottom Casing 5 1/2"O.D. (4.950".I.D) 15.5# 0 5.800 Tubing 2 7/8"O.D. (2.441".I.D) 6.5# 0 4.630 End of Tubing 4,630 ft Pump Via Tubing 00110 STIMULATION o CEMENTING o COMPLETION SERVICES o SERVICE TOOLS o COILED TUBING o PRODUCTION CHEMICALS CASING AND TUBING RUNNING SERVICES o PIPELINE SERVICES o WELL CONTROL o CHEMICAL SERVICES Operator Name: ,ORA GAS IN( . , Well Name: THREE MILE CREEK UNIT#3 .� Job Description: Stage 1 of 2 Date: October 27,2011 Proposal No: 685251051A FLUID SPECIFICATIONS KCI Water:3%KCI 4,200 Gallons Components: 250 ppt Potassium Chloride Salt 0.5 gpt Flo-Back 30 Surface Tension Reducer 0.4 ppt Xcide-207 Bacteria Control Product Frac Fluid:Lightning 2000 21,600 Gallons Components: 250 ppt Potassium Chloride Salt 5 gpt GLFC-5D Gelling Agent 5 ppt GBW-18 Gel Breaker 2 gpt Enzyme G-1 Gel Breaker 1.7 gpt BF-8L Buffers/Ph Control Product 1 gpt Clay Master-5C Clay Stabilization Product 0.8 gpt XLW-32 Crosslinker 0.5 gpt BC-3 Gel Breaker 0.5 gpt Flo-Back 30 Surface Tension Reducer 0.4 ppt Xcide-207 Bacteria Control Product Proppants 90,000 lb 87.5%Sand,White,20/40 12.5%FlexSand MSE,12/20 mesh Fluids are subject to change based on new information or testing STIMULATION o CEMENTING o COMPLETION SERVICES o SERVICE TOOLS o COILED TUBING o PRODUCTION CHEMICALS CASING AND TUBING RUNNING SERVICES o PIPELINE SERVICES o WELL CONTROL o CHEMICAL SERVICES Operator Name: ,4ORA GAS IN 7 Well Name: THREE MILE CREEK UNIT Job Description: Stage 1 of 2 Date: October 27,2011 Proposal No: 685251051A FRACTURE TREATMENT SCHEDULE INPUT PARAMETERS TVD Depth(Mid Perforation) 3,698 ft MD Depth(Mid Perforation) 3,956 ft Perforations Number 240 Perforation Diameter 0.375 in Bottom Hole Static Temperature 100°F Top Bottom Casing 5 1/2"O.D. (4.950"I.D.) 15.5# 0 5,800 Tubing 2 7/8"O.D. (2.441"I.D.) 6.5# 0 4,630 CALCULATED RATES,PRESSURES&HHP REQUIREMENTS Maximum Minimum Average Surface Treating Pressure(psi) 1,342 1,342 1,342 Slurry Rate(bpm) 15.0 15.0 15.0 Proppant Rate(lbs/min) 3,636 1,150 2,657 Slurry Hydraulic Horsepower 494 494 494 PROCEDURE Fluid Proppant Type Volume Conc. Type Stage Cum Stage (gal) (ppa) (lbs) (lbs) 1 3%KCI 2100 Injection Test 2 Lightning 2000 1050 Minifrac 3 3%KCI 2100 Miniflush 4 Lightning 2000 2500 Pad 5 Lightning 2000 3500 2.000 87.5%Sand,White,20/40 6125 12.5%FlexSand MSE,12/20 875 7000 6 Lightning 2000 3500 4.000 87.5%Sand,White,20/40 12250 12.5%FlexSand MSE,12/20 1750 21000 7 Lightning 2000 5500 6.000 87.5%Sand,White,20/40 28875 12.5%FlexSand MSE,12/20 4125 54000 8 Lightning 2000 4500 8.000 87.5%Sand,White,20/40 31500 12.5%FlexSand MSE,12/20 4500 90000 9 'Lightning 2000 10501 0.000IFIush-Lightning 2000 0 90000 Total 25800 I I 90000 STIMULATION o CEMENTING o COMPLETION SERVICES o SERVICE TOOLS o COILED TUBING o PRODUCTION CHEMICALS CASING AND TUBING RUNNING SERVICES o PIPELINE SERVICES o WELL CONTROL o CHEMICAL SERVICES Ope IN Well Na Name: ,RORAGES R kip Well Name: THREE MILE CREEn UNIT#3 Job Description: Stage 1 of 2 Date: October 27,2011 Proposal No FRACTURE TREATMENT SCHEDULE TREATMENT SCHEDULE Surface Rates Volume Stage Treating Slurry Clean Prop.Rate Slurry Fluid Pump Pressure (bpm) Fluid (lb/min) Stage Cum. Stage Cum. Time Stag (psi) (bpm) (bbls) (bbls) (bbls) (bbls) hh:mm:ss 1 1341 15.0 15.0 50.0 50.0 50.0 50.0 00:03:19 2 -361 15.0 15.0 25.0 75.0 25.0 75.0 00:01:40 3 1341 15.0 15.0 50.0 125.0 50.0 125.0 00:03:19 4 -361 15.0 15.0 59.5 184.5 59.5 184.5 00:03:58 5 -536 15.0 13.7 1149.0 91.4 275.9 83.3 267.9 00:06:05 6 -705 15.0 12.6 2112.0 99.4 375.3 83.3 351.2 00:06:37 7 -855 15.0 11.6 2930.8 168.9 544.2 131.0 482.1 00:11:15 8 -982 15.0 10.8 3635.4 148.5 692.8 107.1 589.3 00:09:54 9 -361 15.0 15.0 25.0 717.8 25.0 614.3 00:01:40 Total Pump Time: 00:47:51 STIMULATION o CEMENTING o COMPLETION SERVICES o SERVICE TOOLS o COILED TUBING o PRODUCTION CHEMICALS CASING AND TUBING RUNNING SERVICES o PIPELINE SERVICES o WELL CONTROL o CHEMICAL SERVICES Operator Name: AURORA GAS In„— Le/ii Well Name: THREE MILE CREEK UNIT#3 Job Description: Stage 2 of 2 Date: October 27,2011 Proposal No: 685251051A JOB AT A GLANCE Surface Treating Pressure(max) 3,537 psi Total Rate(max) 15.00 bpm Estimated Pump Time(HH:MM) 00.47 Estimated Gross Frac Height 211 ft Estimated Propped Length 176 ft Frac Fluid 21,530 gals Lightning 2000 KCI Water 4,200 gals 3%KCI Proppants 77,088 lb Sand,White,20/40 11,013 lb FlexSand MSE,12/20 mesh STIMULATION o CEMENTING o COMPLETION SERVICES o SERVICE TOOLS o COILED TUBING o PRODUCTION CHEMICALS CASING AND TUBING RUNNING SERVICES o PIPELINE SERVICES o WELL CONTROL o CHEMICAL SERVICES Operator Name: MURORA GAS INC 1' Well Name: THREE MILE CREEK UNIT#3 I Job Description: Stage 2 of 2 Date: October 27,2011 Proposal No: 685251051A WELL DATA RESERVOIR DATA MD Depth to Middle Perforation 3,391 ft TVD Depth to Middle Perforation 3,197 ft Reservoir Pressure 1,450 psi Fracture Gradient 0.75 psi/ft Bottom Hole Fracture Pressure 2,397 psi Bottom Hole Static Temperature 96°F Net Fracture Height 185 ft Gross Fracture Height 211 ft Desired Prop Length 176 ft PERFORATED INTERVAL DEPTH(ft) Shots per Foot Perf Diameter Total Perfs MEASURED TRUE VERTICAL (in) 3,362- 3,372 3,170- 3,170 I 6 I 0.38 I 60 3,410- 3,420 I 3,223- 3,223 I 6 I 0.38 60 Total Number of Perforations 120 Total Feet Perforated 20 ft TUBULAR GEOMETRY Top Bottom Casing 5 1/2"O.D. (4.950".I.D) 15.5# 0 5,800 Tubing 2 7/8"O.D. (2.441".I.D) 6.5# 0 3,515 End of Tubing 3,515 ft Pump Via Tubing STIMULATION o CEMENTING o COMPLETION SERVICES o SERVICE TOOLS o COILED TUBING o PRODUCTION CHEMICALS CASING AND TUBING RUNNING SERVICES o PIPELINE SERVICES o WELL CONTROL o CHEMICAL SERVICES Operator Name: .ORA GAS INC • Well Name: THREE MILE CREEK UNIT#3 . Job Description: Stage 2 of 2 Date: October 27,2011 Proposal No: 685251051A FLUID SPECIFICATIONS KCI Water:3%KCI 4,200 Gallons Components. 250 ppt Potassium Chloride Salt 0.5 gpt Flo-Back 30 Surface Tension Reducer 0.4 ppt Xcide-207 Bacteria Control Product Frac Fluid:Lightning 2000 21,530 Gallons Components 250 ppt Potassium Chloride Salt 5 gpt GLFC-5D Gelling Agent 5 ppt GBW-18 Gel Breaker 2 gpt Enzyme G-I Gel Breaker 1.7 gpt BF-8L Buffers/Ph Control Product 1 gpt Clay Master-5C Clay Stabilization Product 0.8 gpt XLW-32 Crosslinker 0.5 gpt BC-3 Gel Breaker 0.5 gpt Flo-Back 30 Surface Tension Reducer 0.4 ppt Xcide-207 Bacteria Control Product Proppants 88,100 lb 87.5%Sand,White,20/40 12.5%FlexSand MSE,12/20 mesh Fluids are subject to change based on new information or testing STIMULATION o CEMENTING o COMPLETION SERVICES o SERVICE TOOLS o COILED TUBING o PRODUCTION CHEMICALS CASING AND TUBING RUNNING SERVICES o PIPELINE SERVICES o WELL CONTROL o CHEMICAL SERVICES Operator Name: LORA GAS IN Well Name: SHRe MILE CREtn UNIT#3 Lib2 Job Description: Stage 2 of 2 Date: October 27,2011 Proposal No: 685251051A FRACTURE TREATMENT SCHEDULE INPUT PARAMETERS TVD Depth(Mid Perforation) 3,197 ft MD Depth(Mid Perforation) 3,391 ft Perforations Number 120 Perforation Diameter 0 375 in Bottom Hole Frac Pressure 2,397 psi Bottom Hole Static Temperature 96°F T10 Bottom Casing 5 1/2"O.D. (4.950"I.D) 15 5# 0 5,800 Tubing 2 7/8"O.D. (2.441"I.D) 6 5# 0 3,515 CALCULATED RATES.PRESSURES&HHP REQUIREMENTS Maximum Minimum Average Surface Treating Pressure(psi) 3,538 1,542 2,015 Slurry Rate(bpm) 15.0 15.0 15.0 Proppant Rate(lbs/min) 3,636 1,150 2,714 Slurry Hydraulic Horsepower 1,301 567 741 STIMULATION o CEMENTING o COMPLETION SERVICES o SERVICE TOOLS o COILED TUBING o PRODUCTION CHEMICALS CASING AND TUBING RUNNING SERVICES o PIPELINE SERVICES o WELL CONTROL o CHEMICAL SERVICES Operator Name: LORA GAS IN Well Name: THREEMILE CREEn UNIT#3 2 Job Description: Stage 2 of 2 Date: October 27.2011 Proposal No: 685251051A FRACTURE TREATMENT SCHEDULE PROCEDURE Fluid Proppant Stage Type Volume Conc. Type Stage Cum (gal) (ppa) (lbs) (lbs) 1 3%KCI 2100 Injection Test 2 Lightning 2000 1050 Minifrac 3 3%KCI 2100 Miniflush 4 Lightning 2000 3000 Pad 5 Lightning 2000 2500 2.000 87.5%Sand,White,20/40 4375 12.5%FlexSand MSE,12/20 625 5000 6 Lightning 2000 2500 4.000 87.5%Sand,White,20/40 8750 12.5%FlexSand MSE,12/20 1250 15000 7 Lightning 2000 2500 5.000 87.5%Sand,White,20/40 10938 12.5%FlexSand MSE,12/20 1563 27500 8 Lightning 2000 4500 6.000 87.5%Sand,White,20/40 23625 12.5%FlexSand MSE,12/20 3375 54500 9 Lightning 2000 4200 8.000 87.5%Sand,White,20/40 29400 12.5%FlexSand MSE,12/20 4200 88100 10 Lightning 2000 12801 0.000IFIush-Lightning 2000 I 0 88100 Total I 25730 I 88100 TREATMENT SCHEDULE Surface Rates Volume Stage Treating Slurry Clean Prop.Rate Slurry Fluid Pump Pressure (bpm) Fluid (Ib/min) Stage Cum. Stage Cum. Time Stage (psi) (bpm) (bbls) (bbls) (bbls) (bbls) hh:mm:ss 1 3537 15.0 15.0 50.0 50.0 50.0 50.0 00:03:19 2 2078 15.0 15.0 25.0 75.0 25.0 75.0 00:01:40 3 3537 15.0 15.0 50.0 125.0 50.0 125.0 00:03:19 4 2078 15.0 15.0 71.4 196.4 71.4 196.4 00:04:45 5 1927 15.0 13.7 1149.0 65.3 261.7 59.5 256.0 00:04:21 6 1781 15.0 12.6 2112.0 71.0 332.7 59.5 315.5 00:04:44 7 1714 15.0 12.1 2537.3 73.9 406.6 59.5 375.0 00:04:55 8 1651 15.0 11.6 2930.8 138.2 544.8 107.1 482.1 00:09:12 9 1541 15.0 10.8 3635.4 138.6 683.4 100.0 582.1 00:09:14 10 2078 15.0 15.0 30.5 713.9 30.5 612.61 00:02:01 Total Pump Time: 00:47:35 212011303W aH141 STIMULATION o CEMENTING o COMPLETION SERVICES o SERVICE TOOLS o COILED TUBING o PRODUCTION CHEMICALS CASING AND TUBING RUNNING SERVICES o PIPELINE SERVICES o WELL CONTROL o CHEMICAL SERVICES FracproPT 2011 Hydraulic Fracture Analysis Date: Thursday,October 27,2011 Well Name: Three Mile Creek Unit 3 Location: Alaska Formation: Job Date: Filename: Three Mile Creek 3 Stage 1 Table 1:Fracture Geometry Summary*-Interval#1 Fracture Half-Length(ft) 86 Propped Half-Length(ft) 86 Total Fracture Height(ft) 159 Total Propped Height(ft) 159 Depth to Fracture Top(ft) 3564 Depth to Propped Fracture Top(ft) 3564 Depth to Fracture Bottom(ft) 3722 Depth to Propped Fracture Bottom(ft) 3722 Equivalent Number of Multiple Fracs 1.0 Max.Fracture Width(in) 1.26 Fracture Slurry Efficiency** 0.47 Avg.Fracture Width(in) 0.83 Avg.Proppant Concentration(Ibfft2) 3.58 Table 2:Fracture Geometry Summary*-Interval#2 Fracture Half-Length(ft) 22 Propped Half-Length(ft) 22 Total Fracture Height(ft) 45 Total Propped Height(ft) 45 Depth to Fracture Top(ft) 3695 Depth to Propped Fracture Top(ft) 3695 Depth to Fracture Bottom(ft) 3739 Depth to Propped Fracture Bottom(ft) 3739 Equivalent Number of Multiple Fracs 1.0 Max.Fracture Width(in) 0.31 Fracture Slurry Efficiency** 0.88 _Avg.Fracture Width(in) 0.20 Avg.Proppant Concentration(Iblft2) 0.87 *All values reported are for the entire fracture system at a model time of 46.15 min(end of Stage 6 Main frac flush) **Value is reported for the end of the last pumping stage(Stage 6,Main frac flush) Table 3:Fracture Conductivity Summary*-Interval#1 Avg.Conductivity**(mD•ft) 5269.5 Avg.Frac Width(Closed on prop)(in) 0.096 Dimensionless Conductivity** 15.55 Ref.Formation Permeability(mD) 3.92 Proppant Damage Factor 0.30 Undamaged Prop Perm at Stress(mD) 254051 Apparent Damage Factor*** 0.00 Prop Perm with Prop Damage(mD) 177835 Total Damage Factor 0.30 Prop Perm with Total Damage(mD) 177835 Effective Propped Length(ft) 86 Proppant Embedment(in) 0.007 Table 4:Fracture Conductivity Summary*-Interval#2 Avg.Conductivity**(mD•ft) 0.0 Avg.Frac Width(Closed on prop)(in) 0.096 Dimensionless Conductivity** 0.00 Ref.Formation Permeability(mD) 3.92 Proppant Damage Factor 0.30 Undamaged Prop Perm at Stress(mD) 254051 Apparent Damage Factor*** 0.00 Prop Perm with Prop Damage(mD) 177835 Total Damage Factor 0.30 Prop Perm with Total Damage(mD) 177835 Effective Propped Length(ft) 0 Proppant Embedment(in) 0.007 *All values reported are for the entire fracture system.Actual conductivity could be lower if equivalent multiple fractures have been modeled **Total Damage Factor and Proppant Embedment have been applied ***Apparent Damage due to non-Darcy and multi-phase flow Table 5:Fracture Pressure Summary*-Interval#1 Model Net Pressure**(psi) 2090 BH Fracture Closure Stress(psi) 2279 Observed Net Pressure**(psi) 0 Closure Stress Gradient(psi/ft) 0.620 1 FracproPT 2011 Hydrostatic Head***(psi) 1657 Avg.Surface Pressure(psi) _ 2563 Reservoir Pressure(psi) 1818 Max.Surface Pressure(psi) 4363 Table 6:Fracture Pressure Summary*-Interval#2 Model Net Pressure**(psi) 1673 BH Fracture Closure Stress(psi) 2279 Observed Net Pressure**(psi) 0 Closure Stress Gradient(psi/ft) 0.613 Hydrostatic Head***(psi) 1657 Avg.Surface Pressure(psi) 2563 Reservoir Pressure(psi) 1818 Max.Surface Pressure(psi) 4363 *Averages and maxima reported for Main Frac stages **Values reported for the end of the last pumping stage(Stage 6.Main frac flush) .**Value reported for clean fluid Table 7:Operations Summary*-Interval#1 Total Clean Fluid Pumped(bbls) 475.4 Total Proppant Pumped(klbs) 90.0 Total Slurry Pumped(bbls) 558.6 Total Proppant in Fracture(klbs) 77.3 Pad Volume(bbls) 166.7 Avg.Hydraulic Horsepower(hp) 941 Pad Fraction(%of Slurry Vol)** 24.9 Max.Hydraulic Horsepower(hp) 1602 Pad Fraction(%of Clean Vol)** 29.2 Avg Btm Slurry Rate(bpm) 12.1 Primary Fluid Type LIGHTNING Primary Proppant Type Ottawa Sand 2000 20/40 Secondary Fluid Type Secondary Proppant Type Table 8:Operations Summary*-Interval#2 Total Clean Fluid Pumped(bbls) 124.5 Total Proppant Pumped(klbs) 90.0 Total Slurry Pumped(bbls) 125.9 Total Proppant in Fracture(klbs) 1.3 Pad Volume(bbls) 166.7 Avg.Hydraulic Horsepower(hp) 941 Pad Fraction(%of Slurry Vol)** 24.9 Max.Hydraulic Horsepower(hp) 1602 Pad Fraction(%of Clean Vol)** 29.2 Avg Btm Slurry Rate(bpm) 3.0 Primary Fluid Type LIGHTNING Primary Proppant Type Ottawa Sand 2000 20/40 Secondary Fluid Type Secondary Proppant Type *Averages and maxima reported for Main Frac stages Totals reported for all injections combined. **Based on following volume ratio of stage types:Main frac pad/(Main frac pad+Main frac slurry),and excluding flush. 2 FracproPT 2011 Table 9:Hydraulic Fracture Growth History*-Interval#1 End of Stage Type Time Fracture Fracture Fracture Avg. Model Net Slurry Equivalent Stage# (mm:ss) Half- Height Width at Fracture Pressure Efficiency Number of Length (ft) Well Width (psi) Multifracs (ft) (in) (in) 1 Main frac pad 1 11:06 66 121 0.298 0.195 837 0.31 1.0 2 Main frac slurry! 17:10 77 143 0.377 0.244 866 0.34 1.0 3 Main frac slurry) 23:43 84 155 0.513 0.332 1013 0.38 1.0 4 Main frac slurry 34:49 87 160 0.826 0.539 _ 1442 0.43 1.0 5 Main frac slurry: 44:33 86 159 1.217 0.796 2018 0.47 1.0 6 Main frac flush I 46:08 86 159 1.263 0.827 2090 0.47 1.0 Table 10:Hydraulic Fracture Growth History*-Interval#2 End of Stage Type Time Fracture Fracture Fracture Avg. Model Net Slurry Equivalent Stage# (mm:ss) Half- Height Width at Fracture Pressure Efficiency Number of Length (ft) Well Width (psi) Multifracs (ft) (in) (in) 1 Main frac pad 11:06 42 89 0.164 0.110 412 0.24 1.0 2 Main frac slurry 17:10 48 96 0.177 0.118 444 0.20 1.0 3 Main frac slurry 23:43 45 95 0.241 0.161 595 0.20_ 1.0 4 Main frac slurry 34:49 44 94 0.384 0.255 1026 0.22 1.0 5 Main frac slurry 44:33 44 94 0.319 0.212 2042 0.17 1.0 6 Main frac flush 46:08 22 45 0.313 0.205 1673 0.88 1.0 'All values reported are for the entire fracture system and at the end of each stage Table 11:Propped Fracture Properties by Distance from the Well at Fracture Center at Depth of 3643ft- Interval#1 Distance Fracture Conductivity Frac System Prop Conc per Frac System from Well System per Frac** Conductivity*** Frac Prop Conc**** (ft) Width* (mD•ft) (mD•ft) (Ib/W) (Ib/ft') (in) 8.6 1.257 7000.1 7000.1 4.39 4.39 17.3 1.238 6868.5 6868.5 4.31 4.31 25.9 1.205 6644.2 6644.2 4.17 4.17 34.6 1.158 6374.3 6374.3 4.01 4.01 43.2 1.094 6063.7 6063.7 3.83 3.83 51.9 1.011 5501.8 5501.8 3.49 3.49 60.5 0.902 4725.3 4725.3 3.02 3.02 69.2 0.758 4214.8 4214.8 2.72 2.72 77.8 0.551 2886.5 2886.5 1.92 1.92 86.5 0.000 0.0 0.0 0.00 0.00 Table 12:Propped Fracture Properties by Distance from the Well at Fracture Center at Depth of 3717ft- Interval#2 Distance Fracture Conductivity Frac System Prop Conc per Frac System from Well System per Frac** Conductivity*** Frac Prop Conc**** (ft) Width* (mb•ft) (mD•ft) (Iblfta) (1b/f°) (in) 2.2 0.301 1850.2 1850.2 1.30 . 1.30 4.3 0.296 1816.7 1816.7 1.28 1.28 6.5 0.288 1759.7 1759.7 1.25 1.25 8.7 0.277 1677.2 1677.2 1.20 1.20 10.8 0.262 1565.8 1565.8 1.13 1.13 13.0 0.242 1419.9 1419.9 1.04 1.04 3 FracproPT 2011 Distance Fracture I Conductivity Frac System 'Prop Conc per Frac System from Well System per Frac** Conductivity*** Frac Prop Conc**** (ft) Width* (mD•ft) (mD-ft) (Ib/ftv) (Ib/ftp) (in) 15.2 0.216 1229.6 1229.6 0.93 0.93 17.3 0.181 974.9 974.9 0.77 0.77 19.5 0.132 600.0 600.0 0.55 0.55 21.7 0.000 0.0 0.0 0.00 0.00 'Width values reported are for the entire fracture system. Fracture conductivity reported for total proppant damage of 0.30 and 0.007 in of proppant embedment. "'Frac system conductivity reported for 1.0 equivalent multiple fractures with 100%considered conductive. ""Frac system proppant concentration reported for 1.0 equivalent multiple fractures. 4 FracproPT 2011 Table 13:Design Treatment Schedule Stage Stage Type Elapsed Fluid Clean Prop Stage Slurry Proppant Time Type Volume Conc Prop. Rate Type min:sec (gal) (ppg) (klbs) (bpm) Wellbore Fluid 3%KCL 964 1 Main frac pad 11:06 LIGHTNING 2000 7000 0.00 0.0 15.00 2 Main frac slurry 17:10 LIGHTNING 2000 3500 2.00 7.0 15.00 Ottawa Sand 20/40 3 Main frac slurry 23:43 LIGHTNING 2000 3500 4.00 14.0 15.00 Ottawa Sand 20/40 4 Main frac slurry 34:49 LIGHTNING 2000 5500 6.00 33.0 15.00 Ottawa Sand 20/40 5 Main frac slurry 44:33 LIGHTNING 2000 4500 8.00 36.0 15.00 Ottawa Sand 20/40 6 Main frac flush 46:08 LINEAR 20 GW-32 1000 0.00 0.0 15.00 Design clean volume(bbls) 595.2 Design proppant pumped(klbs) 90.0 Design slurry volume(bbls) 692.2 5 FracproPT 2011 Table 14:Fluid Parameters Fluid Name 3%KCL LINEAR_20_GW-32 LIGHTNING 2000 Vendor MISCELLANEOUS BJ SERVICES BJ SERVICES System _ GENERAL LINEAR GEL LIGHTNING Description 3%KCL WATER 20#LINEAR HPG 20#/1000 GELLED WATER Initial Viscosity(cp) 0.819 17.25 560.8 Initial n' 1.000 0.640 0.433 Initial k'(Ibf•s"n/ft=) 1.000 0.640 0.433 Viscosity @ 4.0 hours(cp) 0.819 8.07 389.1 n'@ 4.0 hours 1.000 0.770 0.506 k'@ 4.0 hours(Ilk sAn/ftz) 1.000 0.770 0.506 Base Fluid Specific Gravity 1.02 1.02 1.000 Spurt Loss(gal/ft2) 0.0 2.00 0.0 Wall Building(ft/min%) 0.0 0.003 0.003 Flowrate #1(bpm) 10.00 10.00 5.00 Fric Press#1(psi/1000 ft) 473.0 135.0 69.14 Flowrate #2(bpm) 20.00 20.00 10.00 i Fric Press#2(psi/1000 ft) 1610.3 330.0 159.0 Flowrate #3(bpm) 40.00 40.00 20.00 Fric Press#3(psi/1000 ft) 5482.6 815.0 496.4 Wellbore Friction Multiplier 1.000 1.000 1.000 All Fluid info is at a reservoir temperature of 95.0(°F) All Viscosities at Shear Rate of 100(1/sec) Wellbore Friction pressures shown are the interpolated values multiplied by the Wellbore Friction Multiplier. Friction is displayed for longest wellbore segment 6 FracproPT 2011 Table 15:Casing Configuration Length Segment Type Casing ID Casing OD Weight Grade (ft) (in) (in) (lb/ft) 5800 Cemented Casing 4.950 5.500 15.500 J-55 Table 16:Surface Line and Tubing Configuration Length Segment Type Tubing ID Tubing OD Weight Grade (ft) (in) (in) (lb/ft) 4630 Tubing 2.441 2.875 6.500 J-55 Total frac string volume(bbls) 23.0 Pumping down Tubing Table 17:Perforated Intervals Interval#1 Interval#2 Top of Perfs-TVD(ft) 3671 3707 Bot of Perfs-TVD(ft) 3689 3725 Top of Perfs-MD(ft) 3926 3966 Bot of Perfs-MD(ft) 3946 3986 Perforation Diameter(in) 0.380 0.380 #of Perforations 120 120 Table 18:Path Summary Segment Length MD TVD Dev Ann OD Ann ID Pipe ID Type (ft) (ft) (ft) (deg) (in) (in) (in) Tubing 3966 3966 3707 15.7 0.000 0.000 2.441 7 FracproPT 2011 Table 19:Near-Wellbore Friction&Perforation Friction Time Flowrate Flowrate Near- Perforation Total Entry Perforation Perfs (mm:ss) #1 #2 Wellbore Friction Friction Friction Effectively (bpm) (bpm) Friction (psi) (psi) Multiplier Open (psi) 0:00 0.00 0.00 0 0 0 1.00 240.00 Table 20:Closure Stress Summary Table Plot Est. ISIP Surf Est. Closure Surf Fracture Dimless Implied Est.Net ISIP Gradient ISIP Closure Stress Closure Closure Fracture Slurry Pressure (psi) (psi/ft) (psi) Pressure Gradient Pressure Time Closure Efficiency (psi) (psi) (psi/ft) (psi) (min) Time (%) Injection/Shut-in#1 SQRT Plot 12656 10.693 1966 12658 0.694 1968 10.00 0.00 0.000 1-2 ISIP and Closure Pressure are determined from: Bottomhole Data Table 21:Reservoir Pressure and Permeability Summary Table Plot Est.Reservoir Est.Reservoir Est.Reservoir Pressure Pressure Permeability (psi) Gradient (mD) (psi/ft) Injection/Shut-in#1 Perm Analysis Plot 1.00e-02 8 FracproPT 2011 Btmh Pressure psi) S000 — prop Cont(p• ----Wbore Friction(psi) 10•• Sud Pressure si -Slur Rate b•m 5000 5000-------- 100.0 4"I --------- 4000 4."11�1111IMMIIMIIIiM ui 80.00 8.•°°Y-------' I1M 3000 ���uH1.�:�'�=�-... 50.00 2000111111=======.11111111 000��=r==/--.111- 2000 4°."'���H�®��� 40.00+M 1...IMEIMIIIIII----EIIIM 1000 • ?6mMMEMIIIIIMmMEMEIIIIIIN 20.00 00--I-______- 0.0 0.0 0.00 10.00 20.00 30.00 40.00 50.00 0.0 Time(rnin) Pressure.Rate,Prop Conc-Interval#1 — Btmh Pressure(psi) 5000 Prop Cons(p•e - Wbore Friction(psi) 1U•• Surf Pressure si -Slur Rate b.m 5000 5000--------= 100.0 1111-------.1 - 4000 400011{{I��-------- M 50.00 pHn{�-------NI ® 3000 �nn„1 --Mill 50.00 4000„fililiT141LIU---�- 2000 2000�--��®M��1- 40,00 • 1000 =1111111111----MINE 1000 • 2°°°mMMEME1=m===11111 2000 0-0- 0.0 -IM-----�- 0.0 0 0 0.00 10.00 20.00 30.00 40,00 50,00 0.0 Time(min) Pressure.Rate,Prop Conc-Interval 9 FracproPT 2011 Width Profile(in) Fracture Conductivity(m04t) 0 025« I I ,-W 126 160 175 200 z t -:1111 Interval Ml Interval 42 1 i FracproPT TotalPropPr pped Hoo 21 7 118.6 1 - 1 - Aver Propped Haight i20 068.] W 1 -I J ,;�. - - - • ■■■.Average Pro., Wmcentr o.zU o El '.■■■ A-- Pro..-iCmcenire0an 113/It. O.B] OfiB r __.IH::::i: : _ Illijillups , • • ,...... ... .. , 1 rIri.l.„ • 7 • , .1..1 11111.1 1 . , ..r 11111 ...... i 4......A , ______, ...■■.! gill:1 __ iiimill - , ii, ....1.....siii A.... ..... , , , • i .::: ::: .. . . :: m N■..■■■ ure Conduct rounoro ikr --.-.]� - Mill r-00 B00 5000 1200. v0 2200 MI 10 FracproPT 2011 Page 1 of 1 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Friday, October 07, 2011 2:42 PM To: 'Dave Bollins (dboelens@aurorapower.com)' Subject: Planned TMC#3 Stimulation (211-071) Contacts: Dave Boelens Dave, This confirms our recent conversation. In the approved operations plan submitted with the permit, it is stated (step 27) that Aurora intends to fracture stimulate intervals in the well much the same as was successfully done in TMC#2. Since the potential pay zones are yet to be penetrated, the actual design has not been finalized. It is Aurora's intent to set the casing, perforate the intervals and install the completion equipment then release the rig pending the final stimulation design. We request that when the stimulation design is finalized that Aurora submit the proposed plan to the Commission with a sundry similar to what was done for TMC#2. Hydraulic fracturing has become very controversial and Alaska is not immune to that growing controversy. The Commission is evaluating what regulatory changes might be needed to improve the public's confidence in operations that here- to-fore have been safely accomplished without damaging underground sources of drinking water. Aurora's providing the planned operational information for TMC#3 will help insure that the file is complete for the well. Thanks in advance for cooperation in this matter. Aurora has my best wishes for success in their endeavors. Call or message with any questions. Tom Maunder, PE AOGCC 10/7/2011 suikuE 01 RAsEA SEAN PARNELL,GOVERNOR ALASKA OIL AND GAS 333 W.7th AVENUE,SUITE 100 CONSERVATION COM1rIISSION ANCHORAGE,ALASKA 99501-3539 PHONE (907)279-1433 FAX (907)276-7542 Bruce D. Webb Manager, Land and Regulatory Affairs Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Three Mile Creek Gas Field, Beluga Gas Pool, Three Mile Creek #3 Aurora Gas, LLC Permit No: 211-071 (revised) Surface Location: 367' FEL, 1224' FSL, T13N, R 11 W, SM, SEC. 34 Bottomhole Location: 1950' FEL, 1810' FSL, T13N,R11W, SM, SEC. 34 Dear Mr. Webb: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Daniel T. Seamount, Jr. tC Chair DATED this- I day of August, 2011. cc: Department of Fish 86 Game, Habitat Section w/o encl. (via e-mail) Department of Environmental Conservation w/o encl. (via e-mail) 4 STATE OF ALASKA ECENDI /1.+u AL :A OIL AND GAS CONSERVATION COM1. ,10 PERMIT TO DRILL �L �� 20 AAC 25.005 { [� la.Type of Work: lb.Proposed Well Class: Development-Oil ❑ Service- Winj 0 Single Zone 6t113�c Sl�c'I II mp F�lssiun Drill ❑., Redrill 0 Stratigraphic Test ❑ Development-Gas ❑� Service-Supply 0 Multiple Zone El Coalbed GNf1®P.KilJeiYdrates ❑ Re-entry 0 Exploratory 0 Service- WAG ❑ Service-Disp 0 Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket ❑✓ Single Well ❑ 11.Well Name and Number Aurora Gas, LLC Bond No NZS 429815 Three Mile Creek#3 3.Address: 6.Proposed Depth:5l/ia. 410.1' 12.Field/Pool(s): 1400 W. Benson Blvd, Suite 410,Anchorage AK,99503 MD: Trees' . y l4QTVD:,5eeg, • 4a Location of Well(Governmental Section): 7 Property Designation: Three Mile Creek Gas Field Surface: T. 13 N., R. 11 W., S.M., Section 34 - ADL-388233 " Beluga Gas Pool 367'FEL and 1,224'FSL • 8.Land Use Permit: 13.Approximate Spud Date: Top of Productive Horizo 700'FEL and 1,530'FSL none 8/21/2011 Total Depth: 1,950'FEL and 1,810'FSL • 9.Acres in Property' 14.Dist.to Nearest Property: 2-i.,2•l 6 r, .0 5'1%' /1 3,320 acres 1,530'at productive horizon 4b.Surface Location of Well(State Base Plane Coordinates): 10.KB Elevation 302'MLLW - 15.Distance to Nearest Well x-2858t5- - , y-,10.217.41zone: 4 (Height above GL): 15' - feet Within Pool: 2,582'at surface - 16.Deviated wells::4S>-3c Kickoff depth 825+/- feet 17.Maximum Anticipate Pressures in psig(see 20 AAC 25 035) /W64,0 Maximum Hole Angle 36 degrees Downhole: 2.;605 ps' 5 L Lour Surface. 1,981 psi - 18 Casing Program Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 13-3/8" 72# K-55 BW 95' 15' 15' 80' 80' N/A 12-1/4" 9-5/8" 36# J-55 LTC 800' surface surface 800' 800' 12 ppg,Type 1, 216 sx ' 7-7/8" 5-1/2" 15.5# J-55 LTC 5,000' surface surface -.51096k 4,706' 12/14.8 ppg,Class G, 656 sx S!1(o wok- 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-Entry Operations) Total Depth MD(ft): Total Depth TVD(ft): Plugs(measured). Effect.Depth MD(ft): Effect.Depth TVD(ft): Junk(measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production • Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): 20. Attachments: Property Plat ❑ BOP Sketch❑ Drilling Program El Time v.Depth Plot Q Shallow Hazard Analysis El Diverter Sketch❑ Seabed Report ❑ Drilling Fluid Program ❑., 20 AAC 25.050 requirements❑., 21 Verbal Approval: Commission Representative: Date 22 I hereby certify that the foregoing is true and correct. Contact Printed Name Bruce D.Webb Title Manager, Land and Regulatory Affairs Signature% <' 4-'36- Phone (907)277-1003 Date July 12,2011 Commission Use Only Permit to Drill API Number: Permit Appr See cover letter for other Number: 211-071 50- 283-20156-00-00 Date: ( I�I I t requirements. Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methane, as hydrates,or gas contained in shales: Et- Other: —re -k" Z.O?E to 30.00 e SA', • Samples req'd: Yes EI No[9 Mud log req'd: Yes ❑ No 0 QUrsct t�wt 62 TOM{ ZS. 03$ ( I1 H2S measures: Yes EI Non/ Directional svy req'd: Yes E 'No EI)(L) -ifw veK-f l r i.-Q v etY 1 ;$ AfP tro ve.d. /ill maxi 12 re-SS or f_ fes s mks+ di V•e h.-_ wt.a.i,n.f-At.i,tte.J -or 30 ►tit,i►tirc.-}•es HAI e. deco,.- -c'o t-. , J APPROVED BY THE COMMISSION ( I f DATE A v/,\)//' ,COMMISSIONER ORI INAL ,,,, :LI Form 10-401(Revised 7/2009) This permit is valid for 24 months from the date of approval(20 AAC 25.005(g)) Submit in Duplicate Aurora Gas, LLC Three Mile Creek#3 Drilling Plan THREE MILE CREEK #3 (VERSION 1.4) Three Mile Creek#3 is a grass-roots directional well targeting numerous Beluga Gas sands.. It is. located in the Three Mile Creek Gas Field and will drilled+/1700' to the WNW from a new pad about 2582' south-south-west of the Three Mile Creek#1 well and facility. It will target Beluga • Tsuga 2-3 to Beluga Tsuga 2-6 sands that have produced/are producing in the Three Mile Creek #1 and#2 wells. Pre Rig work 1. The site for the Three Mile Creek(TMC)#3 is a pad constructed in 2005 immediately to the - east of the"Superior Road,"just before the short access road to TMC #1 The location is in Sec. 34, T13N, R11 W, and the GL is about 293'. 2. A nominally 200' X 300' gravel pad has been built(2005), and 13-3/8" 72# K-55 BFW conductor(12-1/4" special drift) was driven to+/-80' below GL. Pad will need to be graded and,perhaps, expanded slightly. 3. Build sufficient emergency cuttings containment for planned drilling program on this pad(or the#1 pad), and build containment for diverter line using silt fence. 4. Install cellar&mousehole. Cut off conductor as needed to accommodate diverter system. Drilling Procedure 1. File& insure all necessary permits and applications are in place. 2. MIRU AWS#1 in drilling configuration. Install 13-5/8" VG LOK head. , 3. Rig up diverter&mud loggers. Test& calibrate all PVT/gas sensor equipment Provide 24-hr notice to AOGCC inspectors for chance to witness diverter test. 4. Notify AOGCC when ready to start drilling operations. 5. Prepare spud mud system / weight up to 10.0 ppg. Load, strap & drift 800'+ of 9-5/8" 36# J-55 LTC surface casing. Note that float shoe and float collar will be "bucked on" short joints in Kenai—locate and bring to location. 6. PU 12-1/4" mill tooth bit, MWD equipment, & drill to –800', using 8" & 6-1/2" stabilized BHA. (packed hole) w/ float sub and drilling jars (as recommended by Directional Driller). Watch for gas in shallow coals and sands. Attempt to TD in siltstone or claystone, avoid setting surface shoe in a coal bed or sand. If possible, adjust TD to put cement head at floor. (Short joints are available to facilitate this). Watch deviation using MWD—shallow fault will likely cause severe deviation: avoid doglegs—control drilling as needed. 7. Make wiper trip to conductor to condition hole for running 9-5/8" surface casing, POOH, LD 12-1/4" BHA. Prepared by Ed Jones Page 1 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan 8. Run & cement new 9-5/8" 36# J-55 casing @ +1-800', installing 1 centralizer / joint centered on the 1st 4 joints above shoe, & 1 centralizer every 2nd joint across the collars there after. Shoe joint connection at float shoe and float collar must be Baker-Locked. Cementing will be single stage using 12.0 ppg accelerated light-weight Type I cement at 100% excess volume. Overdisplace by 1 bbl if plug doesn't bump. Be prepared to treat cement returns with retarder. Leave 6"to 18"of cement in cellar to seal bottom. 9. RD cementers,nipple own diverter, cut casing and install 11" 3M wellhead. 10. RU and test 11" BOP stack and 5M choke manifold. Test stack and surface equipment to 3,000 psi. Pressure test 9-5/8" casing to 1,500 psi for minutes or as required on approved Permit to Drill. 5° V t4k- 11. PU 7-7/8" Mill Tooth Bit& 6-1/2" & 4-3/4" stabilized BHA w/ float sub and drilling jars. RIH. Drill out shoetrack. Swap out mud from spud mud to KC1-Polymer system with 9.5 ppg. Drill 20' new formation. Pull back into shoe & perform FIT / LOT up t0) ppg EMW. POH, PU directional and MWD BHA. 12. RIH and drill directional 7-7/8" hole to 5000' MD/4706'TVD TD or other depth as directed by Aurora Gas geologist (may slightly deeper, depending upon top of Tsuga 2- 6.4 sand). Monitor well and volumes carefully. Be prepared to shut well in and weight up immediately if flow or excessive gas build up in mud is noticed. Monitor hole cleaning, mud losses, and drilling trends, make wiper trips every 500' or so, as needed (back into shoe first time, then just above last wiper trip point thereafter, or as needed). Anticipated mud weights required are 9.2 ppg – 10.2 ppg. Do not exceed fracture gradient determined in step 11. If possible, adjust TD to put cement head on floor. While drilling, load,tally&drift 5-'/2" casing on racks. Notes: 1)May see some depletion below 2400'. 2) Hole will likely want to "walk" updip (to west)—allow it to do so within directional plan, without any doglegs greater than 1 deg/100'. 3) Target BHL is 1583' west and 586' north, for a total departure of 1688'. 13. Condition hole, short trip and prepare for running wireline logs. 14. POOH, rack back drillstring. RU wireline BOP's and lubricator and logging tools. Log 9-5/8" cased hole section w/gamma ray sensor. Log OH section with logging suite including resistivity and porosity logs as directed by Aurora Gas. RD wireline. 15. RIH w/7-7/8" drilling assembly to TD &condition hole for running 5-'/2" casing. Ensure cementing head has proper connections (8 Rd LTC) or proper cross-over and is available for quick rig up. 16. POOH while laying down drillpipe & BHA, RU to run casing. Verify cementer's equipmen,tr.b lstesr t44I' 17. Instal A5-Y2"pipe rams. 18. Run 5000' of 5-'/2" 15.5# J-55 LTC casing, installing 1 centralizer per joint centered on 1St 4 joints above shoe, 1 centralizer every 2nd joint in open hole & every 3rd joint inside surface casing (use Turbolator centralizers below/thru each pay sand). Shoe joint Prepared by Ed Jones Page 2 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan connection at float shoe, float collar must be Baker-Locked (80' shoetrack). While running casing, fill every 3`d joint. Be prepared to wash to bottom. NOTE: If depletion and lost circulation was encountered while drilling, will add multiple-stage cementer ("DV tool")to casing string,probably about at 3000' and cement in 2 stages. 19. RU cementers, cementer attached cementingprogram from TD to surface. A sufficient P amount of accelerated 12.0 ppg light weight Class G lead cement w/ gas control will be pumped to cover from 1800' up thru the annulus of 9-5/8" to surface. This will be followed by sufficient amount of 14.8 ppg Class G tail blend cement w/ gas control & extender to cover from TD back to 1800'. Excess will be calculated using caliper log data—top of tail slurry will be determined following evaluation of the logs. Plug will be bumped with clean brine (weight to be determined by wireline XPT testing). If possible reciprocate pipe while displacing cement. Land casing& WOC. 20. RD cementers,nipple down stack, land casing in slips&cut casing. 21. Install 11" X 7-1/16" tubing spool, 7-1/16" X 11" DSA, mud cross and reinstall BOP stack. Pressure test BOP and surface equipment to 3,000 psi. Pressure test casing to 2,000 psi for 'minutes and record results. 10 tr.14k 22. Install 2-7/8"pipe rams. 23. RIH w/ bit & casing scraper on 2-7/8" tubing to float collar. Displace well w/ filtered KC1/NaCI brine (wt. to be determined from XPT data). Continue to clean brine for perforating by running through centrifuge & filtering. POOH. Strap tubing on TOH to validate tally. A MORE DETAILED PROCEDURE WILL BE PROVIDED AT THIS POINT INCLUDING / PERFS 24. PU wireline BOP's & lubricator, pressure test all against casing to 1500 psi (or higher if XPT indicated higher gradients). PU GR/CBL/CCL & log 5-1/2" casing to surface. LD logging tools & PU perforating guns, RIH to depth as determined from OH logs and perforate zones of interest. Watch for pressures in casing after shooting. POOH, LD perf gun, RD wireline. (Anticipate perforating about 180' in 12 sands between 2700' and 4750'). 25. RIH w/ bit & casing scraper on 2-7/8" tubing to float collar. Circulate perforating debris from hole. Continue centrifuging & filtering brine until cleaned up. POOH. LD bit & scraper. RU Aurora well test unit, including flare stack. 26. Pick up & assemble completion assembly which will consist of mechanical set packer w/ on-off tool for sump packer to be set above deepest perforated zone (at +/- 4500'), then frac sleeve at +/-3650', and 4 hydraulic packers at +/- 3500', 3200', and 2600', and a mechanical packer 2100' w/ an On-Off tool and w/ sliding sleeves between packers and an expansion joint between the packers at 2600' and 3200'—all sliding sleeves and frac sleeve are to be closed and a pump-out ball-seat below deepest packer (which is compatible with the frac sleeve). RIH with completion on new 2-7/8" 6.5# J-55 8 rd tubing & set completion at appropriate depth, filling tubing as running. (Depending upon frac design, may want to run 3-1/2" L-80 tubing to top packer). Space out, hang off in tubing head & lock down. Drop ball and pressure tubing to 3000 psi (or as required) to Prepared by Ed Jones Page 3 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan test and to set packers. Increase pressure and shear out ball. Install BPV. ND BOP. NU and test tree. Release,rig down,move out rig. Pull BPV. 27. RU frac equipment and tree saver. Frac deepest completion (below deepest packer) with +/- 50,000# 20-40 sand w/ 12.5% 12/20 FlexSand in+/-30,000 gal Lightning 2000 water- based frac fluid. Drop ball to open frac sleeve at +/-3600', and frac 2nd deepest completion w/ 75,000# proppant in 35,000 gal frac fluid. SI well and RD tree saver and frac equipment. 28. Flow back well to clean up. RU & swab in when well dies, if necessaary. After well cleans up (several days), perform flow test—get stabilized rate (1 hour minimum). Shut in well & record pressure buildup until stabilized with no change in one hour. DO NOT KILL, but run blanking plug and set in X nipple below 2n1 packer from bottom (deepest hydraulic packer). 29. Open deepest sliding sleeve (at +/- 3300"). Test well as per Step 28. DO NOT KILL, but close sliding sleeve. 30. Repeat Step 29 for remaining shallower intervals(3 expected). 31. Open zones for initial production and shut sliding sleeves for other completions (depending upon pressures and test results—likely the 2 deepest completions)—flow to clean up. Shut in. . 32. Run 4-point test of initial production zone as per Procedure provided at that time. RD test unit. 33. Clear&clean location. Hand well over to production. 34. File completion reports with proper agencies. Site Access Three Mile Creek #3 will be accessible via existingpublic �'avel roads ("Pan Am Highway/ ., Superior Road") from Beluga or some private (Aurora permitted) roads from Tyonek to the Pan Am Highway. Rig • Aurora Well Service, Rig No. 1 (AWS 1)will be used to drill the TMC #3 well. The Alaska Oil & Gas Conservation Commission has information on this rig and equipment as it has been in use for the last (9) years on other Aurora Gas operations. The pits, BOP system & mud equipment configuration will be the same as that used for previous work. Prepared by Ed Jones Page 4 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan Survey Program The 12-1/4" surface hole will be drilled vertically and the 7-7/8" production hole will be drilled directionally, and the survey program will consist MWD surveys run as required to monitor and control directional hole (and in accordance with rules laid out in 20 AAC 25.050 (a) (1) & (2)). A directiaonl survey will be run at TD. Logging Program Mud loggers will be on site for the duration of drilling activities. Schlumberger(or similar reputable company) will provide wireline logging services as proposed below: Three Mile Creek#3 Proposed Logging Program Well Section Depths(ft) OH CH Log Type 12-1/4"Surface 0'—800' J N/A: No open-hole logs planned for surface at this time. GR only in cased hole. 7-7/8'Production 800'—5000' '1 Platform Express: Array Induction,Compensated Neutron, Hole Litho-Density,SP,GR,and possibly DSI and/or FMUDM.. Also XPT and,possibly, Sidewall cores. 5-1/2"Int.Csg 0'—5000' I GR/CBL/CCL Surface—TD 100'—5000' 1 Mud Logging Services BOP Equipment Aurora Gas, LLC will use the same BOP system they have been using for the last 9 years(except that 12"diverter line was added in 2008),which will consist of the following: 12-1/4" Surface Hole While drilling the 12-1/4" surface hole, a 13-5/8" 5M annular w/ 13-5/8" diverter spool & 12" diverter line will be used: an exception to 20 AAC 25.035 (c)(1)(A), requiring that the diverter 'J r r '- c.e line outlet size be at least 16" diameter or(B) at least as large as the hole size being drilled,will be requested. 7-7/8" Production Hole An 11" 3000 PSI WP Schafco (Shaffer Equivalent)BOP system will be used which is configured with an 11" 3000 PSI WP annular preventer, (1) 3000 PSI WP double gate with a set of pipe rams installed sized to fit the pipe being run and a set of blind rams and (1) 11" 3000 PSI WP rated drilling spool. BOP tests will be performed to 3000 psi./The annular preventer will be Prepared by Ed Jones Page 5 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan tested to 1500 psi. Again, this is the same equipment Aurora has been using all along and information on the system is on file at the AOGCC. Drilling Fluids The drilling fluids will be furnished by Baroid or comparable major mud company, who has extensive experience with drilling activities in this area. An experienced mud engineer will be on site at all times while drilling to monitor properties and make recommendations. Drilling Fluid Properties While Drilling 12-1/4" interval to 800' Glacier Wash Formation Base Fluid Fresh produced water Density 10- pg PV 10- 0 YP 30-40 API Filtrate not controlled Total Solids 15—25 % Bentonite Gel (Aquagen mud system Drilling Fluid Properties While Drilling 7-7/8" interval to 5000' Beluga Formation Base Fluid 3%n Density 9.2pg PV 6-1 YP 13-20 API Filtrate <5 Total Solids 10— 15 % Low Solids Non-Dispersed(LSND)System Drilling Fluid Handling System Shale Shaker, Mud Cleaner, Centrifuge, PVT monitors Prepared by Ed Jones Page 6 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan Drilling Waste Disposal The cuttings will be mixed with saw dust, put into Super Sacks and transported to the Kenai . Borough landfill on the Kenai Peninsula. Drilling mud will be held in tanks for reuse or injection at the Aspen Disposal Well. Brine will be placed in tanks for use in future wells. Casing / Cementing Program All casing is new. Analysis (attached) indicates casing program as designed provides adequate safety factors for this well. All casing strings with the exception of the 13-3/8" conductor will be cemented in place using industry standard casing cementing techniques utilizing a casing shoe, float equipment,top and bottom wiper plugs and centralizers installed as needed. 13-3/8" 72#K-55 Conductor Analysis and Cementing Program The conductor for TMC #3 has been installed by drilling/driving the 13-3/8" pipe to 80'GL/95' RKB. Joints are welded together and a drilling shoe was welded to the bottom joint. No cementing is required. 9-5/8"36#K-55 LTC Surface Casing Analysis and Cementing Program The 9-5/8" surface casing will be cemented from the proposed setting depth of 800' to surface with an accelerated lightweight 12.0 ppg Type I cement system. Capacities: 9-5/8" Csg. Capacity= .0773 bbl/ft and 0.0758 bbl/ft 9-5/8"Csg X 13-3/8"Conductor Capacity=0.0597 bbl/ft 9-5/8" Csg. x 12-1/4" OH Capacity= .0558 bbl/ft System Volume: 9-5/8"X 13-3/8"Annulus: 80 X 0. 0597=4.78 bbl 12-1/4" OH x 9-5/8" Csg: (800'-80) x .0558 bbl/ft x 2 (100%excess)= 80.35 bbls Shoe Jt: 43'x .0758 bbl/ft=3.26 bbls Total Surface Cement Volume=88.4 bbl Actual volumes to be re-calculated at time of running casing due to potential variation in actual depth from planned. Cement System Weight(ppg) bbl cf sx Accelerated Lite Type I 12.0 88.4 496 216 Yield 2.30 cf/sx Please see attached 9-5/8" surface casing analysis and specifications. 5-1/2" 15.5#J-55 LTC Production Casing Cementing Program The 5-1/2" production casing will be cemented in fully from the proposed set depth of 5000' to surface. A 12.0 ppg accelerated light-weight Class "G" lead cement followed with a 14.8 ppg Prepared by Ed Jones Page 7 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan Class G tail cement system (w/extender& gas control) will be used. (The top of the tail may be adjusted upward following the logging program, dependent upon the location of upper most potential pay). This program is designed to insure the intended perforating/production intervals are isolated with tail blend. Capacities: 5-Y2" 15.5#csg capacity= .0238 bbl/ft 5-'/2" 15.5#csg X 7-7/8" OH capacity= .0309 bbl/ft 5-1/4" 15.5#csg X 9-5/8" 36#annular capacity= .0479 bbl/ft Lead System: 9-5/8"x 5-1/2"Csg: 800' +(1800-800') 7-7/8"open hole 800' x .0479 bbls/ft x 1 (0%excess)=38.3 bbls Lead Cement Volume= 38.3 bbl+1000' X .0309 X 1.25 (25%excess)=76.9 bbl Tail System: 7-7/8" OH x 5-W Csg: 5000'-1800' =3200' 3,200' x .0309 bbl/ft x 1.25 (25% excess) =123.6 bbls Shoe Joint: 85' x .0238 bbl/ft=2.0 bbls Total Tail Cement Volume= 125.6 bbls Actual volumes will be calculated at time of running casing due to potential variation in depth from planned and availability of open-hole caliper. Cement System Type Cement Weight(ppg) bbl cf sx Lead @ 2. c sx Class G 12.0 76.9 432 171 Tail @ 1.43 f/sx Class G 14.8 123.6 693 485 Please see attached 5 1/2" production casing analysis and specifications. Pressure Calculations Maximum Anticipated Surface Pressure From offset wells in the immediate area and actual pressure data from the nearby offset well TMC #1, maximum anticipated bottom-hole pressures should not exceed 2605 psi at 5,000 ft. • Pressures measured (MDT) at the Three Mile Creek #1 well indicated a maximum gradient of 0.521 psi/ft, with a bottom-hole pressure of 1644 psia recorded at 3154' TVD (3310' MD). Another MDT pressure taken at 4807' TVD/4970' MD was 2488 psia, for a gradient of 0.518 - psi/ft. Maximum anticipated surface pressures"MASP" can be calculated by subtracting the gas gradient of.1 psi/ft from pore pressure gradient of.521 psi/ft and multiplying by the total TVD depth. • Maximum Anticipated Surface Pressure=(.521 4706' = 1981 psi /. A formation integrity test to 16.0 ppg EMW @ 800' will be conducted while drilling TMC #3, as this has become Aurora's standard test in this area. Assuming casing shoe strength of 16.0 ppg EMW (or 0.83 psi/ft) our estimated Maximum Allowable Surface Pressure during the 7-7/8" interval is expected to be Prepared by Ed Jones Page 8 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan Maximum Allowable Surface Pressure =(.83-.1)*800'=586 psi Drilling Hazards Shallow gas Shallow gas is a known hazard which exists throughout the area. The northwest side of Cook v` Inlet is noteworthy for its shallow gas hazard. All responsible personnel will be made aware and a notice of such hazards will be posted in the rig doghouse. There is no record of H2S in the region, however; a gas detection system capable of detecting H2S as well as methane will be installed on the rig with detectors at the floor level,the shale shaker and in the cellar. Coal Seams The Cook Inlet region is rich in coal seams, inter-bedded between the sands, gravels and shales that make up the Beluga and Tyonek formations. Drilling into a coal seam will appear to be a drilling break when drilled with a tri-cone bit. The major hazard of drilling into a coal seam without observing the proper response is the risk of stuck pipe. The proper course of action for preventing stuck pipe is two-fold. First, prior to drilling, insure the drilling fluid system is up to par, per recommendations from the on-site mud engineer. The second step to successfully drilling through coals in the Cook Inlet area is to not get greedy when coals are encountered. When a coal has been encountered, pull back above coal after drilling into it, and circulate, allowing the coal to stabilize. Re-enter, drill some more, and pull back out again. Continue in this fashion until successfully through the coal bed. The key word in successfully drilling the coal beds is patience. It should be remembered that coals behave plastically, and will flow under the weight of the overburden. The deeper the coal, the more pronounced this tendency becomes. For this reason it is critical to maintain the proper weight and viscosity of the drilling fluid to properly remove the coal cuttings, and to hold flowing coals in place. Again, heed the recommended drilling fluid program and advice offered by the on-site Mud Engineer. Well Proximity Risk There are 3 existing wellbores in this field, the Three Mile Creek #1 and #2 and the Three Mile Creek State #1, all with surface locations 2500' or more from the projected #3 BHL. All were directionally drilled or deviated: the #1 going almost straight east (and will be an estimated 2000' from the #3 well bore, which will be drilled 1688' WNW, at its closest proximity), the #2 being over 3000' away at its closest point, deviated to the northwest, and the TMC State #1 well [P &A'd] will be about 2450' away at its closest point, deviated to the ENE). Thus, there is no well proximity risk. Other Risks Sticky bentonitic clays,boulders, lost returns&differential sticking with overbalanced muds and gas influx while cementing or swabbing while tripping pipe. Prepared by Ed Jones Page 9 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan 2 7/8 6.5#8rd EUE J-55 Tubing r r Aurora Gas, LLC THREE MILE 13.3/8"72#Structural CREEK #1 PrnnncedI Conductor driven to 80'GL Drill 12-1/4"Hole to 800' 9-5/8"360 Surface Casing set at 800' Cement w/12.0 ppg Type 2-7/8" x 5-'/2"annulus to be Accelerated displaced over to inhibited packer Prospective Beluga Pays Tsuga 2-4--1763' Tsuga 2-5—2418' Tsuga 2-6-3587' Perforation Intervals to be determined by open-hole logging. Mechanical Packer @ 2100' 'I suga 2-4.1 Sliding Sleeve @—2450' Hydraulic Set Packer @2600' Sliding Sleeve @—2800'MD Tsuga 2-4.2&2-4.3 .1. Hydraulic Packer @ 3200' Tsuga 2-4.5&2-5.2 . Sliding Sleeve @—3300'MD Hydraulic Packer at —3500'w/X profile nipple . � 4 Tsuga 2-5.4&2-5.5 Frac sleeve @—3600' t} , :, 2 7/8"6.5#EUE 8rd Tubing w/On- �._ Off Tool on Mechanical Packer @ Tsuga 2.6 �! 4500'w/231 profile X nipple Drill 7-7/8"Hole to 5000' MD/4706'TVD 5''h"15.5#J-55 Casing to 5000' (MD/4706'TVD) Estimated PBTD @ 4915' Prepared by Ed Jones Page 10 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan THREE MILE CREEK 3 PROJECTED DRILLING TIME 0 1 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 • -1000 -2000 - D00 —+—s.. a- W 0 -4000 -5000 • • • • • • doh -6000 — – DAY Days 1-3: Drill 12-1/4" Hole Days 3-6: Run and cement 9-5/8" casing Day 6: Test casing, drill out w/ 7-7/8" bit and run FIT, drill 7-7/8" hole. Days 6-14: drill 7-7/8"hole to 5000' MD /TVD Days 15-16: Log Days 17: Run 5-1/2" casing and cement. Days: 18---: Complete and test well. Prepared by Ed Jones Page 11 of 12 Rev. 1.0 • Aurora Gas, LLC Three Mile Creek#3 Drilling Plan THREE MILE CREEK #3 Summary of Drilling Hazards POST THIS NOTICE IN DOGHOUSE There is potential for abnormal pressured shallow gas. Ai There is potential for stuck pipe in coals encountered while drilling from surface to TD. Short trips as dictated by drilling trends. -V There is no H2S risk anticipated for this well. i Due to potential for shallow gas kick, very little response time will • be afforded to respond. PVT and gas detection systems must be fully operational and functioning at all times, visual flow checks and pit level monitoring are critical. Al Due to historic gas production from the field, there is potential to lose circulation in partially depleted sands below 2000'. Visually monitor returns and pit levels. CONSULT THE THREE MILE CREEK #3 WELL PLAN FOR ADDITIONAL INFORMATION Prepared by Ed Jones Page 12 of 12 Rev. 1.0 a M "O N CA (In r-4 00 00 1-1 00 00 O O n a) 742 -p eii v) -4 ,-. En U cn N ,-. .5 .0 a p 2 O -42 GQ Oj 00 0 OD OU og O O U 4. b 3 -•� 4° o tao O2 „,„ o 0. N U4.4 i ‘1"' "100 ,0 CCS a) 0 O N .b 0. 'O 0 V4 t., En'5a) a)) 01) 0 - oo kr, O al ,7:1 o •U a. a) �+ ,.> r> - Q O mOP,5 a) 'C O p 3. 4t 0 XI v0 N O Y `O a_ b ti cp L 'ami ,0 - S� 4" O ..4.i a) C) a) 10 En "al o 0 a) a) a> C Na) ) UHoM y y a) .,t1 a) :; N ) � C p .m N bq = O �O N Q iiiUaDi -U • Cal .E a) U � cn tzs0 ,4 0 O m N U 'C U ` C O a> o Ow aa) Cn 0. NNO 0 U U U ri o U 04 a U o w 0 4-4 U v, F" ,10 k) til vO N a) p -CC 0 ON 0 0• In ti GQ Cl Clen 0 00 71- w � w b0 00 ' C Q -� O p a U K? 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DODO = LA 2 McMains, Stephen E (DOA) From: Bruce D Webb [bwebb@aurorapower.com] Sent: Wednesday, August 24, 2011 10:13 AM To: McMains, Stephen E (DOA) Cc: 'Ed Jones' Subject: FW: TMC 3 Directional Plan Attachments: Sperry TMCU#3 wp06.pdf Good morning Steve, Attached is the Directional Plan for the revised Three Mile Creek#3 PTD 211-071. The revised directional location was submitted on or about July 13, 2011. The proposed bottom hole location has moved, but it is still well within the 1,500' from a property boundary lease: 2,313' FWL / 2,967' FEL and 3,379' FNL / 1,901' FSL - I am assuming, since we never had a spacing exception, or applied for one in the past for this well or location, that the 3,000' notification radius does not apply—as it did for the NCU #10. Please let me and Ed know if we need to submit anything else. Regards, -Bruce Bruce D. Webb Land and Regulatory Consultant Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 (907) 277-1003 office (907) 229-8398 cell (970) 277-1006 fax From: Ed Jones jmailto:jejones@aurorapower.coml Sent: Wednesday, August 24, 2011 9:49 AM To: bwebb@aurorapower.com Subject: TMC 3 Directional Plan Bruce, Here is the directional plan for TMC 3 to be submitted to the AOGCC. Thanks, Ed 1 1 F§ a e Aurora Gas, LLC r � Cook Inlet ' 4; Three Mile Creek Unit Plan: TMCU#3 TMCU#3 • Plan: wp06 Standard Proposal Report 17 August, 2011 z fa a HALLIBURTON Sperry Drilling Services j SECTION DETAILS LAurora Gas, LLC Sec MD Inc Azi TVD +N/-S +E/-W DLeg TFace VSec Target 1 16.0 0.00 0.00 16.0 0.0 0.0 0.00 0.00 0.0 2 1000.0 0.00 0.00 1000.0 0.0 0.0 0.00 0.00 0.0 3 1020.0 0.00 0.00 1020.0 0.0 0.0 0.00 0.00 0.0 4 1705.8 27.43 292.30 1679.9 61.1 -149.0 4.00 292.30 161.1 5 5115.9 27.43 292.30 4706.5 657.1 -1602.6 0.00 0.00 1732.1 TMCU#3 T1 WELLBORE TARGET DETAILS(MAP CO-ORDINATES) Name TVD +W-S +E/-W Northing Easting Shape 0- fff 111 TMCU#3 T1 4706.5 657.1 -1602.6 2622327.00 284232.00 Cirde(Radius:150.0) WELL DETAILS: Plan:TMCU#3 300- Ground Level: 287.5 +N/-S +E-yy Northing Easting Latittude Longitude Slot 0.0 U.0 2621669.89 285834.57 61°10'12.894 N 151°12 47.034 W 600- REFERENCE INFORMATION Co-ordinate(N/E)Reference: Well Plan:TMCU#3,Grid North 9 5/8"x 12.25 hole Start 20.0 hold at 1000.0 MD Vertical(TVD)Reference: TMCU#3 081611 @ 303.5ft(287.5+16) Measured Depth Reference: TMCU#3 081611 @ 303.58(287.5+16) 900- -- Calculation Method: Minimum Curvature Start DLS 4.00 TFO 292.30 SURVEY PROGRAM 1200- - Date:2011-08-17T00:00:00 Validated:Yes Version:4 Tsuga 2-2 Depth From Depth To Survey/Plan Tool 16.0 1000.0 wp06(TMCU#3) BLIND 1000.0 5115.9 wp06(TMCU#3) MWD 1500- Start 3410.0 hold at 1705.8 MD Tsuga 2-3 _-- COMPANY DETAILS: Aurora Gas,LLC Drilling 1800 Tsuga 2-4 Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Tray.Cylinder North c Error Surface: Elliptical Conic 2100- Warning Method: Rules Based O O co - L FORMATION TOP DETAILS N 2400- TVDPath MDPath Formation O Tsuga 2-5 996.5 996.5 Tsuga 2-2 m - 1481.5 1489.9 Tsuga 2-3 o1669.5 1694.1 Tsuga 2-4 "-C _ 2285.5 2388.1 Tsuga 2-5 • 2700- 3387.5 3629.8 Tsuga 2-6 U) - m IL 3000- CASING DETAILS 3300- TVD MD Name Size 1000.0 1000.0 95/8"x 12.25 hole 9-5/8 4705.7 5115.0 7" 7 3600- Tsuga 2-6 3900- 4200- Plan:TMCU#3/wp06 4500- HALLIBURTON Project: Cook Inlet 7° Site: Three Mile Creek Unit TD at 5115.9 Sperry Drilling Services- Well: Plan: TMCU#3 = 4800- Wellbore: TMCU#3 TMCU#3 T1 Plan:wp06(Plan: TMCU#3/TMCU#3) I I I I I I I I I I I I- 1-77-I I I1 I I I I I I I I I I I I I I I I I T I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I -600 -300 0 300 600 900 1200 1500 1800 2100 2400 2700 3000 3300 3600 Vertical Section at 292.30°(600 ft/in) SECTION DETAILS Aurora Gas, LLC Sec MD Inc Azi ND 41/-S +E/-W DLeg TFace VSec Target 1 16.0 0.00 0.00 16.0 0.0 0.0 0.00 0.00 0.0 2 1000.0 0.00 0.00 1000.0 0.0 0.0 0.00 0.00 0.0 3 1020.0 0.00 0.00 1020.0 0.0 0.0 0.00 0.00 0.0 4 1705.8 27.43 292.30 1679.9 61.1 -149.0 4.00 292.30 161.1 Project: Cook Inlet 5 5115.9 27.43 292.30 4706.5 657.1 -1602.6 0.00 0.00 1732.1 TMCU#3 T1 Site: Three Mile Creek Unit Well: Plan: TMCU#3 Wellbore: TMCU#3 Plan:wp06(Plan: TMCU#3/TMCU#3) WELL DETAILS: Plan:TMCU#3 Ground Level: 287.5 SURVEY PROGRAM +N/-S +E/-W Northing Easting Latittude Longitude Slot 0.0 0.0 2621669.89 285834.57 61°10'12.894 N 151°12'47.034 W Date:2011-08-17T00:00:00 Validated:Yes Version:4 Depth From Depth To Survey/Plan Tool WELLBORE TARGET DETAILS(MAP CO-ORDINATES) 16.0 1000.0 wp06(TMCU#3) BLIND 1000.0 5115.9 wp06(TMCU#3) MWD Name TVD +E/-W Northing+N/-5 +ENorthing Easting Shape TMCU#3 T1 4706.5 657.1 -1602.6 2622327.00 284232.00 Circle(Radius:150.0) COMPANY DETAILS: Aurora Gas,LLC CASING DETAILS REFERENCE INFORMATION DrillingCo-ordinate(N/E)Reference: Well Plan:TMCU#3,Grid North ND MD Name Size Vertical(TVD)Reference: TMCU#3 081611 Q 303.5ft(287.5+16) 1000.0 1000.0 95/8"x 12.25 tale 9-5/8 Measured Depth Reference: TMCU#3 081611 8 +16) Calculation Method: Minimum Curvature 4705.7 5115.0 7" 7 Calculation Method: Minimum Curvature Error System:ISCWSA Scan Method: Tray.Cylinder North Error Surface: Elliptical Conic Warning Method: Rules Based West(-)/East(+)(300 ft/in) -1800 -1650 -1500 -1350 -1200 -1050 -900 -750 -600 -450 -300 -150 0 150 I I i i i i I i i i i I i i i i I i i i i I i i i i I i i i i I i i i i l i i i i I I I I I I i I I i I i i i i I i i i i I i i i i I i 1350- -1350 1200- -1200 - I_ Plan:Plan:TMCU#3/wp06 1050- // -1050 80%conf. / TD at 5115.9- - I 900- I / -900 I / I _ I _ a I , ' pb - c 750- -I-4 , n -750 5 1� t - ° + 1 . 1 600- �\ .. ,'_,, I o Start 3410.0 hold at 1705.8 MD -- 600 y S Start DLS 4.00 TFO 292.30 W t - 7"moi-- 1 - o - I 450- Start 20.0 hold at 1000.0 MD -450 5 - TMCU#3 Tl - I - - - 300- I1 -300 1 I - - - - I - .O 5 0O \\` 1 - 150- 5 I -150 S I Is _ HALLIBURTON .,;�� _ 0-- Sperry Drilling Services 9 5/8"x 12.25 hole `o I -150- --150 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I -1800 -1650 -1500 -1350 -1200 -1050 -900 -750 -600 -450 -300 -150 0 150 West(-)/East(+)(300 ft/in) Halliburton Company HALLIBURTON Standard Proposal Report Database: ..Sperry EDM Prod.161 Local Co-ordinate Reference: Well Plan:TMCU#3 Company: Aurora Gas,LLC TVD Reference: TMCU#3 081611 @ 303.5ft(287.5+16) Project: Cook Inlet MD Reference: TMCU#3 081611 @ 303.5ft(287.5+16) Site: Three Mile Creek Unit North Reference: Grid Well: Plan:TMCU#3 Survey Calculation Method: Minimum Curvature Wellbore: TMCU#3 Design: wp06 Project Cook Inlet,COOK INLET BASIN Map System: US State Plane 1927(Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927(NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Three Mile Creek Unit Site Position: Northing: 2,624,191.02ft Latitude: 61°10'37.818 N From: Map Easting: 286,393.49ft Longitude: 151°12'36.591 W Position Uncertainty: 0.0 ft Slot Radius: 0" Grid Convergence: -1.06° Well Plan:TMCU#3 Well Position +N/-S 0.0 ft Northing: 2,621,669.89 ft Latitude: 61°10'12.894 N +E/-W 0.O ft Easting: 285,834.57 ft Longitude: 151°12'47.034 W Position Uncertainty 0.0 ft Wellhead Elevation: 303.5 ft Ground Level: 287.5ft Wellbore TMCU#3 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) bggm2005 10/13/2005 19.93 73.91 55,619 Design wp06 Audit Notes: Version: 4 Phase: PLAN Tie On Depth: 16.0 Vertical Section: Depth From(TVD) +NI-S +E/-W Direction (ft) (ft) (ft) (°) 16.0 0.0 0.0 292.30 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/-S +E/-W Rate Rate Rate Tool Face (ft) (°) (°) (ft) ft (ft) (ft) (°/100ft) (°/100ft) (°I100ft) (°) 16.0 0.00 0.00 16.0 -287.5 0.0 0.0 0.00 0.00 0.00 0.00 1,000.0 0.00 0.00 1,000.0 696.5 0.0 0.0 0.00 0.00 0.00 0.00 1,020.0 0.00 0.00 1,020.0 716.5 0.0 0.0 0.00 0.00 0.00 0.00 1,705.8 27.43 292.30 1,679.9 1,376.4 61.1 -149.0 4.00 4.00 -9.87 292.30 5,115.9 27.43 292.30 4,706.5 4,403.0 657.1 -1,602.6 0.00 0.00 0.00 0.00 8/17/2011 12:54:17PM Page 2 COMPASS 2003.16 Build 71 Halliburton Company HALLIB1. RTDN Standard Proposal Report Database: ..Sperry EDM Prod.161 Local Co-ordinate Reference: Well Plan:TMCU#3 Company: Aurora Gas,LLC TVD Reference: TMCU#3 081611 @ 303.5ft(287.5+16) Project: Cook Inlet MD Reference: TMCU#3 081611 @ 303.5ft(287.5+16) Site: Three Mile Creek Unit North Reference: Grid -- Well: Plan:TMCU#3 Survey Calculation Method: Minimum Curvature Wellbore: TMCU#3 Design: wp06 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (ft) (°) (°) (ft) ft (ft) (ft) (ft) (ft) -287.50 16.0 0.00 0.00 16.0 -287.5 0.0 0.0 2,621,669.89 285,834.57 0.00 0.00 100.0 0.00 0.00 100.0 -203.5 0.0 0.0 2,621,669.89 285,834.57 0.00 0.00 200.0 0.00 0.00 200.0 -103.5 0.0 0.0 2,621,669.89 285,834.57 0.00 0.00 300.0 0.00 0.00 300.0 -3.5 0.0 0.0 2,621,669.89 285,834.57 0.00 0.00 400.0 0.00 0.00 400.0 96.5 0.0 0.0 2,621,669.89 285,834.57 0.00 0.00 500.0 0.00 0.00 500.0 196.5 0.0 0.0 2,621,669.89 285,834.57 0.00 0.00 600.0 0.00 0.00 600.0 296.5 0.0 0.0 2,621,669.89 285,834.57 0.00 0.00 700.0 0.00 0.00 700.0 396.5 0.0 0.0 2,621,669.89 285,834.57 0.00 0.00 800.0 0.00 0.00 800.0 496.5 0.0 0.0 2,621,669.89 285,834.57 0.00 0.00 900.0 0.00 0.00 900.0 596.5 0.0 0.0 2,621,669.89 285,834.57 0.00 0.00 996.5 0.00 0.00 996.5 693.0 0.0 0.0 2,621,669.89 285,834.57 0.00 0.00 Tsuga 2-2 1,000.0 0.00 0.00 1,000.0 696.5 0.0 0.0 2,621,669.89 285,834.57 0.00 0.00 95/8"x12.25 hole 1,020.0 0.00 0.00 1,020.0 716.5 0.0 0.0 2,621,669.89 285,834.57 0.00 0.00 1,100.0 3.20 292.30 1,100.0 796.5 0.8 -2.1 2,621,670.74 285,832.50 4.00 2.23 1,200.0 7.20 292.30 1,199.5 896.0 4.3 -10.5 2,621,674.17 285,824.12 4.00 11.29 1,300.0 11.20 292.30 1,298.2 994.7 10.3 -25.2 2,621,680.24 285,809.33 4.00 27.28 1,400.0 15.20 292.30 1,395.6 1,092.1 19.0 -46.4 2,621,688.90 285,788.21 4.00 50.11 1,489.9 18.80 292.30 1,481.5 1,178.0 29.0 -70.7 2,621,698.87 285,763.90 4.00 76.38 Tsuga 2-3 1,500.0 19.20 292.30 1,491.1 1,187.6 30.2 -73.7 2,621,700.12 285,760.86 4.00 79.67 1,600.0 23.20 292.30 1,584.3 1,280.8 43.9 -107.2 2,621,713.83 285,727.40 4.00 115.83 1,694.1 26.96 292.30 1,669.5 1,366.0 59.1 -144.1 2,621,728.96 285,690.50 4.00 155.72 Tsuga 2-4 1,700.0 27.20 292.30 1,674.7 1,371.2 60.1 -146.6 2,621,729.98 285,688.02 4.00 158.40 1,705.8 27.43 292.30 1,679.9 1,376.4 61.1 -149.0 2,621,731.00 285,685.54 4.00 161.08 1,800.0 27.43 292.30 1,763.5 1,460.0 77.6 -189.2 2,621,747.45 285,645.40 0.00 204.46 1,900.0 27.43 292.30 1,852.3 1,548.8 95.0 -231.8 2,621,764.93 285,602.78 0.00 250.53 2,000.0 27.43 292.30 1,941.0 1,637.5 112.5 -274.4 2,621,782.41 285,560.15 0.00 296.60 2,100.0 27.43 292.30 2,029.8 1,726.3 130.0 -317.1 2,621,799.89 285,517.53 0.00 342.68 2,200.0 27.43 292.30 2,118.5 1,815.0 147.5 -359.7 2,621,817.37 285,474.90 0.00 388.75 2,300.0 27.43 292.30 2,207.3 1,903.8 165.0 -402.3 2,621,834.84 285,432.28 0.00 434.82 2,388.1 27.43 292.30 2,285.5 1,982.0 180.4 -439.9 2,621,850.25 285,394.71 0.00 475.42 Tsuga 2-5 2,400.0 27.43 292.30 2,296.0 1,992.5 182.4 -444.9 2,621,852.32 285,389.65 0.00 480.89 2,500.0 27.43 292.30 2,384.8 2,081.3 199.9 -487.6 2,621,869.80 285,347.03 0.00 526.96 2,600.0 27.43 292.30 2,473.5 2,170.0 217.4 -530.2 2,621,887.28 285,304.40 0.00 573.03 2,700.0 27.43 292.30 2,562.3 2,258.8 234.9 -572.8 2,621,904.76 285,261.78 0.00 619.11 2,800.0 27.43 292.30 2,651.1 2,347.6 252.4 -615.4 2,621,922.23 285,219.15 0.00 665.18 2,900.0 27.43 292.30 2,739.8 2,436.3 269.8 -658.1 2,621,939.71 285,176.52 0.00 711.25 3,000.0 27.43 292.30 2,828.6 2,525.1 287.3 -700.7 2,621,957.19 285,133.90 0.00 757.32 3,100.0 27.43 292.30 2,917.3 2,613.8 304.8 -743.3 2,621,974.67 285,091.27 0.00 803.39 3,200.0 27.43 292.30 3,006.1 2,702.6 322.3 -786.0 2,621,992.15 285,048.65 0.00 849.46 3,300.0 27.43 292.30 3,094.8 2,791.3 339.7 -828.6 2,622,009.62 285,006.02 0.00 895.54 8/17/2011 12:54:17PM Page 3 COMPASS 2003.16 Build 71 Halliburton Company HALLIBURTONI Standard Proposal Report Database: ..Sperry EDM Prod.161 Local Co-ordinate Reference: Well Plan:TMCU#3 Company: Aurora Gas,LLC TVD Reference: TMCU#3 081611 @ 303.5ft(287.5+16) Project: Cook Inlet MD Reference: TMCU#3 081611 @ 303.5ft(287.5+16) Site: Three Mile Creek Unit North Reference: Grid Well: Plan:TMCU#3 Survey Calculation Method: Minimum Curvature Wellbore: TMCU#3 Design: wp06 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (ft) (0) (°) (ft) ft (ft) (ft) (ft) (ft) 2,880.08 3,400.0 27.43 292.30 3,183.6 2,880.1 357.2 -871.2 2,622,027.10 284,963.40 0.00 941.61 3,500.0 27.43 292.30 3,272.3 2,968.8 374.7 -913.8 2,622,044.58 284,920.77 0.00 987.68 3,600.0 27.43 292.30 3,361.1 3,057.6 392.2 -956.5 2,622,062.06 284,878.15 0.00 1,033.75 3,629.8 27.43 292.30 3,387.5 3,084.0 397.4 -969.2 2,622,067.26 284,865.46 0.00 1,047.46 Tsuga 2-6 3,700.0 27.43 292.30 3,449.8 3,146.3 409.7 -999.1 2,622,079.53 284,835.52 0.00 1,079.82 3,800.0 27.43 292.30 3,538.6 3,235.1 427.1 -1,041.7 2,622,097.01 284,792.90 0.00 1,125.89 3,900.0 27.43 292.30 3,627.4 3,323.9 444.6 -1,084.4 2,622,114.49 284,750.27 0.00 1,171.97 4,000.0 27.43 292.30 3,716.1 3,412.6 462.1 -1,127.0 2,622,131.97 284,707.65 0.00 1,218.04 4,100.0 27.43 292.30 3,804.9 3,501.4 479.6 -1,169.6 2,622,149.45 284,665.02 0.00 1,264.11 4,200.0 27.43 292.30 3,893.6 3,590.1 497.1 -1,212.2 2,622,166.92 284,622.40 0.00 1,310.18 4,300.0 27.43 292.30 3,982.4 3,678.9 514.5 -1,254.9 2,622,184.40 284,579.77 0.00 1,356.25 4,400.0 27.43 292.30 4,071.1 3,767.6 532.0 -1,297.5 2,622,201.88 284,537.14 0.00 1,402.32 4,500.0 27.43 292.30 4,159.9 3,856.4 549.5 -1,340.1 2,622,219.36 284,494.52 0.00 1,448.40 4,600.0 27.43 292.30 4,248.6 3,945.1 567.0 -1,382.7 2,622,236.84 284,451.89 0.00 1,494.47 4,700.0 27.43 292.30 4,337.4 4,033.9 584.5 -1,425.4 2,622,254.31 284,409.27 0.00 1,540.54 4,800.0 27.43 292.30 4,426.1 4,122.6 601.9 -1,468.0 2,622,271.79 284,366.64 0.00 1,586.61 4,900.0 27.43 292.30 4,514.9 4,211.4 619.4 -1,510.6 2,622,289.27 284,324.02 0.00 1,632.68 5,000.0 27.43 292.30 4,603.7 4,300.2 636.9 -1,553.3 2,622,306.75 284,281.39 0.00 1,678.75 _ 5,100.0 27.43 292.30 4,692.4 - 4,388.9 654.4 -1,595.9 2,622,324.23 284,238.77 0.00 1,724.83 5,115.0 27.43 292.30 4,705.7 4,402.2 657.0 -1,602.3 2,622,326.85 284,232.37 0.00 1,731.74 7.. 5,115.9 27.43 292.30 4,706.5 4,403.0 657.1 -1,602.6 2,622,327.00 284,232.00 0.00 1,732.14 TMCU#3 T1 Targets Target Name -hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Easting -Shape (°) (°) (ft) (ft) (ft) (ft) (ft) 0.00 360.00 4,706.5 657.1 -1,602.6 2,622,327.00 284,232.00 -plan hits target center -Circle(radius 150.0) 5,115.0 4,705.7 7" 7 8-1/2 1,000.0 1,000.0 9 5/8"x 12.25 hole 9-5/8 12-1/4 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (ft) (ft) ft Name Lithology (0) (0) 2,388.1 2,285.5 Tsuga 2-5 996.5 996.5 Tsuga 2-2 1,489.9 1,481.5 Tsuga 2-3 3,629.8 3,387.5 Tsuga 2-6 1,694.1 1,669.5 Tsuga 2-4 8/17/2011 12:54:17PM Page 4 COMPASS 2003.16 Build 71 Halliburton Company HALLIBURTON Standard Proposal Report Database: ..Sperry EDM Prod.161 Local Co-ordinate Reference: Well Plan:TMCU#3 Company: Aurora Gas,LLC TVD Reference: TMCU#3 081611 @ 303.5ft(287.5+16) Project: Cook Inlet MD Reference: TMCU#3 081611 @ 303.5ft(287.5+16) Site: Three Mile Creek Unit North Reference: Grid Well: Plan:TMCU#3 Survey Calculation Method: Minimum Curvature Wellbore: TMCU#3 Design: wp06 8/17/2011 12:54:17PM Page 5 COMPASS 2003.16 Build 71 TRANSMITTAL LETTER CHECKLIST WELL NAME / l l'�' �� �1� /4 '0 J PTD# -1 I C17 ( "G Development Service Exploratory Stratigraphic Test Non-Conventional Well FIELD (/L I /( c ( / POOL: f/-e Circle Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in Permit No. ,API No. 50- - - . API number are between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - - ) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce / inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non-Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. Rev: 1/11/2008 7 E N cn cu o , ,. :S . 3, CA : : : ; ; ; Q . : . . , ' , . . : . . . . . , . , . . . . . , . ' m' m' , . , . . . . . • . , . . (j ,:. :,, . . • ' —' 0 = '0, , , , , : , , , , : : : : , > : • : O a) C O. E 0 y. , o, , o) co N' y" , am , , 1, d, l0, o, ; io , ; U' , , , ,oaa� �Y ' p3 v, U O a . D' pr Q (` c or a) M, y c wp, N. . 0) U. , y, C , e. >, , O• . 0. G 76 M' N' (C .p-. ,_ U J Y y w a) . O O ' ay • c . o. co • a 4 . as, . • a) . Z �. 0. , y 00 a0, a�j y. �, . UT , . „„co". , . c m C7 O, 3, g, >' > c, n, c. �, , i, •o �, : a) �. , rn, , . Z, : , a-a, : , , o Z o o, o �. QO 7. O. 0` 3. g. 4 C. a co) , >. _: , uor c m m' 60' m' w , , : , , (�r , aQi (/x 3 : Q. c 4 co - o ' Q' w I- 0 Q Q' n, (I) . . . �: . Q: . Q, Q: Z. , j �, FA /,Z \ u A SEAN PARNELL,GOVERNOR ALASKA OIL AND GAS 333 W.7th AVENUE,SUITE 100 CONSERVATION COMMISSION ANCHORAGE,ALASKA 99501-3539 PHONE (907)279-1433 FAX (907)276-7542 J. Edwards Jones Executive Vice President, Engineering - Operations Aurora Gas, LLC 1400 W. Benson Blvd., Suite 410 Anchorage, AK 99503 Re: Three Mile Creek Gas Field, Beluga Gas Pool, Three Mile Creek #3 Aurora Gas, LLC Permit No: 211-071 Surface Location: 367' FEL, 1224' FSL, T13N, R11W, SM, SEC. 34 Bottomhole Location: 1538' FEL, 2287' FSL, T13N,R11W, SM, SEC. 34 Dear Mr. Jones: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, I, Daniel T. Seamount, Jr. Chair DATED this L� day of June, 2011. cc: Department of Fish & Game, Habitat Section w/o encl. (via e-mail) Department of Environmental Conservation w/o encl. (via e-mail) Wrill- STATE OF ALASKA ''�" o�/,3 to II AL. ,KA OIL AND GAS CONSERVATION COM.. 310N n" »i s r' PERMIT TO DRILL 4I4l' z i /Ur 20 AAC 25.005 la.Type of Work 1b.Proposed Well Class. Development-Oil ❑ Service- Winj ❑ Single Zone ❑ -II is •ropose. f. Drill DRedrill 0 Stratigraphic Test ❑ Development-Gas 0Service-Supply 0 Multiple Zone ❑ oalbed G s ii 1 . i• -J t . 1 Will Re-entry ❑ Exploratory ❑ Service- WAG 0 Service-Disp ❑ " ' ,':. as 0 2.Operator Name: 5. Bond: Blanket Q Single Well ❑ 11.Well Name and •mber: Aurora Gas, LLC Bond No NZS 429815 Three 'e Creek#3 3.Address 6.Proposed Depth: 12.Field/Pool : : 1400 W. Benson Blvd, Suite 410,Anchorage AK,99503 MD: 5,000' TVD: 5,000' 4a. Location of Well(Governmental Section): 7.Property Designation: Th -e Mile Creek Gas Field Surface- T. 13 N., R. 11 W., S.M., Section 34 ADL-388233 ` -.eluga�d 'D nedas Pool, ? l• 367'FEL and 1,224'FSL 8.Land Use Permit: ..Approximate •.d Date Top of Productive Horizo 1,386'FEL and 2,263r FSL / none 011 Total Depth 1,538'FEL and 2,287'FSL , 9.Acres in Property: 14.Dist.to ,. est Property: 3,320 acres 2,263'at—productive horizon 4b.Surface Location of Well(State Base Plane Coordinates): 10.KB Elevation 302'MLLW 15.Distance to Nearest Well x-285835- y-2621670- zone: 4 (Height above GL) 15' -et Within Pool: 2,582'at surface 16.Deviated wells: Kickoff depth: feet 17.Maximum Anticipated Pressur=_ in psig(see 20 AAC 25 035) Maximum Hole Angle. degrees Downhole 2,605 psi Surface: 2,105 psi - 18.Casing Program: Specifications Top - Setting Dept, - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 13-3/8" 72# K-55 BW 95' 15' 1 80' 80' N/A _ 12-1/4" 9-5/8" 36/40# J-55/K-55 LTC/BTC 800' surface sf •• 800' 800' 13 ppg,Type 1, 216 sx 7-7/8" 5-1/2" 15.5# J-55/K-55 LTC 5,000' surface \� .ce 5,000 5,000' 12.5/15.8 ppg,Class G, 768 sx' ``v _ ti NN 19. PRESENT WELL CONDITION SUMMARY(To be completed •r Eill and Re-Entry Operations) Total Depth MD(ft): Total Depth TVD(ft): Plugs(measured): \ff .Depth MD(ft): Effect.Depth TVD(ft): Junk(measured): 0% Casing Length Size �� Cement Volume MD TVD ., Conductor/Structural Surface �� V Intermediate Production Liner . Perforation Depth MD(ft): Perforation Depth TVD(ft) 20. Attachments: Property Plat Q BO' Sketch❑ Drilling Program Q Time v.Depth Plot Q Shallow Hazard Analysis Div, er Sketch❑ Seabed Report ❑ Drilling Fluid Program ❑., 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representativ-: Date 22. I hereby certify that the foregoing is true an• correct Contact N Printed Name J.Edward Jone- ilis Title Executive Vice President, Engineering-Operations li 0.1. Signature ,4it Phone (907)277-1003 Date 05/25/2011 Commission Use Only Permit to Dr' API i• tuber: ., Permit App ov 1 See cover letter for other Number: 2I /0 1 50-7i7;5':' -,2.-C;/Src -C.,e�`e-)o' Date: ��\3 1 \\ requirements. ,, Conditions of approval: If box is checked,well may not be used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained in shales: aOther:r C S f $o P {ti 300 0 r ti. . Samples req'd: Yes❑ No[r Mud log req'd: Yes ❑ No [i' HZS measures: Yes❑ No[r Directional svy req'd: Yes Er No ❑ /4v meek.f to zo Mc z.s.o35 (1)(z,, diverfer vts (ia.e vari*t4ceA. i; co.tryWed All em.szt 'rtiSure ±Gitc wt.Klt be wtiaKfa•i.►ted .4r 30 ioua.tet 41}Ste dwra. iCA- . / APPROVED BY THE COMMISSION / 5/ / DATE ,COMMISSIONER ORIGINAL Form 10-401(Revised 7/2009) This permit is valid for 24 months from the date of approval(20 AAC 25.005(g)) Submit in Duplicate Davies, Stephen F (DOA) From: Ed Jones [jejones@aurorapower.com] Sent: Monday, June 06, 2011 4:19 PM To: Davies, Stephen F (DOA) Cc: 'Chad Helgeson'; 'Bruce D Webb' Subject: RE: Three Mile Creek 3 Permit to Drill Application - Need Directional Survey Steve, We will plan to do a directional survey when we do the open hole logs. Thanks, Ed J. Edward Jones Executive Vice President, Eng. &Ops. Aurora Gas, LLC 6051 North Course Dr.,Ste 200 Houston,TX 77072 281-495-9957 (0) 713-899-8103 (C) From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Monday, June 06, 2011 6:40 PM To: Ed Jones Cc: Aubert, Winton G (DOA) Subject: FW: Three Mile Creek 3 Permit to Drill Application - Need Directional Survey Ed, The coordinates provided on the permit to drill application give me enough information to plot the planned well course on my workstation. Fortunately, correlative rights are not an issue since this well is being drilled away from the exterior boundary of lease ASL 388233. Collision avoidance isn't an issue because the nearest well is about 2,200' away, and, under Rule 2 of Conservation Order No. 558, well spacing isn't an issue. However, per regulation 20 AAC 25.050, a directional survey will be required because the well will be deviated (as indicated by the different surface, productive horizon and total depth coordinates provided on the application form) and because of the strong tendency for wellbores on this structure to "walk" up-dip that you describe in your email, below. Regards, Steve Davies AOGCC From: Davies, Stephen F (DOA) Sent: Monday, June 06, 2011 2:29 PM To: 'Ed Jones' Subject: RE: Three Mile Creek 3 Permit to Drill Application - Need Directional Survey Thanks Ed. No, your email below is adequate. I'll attach a copy to the permit to drill and forward it to the Commissioners for review. Regards, Steve Davies AOGCC 1 From: Ed Jones [mailto:jejones@aurorapower.com] Sent: Monday, June 06, 2011 1:02 PM To: Davies, Stephen F (DOA) Cc: 'Chad Helgeson'; 'Bruce D Webb' Subject: RE: Three Mile Creek 3 Permit to Drill Application - Need Directional Survey Steve, This well is intended to be a "straight hole," without directional drilling. However, there will probably be some natural "walk" updip, as the well will cross a fault at a fairly shallow depth, which caused the other 2 Three Mile Creek wells to have 25 deg of deviation before 1000' depths. However, we plan to take precautions to avoid this extreme deviation, but will let it drift up-dip, which is desirable for production potential. If the single-shots surveys show significant deviation, we will run a multi-shot survey when we log. Is this sufficient information, or should I add a brief paragraph to the drilling procedure discussion in the APD? Thanks, Ed J. Edward Jones Executive Vice President, Eng. & Ops. Aurora Gas, LLC 6051 North Course Dr., Ste 200 Houston,TX 77072 281-495-9957(0) 713-899-8103 (C) From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Thursday, June 02, 2011 3:17 PM To:jejones@aurorapower.com Subject: Three Mile Creek 3 Permit to Drill Application - Need Directional Survey Ed, During review of the application for a permit to drill for the Three Mile Creek 3 well, I noticed that there is no directional survey information. Could you please provide it? Thanks, Steve Davies Sr. Petroleum Geologist Alaska Oil and Gas Conservation Commission 907-793-1224 No virus found in this message. Checked by AVG - www.avg.com Version: 10.0.1375 /Virus Database: 1511/3675 - Release Date: 06/02/11 No virus found in this message. Checked by AVG - www.avg.com Version: 10.0.1382 /Virus Database: 1511/3685 - Release Date: 06/06/11 2 t f, , """ * ' c;1',.' '''' _. :,,„„t,'%. p4 * 14, kSCALE41",,P; 4. ce '' ' rt ` ' a , 1 inch = 500 ft :,,,,,,y'#,,,,,,,,,,A' ' . MCU 6 IN. PIPELINE 4# . c v v ' i . ' , %.,4,. ; 4,„ ,:,,',11 :41ctit, ,,,, ,.. 1 44,-,- i If NOTES 1)BASIS OF COORDINATES IS ALASKA STATE .''k' PLANE NAD 27 ZONE 4 FROM A DIRECT TIE �O TO ADL NO.31270. ., Otaila 4. 1" i 2)BASIS OF ELEVATION IS FROM TIDAL �'� ' `+ OBSERVATION ON 9-22-93. DATUM IS MLLW. ALL ELEVATIONS SHOWN HEREON WERE TAKEN ON GROUND. TMCU NO. 3 AS—BUILT '-4: " 3)SECTION LINES SHOWN HEREON ARE GRID N:2621669.899 BASED ON PROTRACTED VALUES. GRID E:285834.567 '.1. .I - `e (A,* - LATITUDE: 61°10'12.894"N "�) I. r.}� ,, LONGITUDE: 151 1247. 44,Nill 034 W -•;-,4i ELEV. 287.5 m; ,1 ..,14;,-,,k:' -,: ' ''‘'''',4*;A ''. , ' '„. ' :',,,,,..:;` ,; a R y ` y ' -- — SEC 35 r CREEK ` '4:‘ OF �g4iiL . ` - . 44'- . �� , r • • +.' ' I' �+ M. SCOTT McLANE: ff • 0. - 4928—S i -- •1,1 � �f ESS;e -.1. g •f y A twiliomotwaiiiimiatiii00040... T /, AS-STA ED SURFACE LOCATION DIAGRAM McLane ConsuLting Inc APPLICANT: ENGINEERING/MAPPING/SURVEI1NG/TESTING - `�Aurora Gas LLC P.O. BOX 468 SOLDOTNA, AK. 99669 ----;•„?..--......_. g VOICE: (907) 283-4218 FAX: (907) 283-3265 EMAIL: msmclane®mclanecg.com PROJECT NO. DRAWN BY: DATE: SEC.LINE LOCATION: Nov.4,05 OFFSETS: PROTRACTED SECTION 34 053032 MSM 367'FEL TOWNSHIP 13 NORTH, RANGE 11 WEST 1244'FSL SEWARD MERIDIAN,ALASKA S rnvl � O 1 N P:110000 0000 0000 O O O LJ N -C v1• v) 0A OO• .0 C cl U Cd m N a p A 3 C 2 O pO .D 00 1:4\ .-00 `. 0< N � 6° 'C°1 2 4) 06' ..t 0 mai a� )• o 0 -� a. ., o °' ,� o ° E03 a as rECO I -0 ] O N V w ,.. 0cn 0c bA iOIk 0 4 0 cdp N y0 C 0 O 0 cN U GJ No O n M t- e m ti �) N ...i d' 00 N OA 0n y .7.1 1. OA C mQO O O , n cc; a) c.) U A •o n O .C) N N bq vCi o y0 a U 'E - cid 'C 0 O cn U V, 'C O C ❑❑ b cd cd U c O F: •n O co O C O-ti O y U p, .-.. U 'C 4 ',-i M M CdC ; O O Cd U U N C 4. 6 --•. U c• dN N Q P-1 H • Oj -1 � �1 0 `"o S C) F -�U HOm N. -j, i p� y.y cn M 4 ' rC C00 AN . eci � oAw o ai a) ap, u y , , M � - C p P., bq • r+ 'n cd — N M M N y P" O O N O c QH C iC1.) O O en $... W Urn A * 0O � _ 4tItv') Py c, N N _000 Co� N N M ? `n C/) 000 N N .-4 S." _ O O� 01 vl 00 00kr) 0 O- 0 U < oC U kr) cci W , Aurora Gas, LLC Three Mile Creek#3 Drilling Plan THREE MILE CREEK #3 Three Mile Creek#3 is a grass-roots well targeting numerous Beluga Gas sands./It is located in the Three Mile Creek Gas Field, drilled from a new pad about 2582' south-south-west of the Three Mile Creek#1 well and facility. It will target Beluga Tsuga 2-3 to Beluga Tsuga 2-6 sands that have produced/are producing in the Three Mile Creek#1 and#2 wells. Pre Rig work 1. The site for the Three Mile Creek(TMC) #3 is a pad constructed in 2005 immediately to the east of the"Superior Road,"just before the short access road to TMC #1 The location is in Sec. 34, T13N, R11W, and the GL is about 287'. 2. A nominally 200' X 300' gravel pad has been built (2005), and 13-3/8" 72#K-55 BFW conductor was driven to +/-80' below GL. Pad will need to be graded and, perhaps, expanded slightly. 3. Build sufficient emergency cuttings containment for planned drilling program on this pad (or the#1 pad), and build containment for diverter line using silt fence. 4. Install cellar&mousehole. Cut off conductor as needed to accommodate diverter system. Drilling Procedure 1. File&insure all necessary permits and applications are in place. 2. MIRU AWS #lin drilling configuration. Install 13-5/8" VG LOK head. 3. Rig up diverter&mud loggers. Test & calibrate all PVT/gas sensor equipment. Provide 24-hr notice to AOGCC inspectors for chance to witness diverter test. 4. Notify AOGCC when ready to start drilling operations. 5. Prepare spud mud system / weight up to 10.0 ppg. Load, strap & drift 800'+ of 9-5/8" 36# J-55 LTC and 40# K-55 BTC surface casing (160' of 40# is in stock, balance is new—confirm that BTC pin X LTC collar is available). Note that float shoe and float collar will be"bucked on" short joints in Kenai—locate and bring to location. 6. PU 12-1/4" mill tooth bit & drill to -800', using 8" & 6-1/2" stabilized BHA (packed hole) w/ float sub and drilling jars. Watch for gas in shallow coals and sands. Attempt to TD in siltstone or claystone, avoid setting surface shoe in a coal bed or sand. If possible, adjust TD to put cement head at floor. (Short joints are available to facilitate this). Take surveys at 400' and 800'—shallow fault will likely cause severe deviation: avoid doglegs—survey more often if needed. 7. Make wiper trip to conductor to condition hole for running 9-5/8" surface casing, POOH, LD 12-1/4" BHA. Prepared by Ed Jones Page 1 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan 8. Run & cement new 9-5/8" 36 and 40# J-55 and K-55 casing @ +/-800', installing 1 centralizer/joint centered on the 1St 4 joints above shoe, & 1 centralizer every 2nd joint across the collars there after. Shoe joint connection at float shoe and float collar must be Baker-Locked. Cementing will be single stage using 13.0 ppg accelerated Type I cement at 100% excess volume. Overdisplace by 1 bbl if plug doesn't bump. Be prepared to treat cement returns with retarder. Leave 6"to 18" of cement in cellar to seal bottom. 9. RD cementers, nipple down diverter, cut casing and install 11" 3M wellhead. 10. RU and test 11" 3M BOP stack and 5M choke manifold. Test stacand s rface 3p IA-equipment to 3,000 psi.' Pressure test 9-5/8" casing to 1,500 psi for k3'minutes or as required on approved Permit to Drill. Mud weight to drill out should be 9.5 ppg at this point. 11. PU 7-7/8" Mill Tooth Bit & 6-1/2" & 4-3/" stabilized BHA w/ float sub and drilling jars. RIH. Drill out shoetrack. Condition / treat mud as needed for cement contamination, drill 20' new formation. Pull back into shoe&perform FIT/ LOT up to 16.0 ppg EMW / 12. RIH and drill 7-7/8" hole to 5000' MD/TVD TD or other depth as directed by Aurora Gas geologist (may slightly deeper, depending upon top of Tsuga 2-6.4 sand). Monitor well and volumes carefully. Be prepared to shut well in and weight up immediately if flow or excessive gas build up in mud is noticed. Monitor hole cleaning and drilling trends, make wiper trips every 500' or so, as needed (back into shoe first time, then just above last wiper trip point thereafter, or as needed). Anticipated mud weights required are 9.2 ppg– 10.2 ppg. Do not exceed fracture gradient determined in step 11. If possible, adjust TD ut cement head on floor. While drilling, load, tally& drift 5-1/2" casing on racks. Notes: 1) May see some depletion below 2400'. 2) Hole will likely want to "walk" updip (to east)—allow it to do so, without any doglegs greater than 1 deg/100'. u -1-7t--xS''''-L c 13. Condition hole, short trip and prepare for running wireline logs. 1,7 L . '0 C : 6 6 14. POOH, rack back drillstring. RU wireline BOP's and lubricator and logging tools. Log 9-5/8" cased hole section w/gamma ray sensor. Log OH section with logging suite including resistivity and porosity logs as directed by Aurora Gas. RD wireline. 15. RIH w/ 7-7/8" drilling assembly to TD & condition hole for running 5-1/2" casing. Ensure cementing head has proper connections (8 Rd LTC) or proper cross-over and is available for quick rig up. 16. POOH while laying down drilipipe & BHA, RU to run casing. Verify cementer's equipment is ready. 17. Install 5-1/2" pipe rams. ` 18. Run 5000' of 5-'/2" 15.5# J-55 LTC casing, installing 1 centralizer per joint centered on 1St 4 joints above shoe, 1 centralizer every 2nd joint in open hole & every 3rd joint inside surface casing (use Turbolator centralizers below/thru each pay sand). Shoe joint connection at float shoe, float collar must be Baker-Locked (80' shoetrack). While running casing, fill every 3rd joint. Be prepared to wash to bottom. NOTE: If depletion Prepared by Ed Jones Page 2 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan We+L and lost circulation .was'encountered while drilling, will add multiple-stage cementer ("DV tool") to casing string,probably about at 3000' and cement in 2 stages. 19. RU cementers, cement per attached cementing program from TD to surface. A sufficient amount of accelerated 12.0 ppg light weight Type I w/ 20% Poz Powder lead cement will be pumped to cover from 1800' up thru the annulus of 9-5/8" to surface. This will be followed by sufficient amount of 14.8 ppg Type I tail blend cement to cover from TD back to 1800'. Excess will be calculated using caliper log data—top of tail slurry will be / determined following evaluation of the logs. Plug will be bumped with clean brine (weight to be determined by wireline XPT testing). If possible reciprocate pipe while displacing cement. Land casing &WOC. 20. RD cementers, nipple down stack, land casing in slips & cut casing. 21. Install 11" X 7-1/16" tubing spool, 7-1/16" X 11" DSA, mud cross and reinstall BOP stack. Pressur test BOP and surface equipment to 3,000 psi. Pressure test casing to reµ 2,000 psi for inutes and record results. IP 10J64- 22. Install 2-7/8"pipe rams. 23. RIH w/ bit & casing scraper on 2-7/8" tubing to float collar. Displace well w/ filtered KC1/NaC1 brine (wt. to be determined from XPT data). Continue to clean brine for perforating by running through centrifuge & filtering. POOH. Strap tubing on TOH to validate tally. A MORE DETAILED PROCEDURE WILL BE PROVIDED AT THIS POINT INCLUDING ' PERFS 24. PU wireline BOP's & lubricator, pressure test all against casing to 1500 psi (or higher if XPT indicated higher gradients). PU GR/CBL/CCL & log 5-1/2" casing to surface. LD logging tools & PU perforating guns, RIH to depth as determined from OH logs and perforate zones of interest. Watch for pressures in casing after shooting. POOH, LD perf gun, RD wireline. (Anticipate perforating about 180' in 12 sands between 2700' and 4750'). 25. RIH w/ bit & casing scraper on 2-7/8" tubing to float collar. Circulate perforating debris from hole. Continue centrifuging & filtering brine until cleaned up. POOH. LD bit & scraper. RU Aurora well test unit, including flare stack. 26. Pick up & assemble completion assembly which will consist of mechanical set packer w/ on-off tool for sump packer to be set above deepest perforated zone (at +/- 4500'), then frac sleeve at +/-3650', and 4 hydraulic packers at +/- 3500', 3200', and 2600', and a mechanical packer 2100' w/ an On-Off tool and w/ sliding sleeves between packers and an expansion joint between the packers at 2600' and 3200'—all sliding sleeves and frac sleeve are to be closed and a pump-out ball-seat below deepest packer (which is compatible with the frac sleeve). RIH with completion on new 2-7/8" 6.5# J-55 8 rd tubing & set completion at appropriate depth, filling tubing as running. (Depending upon frac design, may want to run 3-1/2" L-80 tubing to top packer). Space out, hang off in tubing head & lock down. Drop ball and pressure tubing to 3000 psi (or as required) to test and to set packers. Increase pressure and shear out ball. Install BPV. ND BOP. NU and test tree. Release, rig down,move out rig. Pull BPV. Prepared by Ed Jones Page 3 of 12 Rev.1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan 27. RU frac equipment and tree saver. Frac deepest completion (below deepest packer) with +/- 50,000# 20-40 sand w/ 12.5% 12/20 FlexSand in+/-30,000 gal Lightning 2000 water- based frac fluid. Drop ball to open frac sleeve at +/-3600', and frac 2nd deepest completion w/ 75,000# proppant in 35,000 gal frac fluid. SI well and RD tree saver and frac equipment. 28. Flow back well to clean up. RU & swab in when well dies, if necessary. After well cleans up (several days), perform flow test—get stabilized rate (1 hour minimum). Shut in well & record pressure buildup until stabilized with no change in one hour. DO NOT KILL, but run blanking plug and set in X nipple below 2nd packer from bottom (deepest hydraulic packer). 29. Open deepest sliding sleeve (at +/- 3300"). Test well as per Step 28. DO NOT KILL, but close sliding sleeve. 30. Repeat Step 29 for remaining shallower intervals (3 expected). 31. Open zones for initial production and shut sliding sleeves for other completions (depending upon pressures and test results—likely the 2 deepest completions)—flow to clean up. Shut in. . 32. Run 4-point test of initial production zone as per Procedure provided at that time. RD test unit. 33. Clear& clean location. Hand well over to production. 34. File completion reports with proper agencies. Site Access Three Mile Creek #3 will be accessible via existing public gravel roads ("Pan Am Highway/ Superior Road") from Beluga or some private (Aurora permitted) roads from Tyonek to the Pan Am Highway. Rig Aurora Well Service, Rig No. 1 (AWS 1) will be used to drill the TMC #3 well. The Alaska Oil & Gas Conservation Commission has information on this rig and equipment as it has been in use for the last (9) years on other Aurora Gas operations. The pits, BOP system & mud equipment configuration will be the same as that used for previous work. Survey Program The 12-1/4" surface hole and the 7-7/8" production hole will be drilled vertically, and the survey program will consist of single-shot surveys as required to be obtained at 400-500' intervals in accordance with rules laid out in 20 AAC 25.050 (a) (1) & (2). Prepared by Ed Jones Page 4 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan Logging Program Mud loggers will be on site for the duration of drilling activities. Schlumberger will provide wireline logging services as proposed below: Three Mile Creek#3 Proposed Logging Program Well Section Depths(ft) OH CH Log Type 12-1/4" Surface 0'—800' v N/A: No open-hole logs planned for surface at this time. GR only in cased hole. 7-7/8"Production 800'—5000' v Platform Express: Array Induction,Compensated Neutron, Hole Litho-Density, SP,GR,and possibly DSI and/or FMI/DM.. Also XPT and,possibly, Sidewall cores. 5-1/2"Int. Csg 0'—5000' v GR/CBL/CCL Surface—TD 100'—5000' v Mud Logging Services BOP Equipment Aurora Gas, LLC will use the same BOP system they have been using for the last 9 years (except that 12" diverter line was added in 2008), which will consist of the following: 12-1/4" Surface Hole While drilling the 12-1/4" surface hole, a 13-5/8" 5M annular w/ 13-5/8" diverter spool & 12" diverter line will be used: an exception to 20 AAC 25.035 (c)(1)(A), requiring that the diverter Vc+v«u2 line outlet size be at least 16" diameter or(B) at least as large as the hole size being drilled, will be requested. 7-7/8" Production Hole An 11" 3000 PSI WP Schafco (Shaffer Equivalent) BOP system will be used which is configured with an 11" 3000 PSI WP annular preventer, (1) 3000 PSI WP double gate with a set of pipe rams installed sized to fit the pipe being run and a set of blind rams and (1) 11" 3000 PSI WP rated drilling spool. BOP tests will be performed to 3000 psi. The annular preventer will be tested to 1500 psi. Again, this is the same equipment Aurora has been using all along and information on the system is on file at the AOGCC. Prepared by Ed Jones Page 5 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan Drilling Fluids The drilling fluids will be furnished by Baroid or comparable major mud company, who has extensive experience with drilling activities in this area. An experienced mud engineer will be on site at all times while drilling to monitor properties and make recommendations. Drilling Fluid Properties While Drilling 12-1/4"interval to 800' Glacier Wash Formation Base Fluid Fre or produced water Density 10 ;kPpg PV 10- 3 0-40 API Filtrate not controlled Total Solids 15 —25 Bentonite Gel (Aquagel) mud system Drilling Fluid Properties While Drilling 7-7/8"interval to 5000' Beluga Formation Base Fluid 31)/ (C1 Density 9. 10.249g PV 6-1 YP 13-20 API Filtrate < 5 Total Solids 10— 15 % Low Solids Non-Dispersed (LSND) System Drilling Fluid Handling System Shale Shaker, Mud Cleaner, Centrifuge, PVT monitors Drilling Waste Disposal The cuttings will be mixed with Portland cement, put into Super Sacks and transported to the Kenai Borough landfill on the Kenai Peninsula. Drilling mud will be held in tanks for reuse or injection at the Aspen Disposal Well. Brine will be placed in tanks for use in future wells. Casing/ Cementing Program All casing is new. Analysis (attached) indicates casing program as designed provides adequate safety factors for this well. All casing strings with the exception of the 13-3/8" conductor will be cemented in place using industry standard casing cementing techniques utilizing a casing shoe, float equipment, top and bottom wiper plugs and centralizers installed as needed. Prepared by Ed Jones Page 6 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan 13-3/8" 72# K-55 Conductor Analysis and Cementing Program The conductor for TMC #3 has been installed by drilling/driving the 13-3/8" pipe to 80'GL/95' RKB. Joints are welded together and a drilling shoe was welded to the bottom joint. No cementing is required. 9-5/8" 36# K-55 LTC Surface Casing Analysis and Cementing Program The 9-5/8" surface casing will be cemented from the proposed setting depth of 800' to surface with an accelerated lightweight 12.0 ppg Type I cement system. Capacities: 9-5/8" Csg. Capacity= .0773 bbl/ft and 0.0758 bbl/ft 9-5/8" Csg X 13-3/8" Conductor Capacity=0.0597 bbl/ft 9-5/8" Csg. x 12-1/4" OH Capacity= .0558 bbl/ft System Volume: 9-5/8"X 13-3/8" Annulus: 80 X 0. 0597=4.78 bbl 12-1/4" OH x 9-5/8" Csg: (800'-80) x .0558 bbl/ft x 26100 % excess) = 80.35 bbls Shoe Jt: 43' x .0758 bbl/ft= 3.26 bbls Total Surface Cement Volume=88.4 bbl Actual volumes to be re-calculated at time of running casing due to potential variation in actual depth from planned. Cement System Weight (ppg) bbl cf sx AccelLite Type I 13.0 88.4 496 216 Yield .3 cf/sx Plea a see attached 9-5/8" surface casing analysis and specifications. 5-1/2" 15.5#J-55 LTC Production Casing Cementing Program The 5-1/2" production casing will be cemented in fully from the proposed set depth of 5000' to surface./A 12.5 ppg accelerated lead light-weight "G" cement followed with a 15.8 ppg Class "G" tail cement system will be used. (The top of the tail may be adjusted upward following the logging program, dependent upon the location of upper most potential pay). This program is designed to insure the intended perforating/production intervals are isolated with tail blend. Capacities: 5-%2" 15.5# csg capacity= .0238 bbl/ft 5-%2" 15.5# csg X 7-7/8" OH capacity= .0309 bbl/ft 5-'/2" 15.5# csg X 9-5/8" 36#annular capacity= .0479 bbl/ft Lead System: 9-5/8" x 5-%2"Csg: 800' + (1800-800') 7-7/8" open hole 800' x .0479 bbls/ft x 1 (0% excess) = 38.3 bbls Lead Cement Volume = 38.3 bbl+1000' X .0309 X 1.25 (25% excess)=76.9 bbl Prepared by Ed Jones Page 7 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan Tail System: 7-7/8" OH x 5-'/2' Csg: 5000'-1800' = 3200' 3,200' x .0309 bbl/ft x 1.25 (25% excess) =123.6 bbls Shoe Joint: 85' x .0238 bbl/ft= 2.0 bbls Total Tail Cement Volume= 125.6 bbls Actual volumes will be calculated at time of running casing due to potential variation in depth from planned and availability of open-hole caliper. Cement System Type Cement Weight (ppg) bbl cf sx Lead @ 2.47 cf/sx Type I 12.5 76.9 432 v 175 Tail @ 1.17 cf/sx Class G 15.8 123.6 693 l 593 Please see attached 5 1/2"production casing analysis and specifications. Pressure Calculations Maximum Anticipated Surface Pressure From offset wells in the immediate area and actual pressure data from the nearby offset well TMC #1, maximum anticipated bottom-hole pressures should not exceed 2605 psi at 5,000 ft. Pressures measured (MDT) at the Three Mile Creek #1 well indicated a maximum gradient of 0.521 psi/ft, with a bottom-hole pressure of 1644 psia recorded at 3154' TVD (3310' MD). Another MDT pressure taken at 4807' TVD/4970' MD was 2488 psia, for a gradient of 0.518 psi/ft. Maximum anticipated surface pressures "MASP" can be calculated by subtracting the gas gradient of.1 psi/ft from pore pressure gradient of.521 psi / ft and multiplying by the total TVD depth. Maximum Anticipated Surface Pressure= (.521 - .1) * 5000' — 1054i A formation integrity test to 16.0 ppg EMW @ 800' will be conducted while drilling TMC #3, as this has become Aurora's standard test in this area. Assuming casing shoe strength of 16.0 ppg EMW (or 0.83 psi/ft) our estimated Maximum Allowable Surface Pressure during the 7-7/8" interval is expected to be Maximum Allowable Surface Pressure= (.83-.1)*800'=186'psi Drilling Hazards Shallow gas Shallow gas is a known hazard which exists throughout the area. The northwest side of Cook Inlet is noteworthy for its shallow gas hazard. All responsible personnel will be made aware and a notice of such hazards will be posted in the rig doghouse. There is no record of H2S in the ,-- region, region, however; a gas detection system capable of detecting H2S as well as methane will be installed on the rig with detectors at the floor level, the shale shaker and in the cellar. Coal Seams Prepared by Ed Jones Page 8 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan The Cook Inlet region is rich in coal seams, inter-bedded between the sands, gravels and shales that make up the Beluga and Tyonek formations. Drilling into a coal seam will appear to be a drilling break when drilled with a tri-cone bit. The major hazard of drilling into a coal seam without observing the proper response is the risk of stuck pipe. The proper course of action for preventing stuck pipe is two-fold. First, prior to drilling, insure the drilling fluid system is up to par, per recommendations from the on-site mud engineer. The second step to successfully drilling through coals in the Cook Inlet area is to not get greedy when coals are encountered. When a coal has been encountered, pull back above coal after drilling into it, and circulate, allowing the coal to stabilize. Re-enter, drill some more, and pull back out again. Continue in this fashion until successfully through the coal bed. The key word in successfully drilling the coal beds is patience. It should be remembered that coals behave plastically, and will flow under the weight of the overburden. The deeper the coal, the more pronounced this tendency becomes. For this reason it is critical to maintain the proper weight and viscosity of the drilling fluid to properly remove the coal cuttings, and to hold flowing coals in place. Again, heed the recommended drilling fluid program and advice offered by the on-site Mud Engineer. Well Proximity Risk There are 3 existing wellbores in this field, the Three Mile Creek #1 and #2 and the Three Mile Creek State #1, all with surface locations 2500' or more from the projected #3 BHL. All were directionally drilled or deviated: the #1 going almost straight east (and will be an estimated 2300' from the #3 well bore at its closest proximity), the #2 being over 3000' away at its closest point, deviated to the northwest, and the TMC State #1 well [P &A'd] will be about 2450' away at its closest point, deviated to the ENE). Thus, there is no well proximity risk. Other Risks Sticky bentonitic clays,boulders, lost returns & differential sticking with overbalanced muds and gas influx while cementing or swabbing while tripping pipe. Prepared by Ed Jones Page 9 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan / 0 2 7/8 6.5#8rd EUE J-55 Tubing -'Aurora Gas, LLC ° . THREE MILE ar 13-3/8"72#Structural CREEK #1 PrnnncPd • Conductor driven to 80'GL ):: .e.k, . Drill 12-1/4"Hole to 800' + 9-5/8"36#Surface Casing set at 800' ' 1a � "' Cement w/12.0 ppg Type I 2-7/8" x 5-'h"annulus to be ; Accelerated displaced over to inhibited packer :; e I Prospective Beluga Pays Tsuga 2-44-2200' Tsuga 2-5-3300' i Tsuga 2-6—4000' e A Perforation Intervals to be i determined by open-hole logging. • Mechanical Packer @ 2100' I Tsuga 2-4.1 Sliding Sleeve @—2450' I X Hydraulic Set Packer @ 2600' 04) Tsuga 2-4.2&2-4.3 Yom.-. ...t`'1" Sliding Sleeve @—2800'MD Hydraulic Packer @ 3200' Tsuga 2-4.5&2-5.2 .-- Sliding Sleeve @—3300'MD Hydraulic Packer at —3500'w/X profile nipple Frac sleeve @—3600' Tsuga 2-5.4&2-5.5 Is itow ____ 2 7/8"6.5#EUE 8rd Tubing w/On- Off Tool on Mechanical Packer @ Tsuga 2.6iiit, 4500'w/2.31 profileX nipple s Drill 7-7/8"Hole to 5000' e •_ MD/TVD �,,.. 'lb: _... ":' F f 5 Y:"15.5#J-55 Casing to 5000'(MD/TVD) w Estimated PBTD(ii 4915' 0 Prepared by Ed Jones Page 10 of 12 Rev.1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan THREE MILE CREEK 3 PROJECTED DRILLING TIME -1000 ik -2000 - 00 �� .. —r—S.. Li/ O -4000 � j, ,� � � _ __ ' '/ ,5; Esq ' f, -5000 , JUIIIJI% / ''%'' 1 '. 4,.:4: '',..ki.-%%% , ,' - ', Irt \ , ,1%;',1 , '''' , '':. ' %' ,:, , /•e, - ♦ ► ' t ' 1 / am s . Vii, P -6000 DAY Days 1-3: Drill 12-1/4" Hole Days 3-6: Run and cement 9-5/8" casing Day 6: Test casing, drill out w/ 7-7/8"bit and run FIT, drill 7-7/8"hole. Days 6-14: drill 7-7/8"hole to 5000' MD /TVD Days 15-16: Log Days 17: Run 5-1/2" casing and cement. Days: 18---: Complete and test well. Prepared by Ed Jones Page 11 of 12 Rev. 1.0 Aurora Gas, LLC Three Mile Creek#3 Drilling Plan THREE MILE CREEK #3 Summary of Drilling Hazards POST THIS NOTICE IN DOGHOUSE ✓ There is potential for abnormal pressured shallow gas. There is potential for stuck pipe in coals encountered while drilling from surface to TD. Short trips as dictated by drilling trends. ✓ There is no H2S risk anticipated for this well. ✓ Due to potential for shallow gas kick, very little response time will be afforded to respond. PVT and gas detection systems must be fully operational and functioning at all times, visual flow checks and pit level monitoring are critical. CONSULT THE THREE MILE CREEK #3 WELL PLAN FOR ADDITIONAL INFORMATION Prepared by Ed Jones Page 12 of 12 Rev. 1.0 OVERSIZED DOCUMENT INSERT This file contains one or more oversized documents. These materials may be found in the original hard file or check the parent folder to view it in digital format. TRANSMITTAL LETTER CHECKLIIST WELL NAME I /WI,le PTD# - / ( Development Service Exploratory Stratigraphic Test Non-Conventional Well / ` FIELD:1 l i-* - /t( r j ( L POOL: � C �' ` i Circle Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in Permit No. ,API No. 50- - - API number are between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - - ) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce / inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non-Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name)must contact the Commission to obtain advance approval of such water well testing program. 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E O ac) C 0 N 0 -Uo C Q 0 !— 0 00 O .0 .� N @ n O d 7 U > > 3 7 7 a) C) W W 0 3 N a) '-' d a) N N J < c E m 0- m a) m a) a`) 0 E E 0 a) 3 a) c .0 H H H '� g ami > = a a o Y`o 0`n 0 E m 0 0 c io o a) a) c 7 0 n a a) a) ° 0 7 2 2 2 as V ° .0 `0 = O O L a) a) CO a) a) o 0 ✓ 0 z a J D 5 5 5. (n ± O O a a U 5 Q a U (n U U U U < Q , a co co U 5 N 2 a Q (n (n U coILIn I r O • N (�') V (O O W 0) O N M V (() (C h W O) O N M <t U) co' h a0 aA (N co V U) co r co 0) �- N N N N N N N N N N M M M M M M M M M U U CH .a) p 0 0 a) p c C 0 C CO N (6 N (6 N U 0 Ct r 0 Cl CO G a N on V) LLI O 16 (0 C C. 0 N CL _ r 0 C _I N E a) co O 4 c C. Q O G Lu d Q < Ci)Q w Q 5 < 0 0 Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simplEfy finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. Technical Report Title Date Client: Aurora Gas, LLC Field: Three Mile Creek Gas Field Rig: AWS #1 Date: November 1, 2011 Surface Data Logging End of Well Report Three Mile Creek #3 TABLE OF CONTENTS 1. General Information 2. Daily Summary 3. Morning Reports 4. Bit Record 5. Mud Record 6. Formation Tops 7. Survey Report 8. Days vs. Depth Digital Data to include: Final Logs Halliburton Log Viewer EMF Log Viewer ASCII/LAS Files End of Well Report in PDF format ADI Backup GENERAL WELL INFORMATION Company: Aurora Gas, LLC Rig: AWS-1 Well: Three Mile Creek #3 Field: Three Mile Creek Gas Field Borough: Kenai State: Alaska Country: United States API Number: 50-283-20156-00 Sperry Job Number: AK-AM-8370362 Job Start Date: 28 Sept 2011 Spud Date: 28-Sept-2011 Total Depth: 5159.00 North Reference: True Declination: 17.956 Dip Angle: 73.989 Total Field Strength: 55682 Date Of Magnetic Data: 01 Oct 2011 Wellhead Coordinates N: 61° 10’ 12.89” N Wellhead Coordinates W: 151° 12’ 47.03” W Drill Floor Elevation 302.17’ Ground Elevation: 287.5 Permanent Datum: Mean Sea Level SDL Engineers: Steve Gales David LaSalle Mark Lindloff Company Geologist: Ed Jones Company Representatives: Gary Goerlich, Mike Grubb Shane McGeeham SSDS Unit Number: 117 DAILY SUMMARY 9/27-9/29/2011 Mudloggers arrived on location. Performed rig site assessment and inspected mudlogging unit. Met with Company Man and Tool Pusher to discuss logistics and rig timelines. Mudloggers ran preliminary sensor cables. Rig began picking up BHA to clean out the conductor. 9/30/2011 Run in the hole with bottom hole assembly (BHA). Drill to 480’. Crown wheel down for repair. No depth tracked for 12 ¼” section. No gas to report. 10/01/2011 Continue Drilling to 900’ MD. Circulate hole clean. Crown wheel in operation. 10/02/2011 Circulate until clean returns, pull out of hole. Make a wiper trip then pull out of hole. Lay down BHA. Run 9.625” casing to 865’. Circulate hole clean for cement job the cement casing. 10/03/2011 Rig down cementers and then nipple down diverter. Cut casing and wait for it to cool. 10/04/2011 Rig up and test Blow out preventer stack (BOPS) and choke. Currently testing BOPS at report time. 10/05/2011 Finish testing BOPs. Pick up and Run in hole with 8 ½ " Mill Tooth BHA.. Tagged cement at 821'. Try to test casing to 1500 PSI. Unable to test. Pull out of hole (POOH) and lay down BHA. Rig up to run in the hole (RIH) with RTPS and RIH with the same 10/06/2011 Pressure test casing with RTPS. Pressure bled off at shoe. POOH and Lay Down RTPS Pick Up BHA and run in the hole. Drill out cement. Currently dumping and cleaning pits. 10/07/2011 Drill out cement from 825’ to shoe track at 900 ft. Circulate until clean and pull into casing and build 200 bbls of mud. Displace well with new mud and drill 20’ of new formation Circulate well clean and run Formation Integrity Test to 16.2 ppg Estimated mud weight Drill ahead to 973’ MD. 10/08/2011 Drilled from 979 to 1400, Perform wiper trip to shoe, RIH, Drill ahead to 1510’ MD. No losses down hole to report for the day. Average rate of penetration (ROP) for the day was 20 ft/hr with a max ROP of 72 ft/hr. Average Gas was 24 units with a Max Gas of 205 units. Samples 100% Claystone: grey, soft, gummy, amorphous. 10/09/2011 Continue to drill from 1510’ to 1910’, POOH to 1510’ for a wiper trip , RIH, Drill ahead to 2046. No losses to report down hole for the day. Average ROP for the day 34 ft/hr with a max ROP of 175 ft/hr at 1528’MD Average Gas for the day 95 units with a max gas of 362 units at 1758’ MD. Samples remain predominately claystone with a coal stringer starting at 1910’ to 1930’. 10/10/2011 Drill ahead from 2046' to 2410'. POOH 500' for wiper trip. No problems. RIH and drill ahead to 2566'. No losses to report down hole for the day. Average ROP for the day 45 ft/hr with a max ROP of 286 ft/hr at 2443’ md. Average gas for the day 145 units with a Max Gas of 1198 units at 2186’MD. Sample becoming sandier with increase in sand stringers and more coal was observed, 10/11/2011 Drill ahead from 2566' to 3008'. Pump 25 bbl Hi-Vis sweep (100% increase in cutting at shakers). POOH to check bit. Currently pulling out of the hole. Average ROP for the day 62 ft/hr with a max ROP of 137 ft/hr at 2932’ MD. Average gas for the day 107 units with a Max Gas of 464 units at 2861’ MD. 10/12/2011 POOH from 1900' to change out motor, check bit and change pump liners. 10/13/2011 POOH from 1900, changed out bit, motor and pump liners. 10/14/2011 Finish changing pump liners. Run in hole to bottom and circulate to condition mud. Drill from 3008’ to 3386' MD. Average ROP for the day 43 ft/hr with a max ROP of 167 ft/hr at 2932’ MD. Average gas for the day 76 units with a Max Gas of 960 units of trip gas at bottoms up. Samples remain claystone with an occasional coal and sand stringer. 10/15/2011 Drill ahead from 3800' to 4010'. Pump 25 bbl Hi-Vis sweep (100% increase in cuttings at shakers). Short Trip 500' for short/wiper trip. Circulate hole clean and Run in hole. Circulate hole clean again and drill ahead to 4224' MD. Average ROP for the day 10 ft/hr with a max ROP of 292 ft/hr at 4221’ MD. Average gas for the day 97 units with a Max Gas of 490 units of short trip gas at bottoms up. Samples increasingly sandy with scattered coal stringers. 10/16/2011 Drill ahead from 4204' to 4487'. Pump 25 bbl Hi-Vis sweep (150% increase in cuttings at shakers).Pull out of hole 500' for short/wiper trip. Circulate hole clean. Run in hole to bottom and circulate hole clean. Drill ahead to 4578'. Average ROP for the day 45 ft/hr with a max ROP of 204 ft/hr at 4559’ md. Average gas for the day 111 units with a Max Gas of 446 units at 4395’ md. Samples remaining sandy with scattered coal stringers, samples becoming heavily contaminated with calcium chloride. 10/17/2011 Drill ahead from 4550' to 5012'. Average ROP for the day 10 ft/hr with a max ROP of 292 ft/hr at 4221’ MD. Average gas for the day 75 units with a Max Gas of 446 units at 4837’ MD. Samples increasing in claystone until 5000’ md then becoming sandy. Samples continue to be contaminated with calcium chloride 10/18/2011 Drill ahead from 5012' to 5070'. Pump 25 bbl Hi-Vis sweep (400% increase in cuttings at shakers). Drill ahead to 5127’, circulate bottoms up, coal increase to 75% in samples, drill another 15 feet to 5142’ md. Circulated bottoms up and coal decreased to less than 10%.TD well at 5142'. Pull out of the hole 500’ for short/wiper trip. Run in hole to bottom and Pump 25 bbl Hi-Vis sweep (100% increase in cuttings at the shakers). Begin pulling out of hole with no problems. Average ROP for the day 10 ft/hr with a max ROP of 250 ft/hr at 5017’ MD. Average gas for the day 88 units with a Max Gas of 450 units at 5141’ MD. Samples increasing to 100% claystone at TD. 10/19/2011 Finish pulling out of hole. Lay down bottom hole assembly. Test BOPS Rig up and run in with wire line tools, Could not get past 1960’ md. Pull out and run in hole with a clean out assembly for a cleanout run. 10/20/2011 Continue to run in the hole with a for clean-out bottom hole assembly. Started circulating, mud really thick, continue to circulate till mud is even in and out, Trip Gas 365 units. Continue circulating to condition mud and drilled an extra 17’ to 5159’. Pull out of hole to 1800’ and circulate hole clean. Continue to pull out of the hole. 10/21/2011 Finish Pulling out of the hole then rig up and run wireline logs 10/22/2011 Finished wireline logs, rig down wireline, Pick up and run in hole for cleanout run. Circulated and conditioned hole 261 units of trip gas. Pull out of hole. Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth Lst 92' 100 Max: Sh Chromatograph (ppm) H2S Data Sample Line Avg: Milltooth Siltst ClystChtSd AWS#1 AK-AM-8370362 PVMBT Max @ ft Current 1 09/30/2011 100 12.25 1.031 (ppb Eq)cP Size Aurora Gas TMCU #3 North Cook Inlet Three Mile Creek Unit Daily Charges Avg ml/30min Min Avg pH Chlorides GvlCoal mg/l AvgMin Max Max API Filt 2.7900 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke22 TIH 85 Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ % Depth R.O.P. (ft/hr) Gas (units) Hole Condition On Bot Hrs Avg Diam Max: Gas (units) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air We are continuing to Rigup and Troubleshoot equipment while they are TIH. md Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) Gas (units) Avg Diam Max: Depth R.O.P. (ft/hr) Gas (units)47 PWD Drilling All Circ % 542' TIH 89 481.48'MD Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 948 2.7900 389 154 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 6.8 mg/l AvgMin Max Max API Filt 8.00 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 22 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 10.00 3393 Three Mile Creek Unit 2 10/01/2011 542'MD 12.25 1.031 (ppb Eq)cP Size 2610.00 AWS#1 AK-AM-8370362 PVMBT Max @ ft Current 20.0 Milltooth Siltst ClystChtSd 480' H2S Data Sample Line Avg: 25 75 Sh Chromatograph (ppm) Depth 5.0 Lst 100 Max: Avg:Ambient Air Pit Room Silt Tuff Gas Breakdown Ann Corr Cor Solids (lb/100ft2) 500 Sst 24 hr Max YP to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air md We continued to rigup while the rig continued to Drill. A lot of progress was made today, the rig floor monitor and the Stoke Counters were both fixed and are up and running. We calibrated and set flows on the THA. We have had a Backbground Gas of 35 units of gas since hitting Coal at approximately 451'MD. Steve Gales, Jr Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 500 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 6.0 Lst 92' 100 Max: 75 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 25 20.0 Milltooth Siltst ClystChtSd 900' AWS#1 AK-AM-8370362 PVMBT Max @ ft Current 3 10/03/2011 900'MD 12.25 1.031 (ppb Eq)cP Size 1610.00 Aurora Gas LLC TMCU #3 North Cook Inlet 10.00 4680 Three Mile Creek Unit Daily Charges Avg 0 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 6.8 mg/l AvgMin Max Max API Filt 8.50 261 2.7900 0 0 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 0 Casing/Cement 0 900' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % Depth R.O.P. (ft/hr) Gas (units)0 Avg Diam Max: Gas (units) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In AirSteve Gales, Jr./David LaSalle POOH,LD, Run in Casing ,LD BHA, RIC,Cemen Casing. md Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP 726 1-1-NO-A-E-I-NO-TD Ann Corr Cor Solids (lb/100ft2) 500 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 7.0 Lst 92' 100 Max: 808' 0 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 0 20.0 Milltooth Siltst ClystCht 900' Sd 900' AWS#1 $3,445.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 4 10/04/2011 900'MD 12.25 1.031 (ppb Eq)cP Size 2210.00 Aurora Gas LLC TMCU #3 North Cook Inlet 10.00 1548 28.61 Three Mile Creek Unit Daily Charges Avg 0.0 0 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 6.8 mg/l AvgMin Max Max API Filt 9.00 24 2.7900 $16,880.00 0 0 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 0 Cement 0 900' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 0' Depth R.O.P. (ft/hr) Gas (units)0 Avg Diam Max: Gas (units) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In AirSteve Gales, Jr. / David LaSalle RD Cementers, nipple down diverter, Cut Casing, waitint on casing to cool. md Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) Gas (units) Avg Diam Max: 0' Depth R.O.P. (ft/hr) Gas (units)0 PWD Drilling All Circ % 0 Testing BOP 0 900' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 10 2.7900 $19,950.00 0 0 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 6.8 mg/l AvgMin Max Max API Filt 9.00 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 0.0 0 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 10.00 1449 28.61 Three Mile Creek Unit 5 10/05/2011 900'MD 12.25 1.031 (ppb Eq)cP Size 2310.00 AWS#1 $3,070.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 20.0 Milltooth Siltst ClystCht 900' Sd 900' H2S Data Sample Line Avg: 0 808' 0 Sh Chromatograph (ppm) Depth 7.0 Lst 92' 100 Max:Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: 1-1-NO-A-E-I-NO-TD Ann Corr Cor Solids (lb/100ft2) 500 Sst 24 hr Max YP 726 to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air md Testing BOP stack and choke. Steve Gales, Jr. / David LaSalle Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP 00 0-0-NO-A-E-I-NO-HP Ann Corr Cor Solids (lb/100ft2) 500 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 7.0 Lst 900' 200 Max: 0' 0 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 0 20.0 Milltooth Siltst ClystCht 900' Sd 900' AWS#1 $3,070.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 6 10/06/2011 900'MD 12.25 1.031 (ppb Eq)cP Size 229.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1446 0.00 Three Mile Creek Unit Daily Charges Avg 0.0 0 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 6.8 mg/l AvgMin Max Max API Filt 9.00 5 2.7900 $23,020.00 0 0 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 0 RIH, w/t RTPS 0 900' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 0' Depth R.O.P. (ft/hr) Gas (units)0 Avg Diam Max: Gas (units) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In AirMark Lindloff / David LaSalle Testing BOP stack and choke.tested casing, unable to test, POOH and LD, BHA, RIH, w/t RTPS @ time of report. md Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) Gas (units) Avg Diam Max: 876' 0' Depth R.O.P. (ft/hr) Gas (units)0 PWD Drilling All Circ % 0 RIH, w/t RTPS 4 876' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 385 2.79 $27,080.00 306 140 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 6.8 mg/l AvgMin Max Max API Filt 9.00 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 0.0 1 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1145 Three Mile Creek Unit 7 10/07/2011 900'MD 8.5 0.991 (ppb Eq)cP Size 249.50 AWS#1 $4,060.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 20.0 Tricone Siltst ClystChtSd 900' H2S Data Sample Line Avg: 00 Sh Chromatograph (ppm) Depth 9.0 Lst 300 Max:Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Ann Corr Cor Solids (lb/100ft2) 500 Sst 24 hr Max YP to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air md POOH and LD, BHA, RIH, w/t RTPS /PU BHA,TIH,Drill out cement @ time of report Mark Lindloff/ David LaSalle Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 500 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 5.0 Lst 300 Max: 100 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 0 0.3 Tricone Siltst ClystChtSd 950' AWS#1 $4,060.00 AK-AM-8370362 PVMBT 32.0 Max @ ft Current 46.0 8 10/08/2011 970'MD 8.5 0.991 (ppb Eq)cP Size 119.40 Aurora Gas LLC TMCU #3 North Cook Inlet 9.40 2255 Three Mile Creek Unit Daily Charges Avg 8.3 24 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 3.8 mg/l AvgMin Max Max API Filt 8.00 684 2.79 $31,140.00 344 140 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 0 RIH, w/t RTPS 71 966' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 972' Depth R.O.P. (ft/hr) Gas (units)20 973' Avg Diam Max: Gas (units) G Cto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In AirMark Lindloff/ David LaSalle 929.00 930.00 POOH and LD, BHA, RIH, w/t RTPS /PU BHA,TIH,Drill out cement @ time of report md 7 BG C1-2700 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 14,000 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 4.6 Lst 300 Max: 100 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 0 0.5 Tricone Siltst ClystChtSd 1510' AWS#1 $3,070.00 PVMBT 10.0 Max @ ft Current 72.0 9 10/09/2011 970'MD 8.5 0.991 (ppb Eq)cP Size 189.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 2252 Three Mile Creek Unit Daily Charges Avg 19.9 24 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 4.8 mg/l AvgMin Max Max API Filt 9.00 1551 2.79 $34,210.00 502 173 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 0 RIH, w/t RTPS 205 1361' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 1320' Depth R.O.P. (ft/hr) Gas (units)46 Avg Diam Max: Gas (units) G Cto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air Mark Lindloff/David LaSalle 1360.00 1320.00 130 BG 1361.00 1322.00 Drilled from 979 to 1400, POOH, wiper trip to shoe, RIH, Drill ahead to 1510 @ time of report. md C1-13577 205 FG C1-22101 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 13,000 Sst Ambient Air Pit Room 10 Silt Tuff Gas Breakdown Avg: Depth 4.3 Lst 300 Max: 90 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 0 0.5 Tricone Siltst ClystChtSd 2046' AWS#1 $3,070.00 PVMBT 23.0 Max @ ft Current 175.0 10 10/10/2011 970'MD 8.5 0.991 (ppb Eq)cP Size 219.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 2050 Three Mile Creek Unit Daily Charges Avg 34.0 95 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 5.9 mg/l AvgMin Max Max API Filt 8.50 1785 2.79 $37,280.00 493 170 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 0 Drilling 362 1758' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 1528' Depth R.O.P. (ft/hr) Gas (units)92 Avg Diam Max: Gas (units) CG Cto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air Mark Lindloff/David LaSalle 1559.00 1755.00 1990.00 1993.00 304 362 CG C1-11985 1560.00 1758.00 Drilled from 1510 to 1910, POOH, to 1510 wiper trip , RIH, Drill ahead to 2046 @ time of report. md 2024.002022.00 FG 103 BG C1-36296 C1-42982 299 CG C1-25814 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP C Ann Corr Cor Solids (lb/100ft2) 14,000 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 4.5 Lst 300 Max: 90 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 10 0.4 Tricone Siltst ClystChtSd 2566' AWS#1 $3,070.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 137.0 11 10/11/2011 2566'MD 8.5 0.991 (ppb Eq)cP Size 199.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1647 Three Mile Creek Unit Daily Charges Avg 46.0 109.0 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 5.8 mg/l AvgMin Max Max API Filt 8.50 1807 2.79 $40,350.00 470 160 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 0 Drilling 464.0 3009' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 3008' Depth R.O.P. (ft/hr) Gas (units)1 Avg Diam Max: Gas (units) G Cto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air C2-8.72 David LaSalle Mark Lindhoff 2384.00 2410.00 1521.00 1522.00 72 395 T 2390.00 2412.00 Drilled from 2046 to 2410, POOH, 500' wiper trip , RIH, Drill ahead to 2566 @ time of report. md 2455.002453.00 BG 251 CG C1-36352 740 FG C1-76437 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 15,000 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 4.3 Lst 300 Max: 0 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 0 1.0 Tricone Siltst ClystChtSd 3008' AWS#1 $3,070.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 187.0 12 10/12/2011 3008'MD 8.5 0.991 (ppb Eq)cP Size 289.60 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 2579 Three Mile Creek Unit Daily Charges Avg 62.0 119 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 5.7 mg/l AvgMin Max Max API Filt 9.50 20 2.79 $43,420.00 0 0 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 0 Tripping 464 2584' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 2567' Depth R.O.P. (ft/hr) Gas (units)1 Avg Diam Max: G Gas (units) Cto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle/ Mark Lindhoff 2649.00 FG 272 C1-33028.92 134 464 2662.00 2672.00 2675.00 CG 2861.00 CG 168 C1-41046.70 FG 2650.00 2664.00 C1-46607.30 230.002929.00 BG2985.00 C1-14775.17 2860.00 Drilled from 2066 to 3008, POOH, pumped 25 bbl sweep Hi Vis(100%) increase in cuttings at shakers POOH. md 2722.002720.00 2989.00 358 FG 234 C1-24131.99 C1-16881.45 BG 176 C1-8357.90 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP 4510.49 1-1-CT-A-E-I-NO-RIG Ann Corr Cor Solids (lb/100ft2) 15,000 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 4.2 Lst 900' 300 Max: 2108' 0 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 0 1.3 Tricone Siltst ClystCht 3008' Sd 3008' AWS#1 $3,070.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 13 10-13-11 3008'MD 8.5 0.991 (ppb Eq)cP Size 259.70 Aurora Gas LLC TMCU #3 North Cook Inlet 9.70 2788 53.28 Three Mile Creek Unit Daily Charges Avg 0.0 106 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 6.8 mg/l AvgMin Max Max API Filt 8.50 0 2.34 $46,490.00 0 0 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 0 Tripping 464 2861' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 0' Depth R.O.P. (ft/hr) Gas (units)0 Avg Diam Max: Gas (units) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle /Mark Lindhoff FG 272 C1-33028.92 464 2830.00 2834.00 CG 2861.00 C1-41046.70 FG C1-46607.30 230.002929.00 2860.00 POOH from 1900, changed out bit, motor and pump liners. md 2722.002720.00 358 BG 105 C1-12890.18 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) G Gas (units) Avg Diam Max: 3380' Depth R.O.P. (ft/hr) Gas (units)78 PWD Drilling All Circ % 80 Drilling 957 2971' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 1770 2.345 $49,560.00 428 158 Total Charges: Flow (SPM) SPP (psi) Gallons/stroke 6.8 mg/l AvgMin Max Max API Filt 8.00 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 42.0 106 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 2556 Three Mile Creek Unit 14 10-14-11 3088'MD 8.5 0.991 (ppb Eq)cP Size 239.50 AWS#1 $3,070.00 AK-AM-8370362 PVMBT 34.0 Max @ ft Current 58.0 1.0 Milltooth Siltst ClystChtSd 3088' H2S Data Sample Line Avg: 40 30 Sh Chromatograph (ppm) Depth 4.8 Lst 400 Max:Ambient Air Pit Room 30 Silt Tuff Gas Breakdown Avg: Ann Corr Cor Solids (lb/100ft2) 15,000 Sst 24 hr Max YP to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air FG 151 C1-17771.43 C1- 12361.06 TG 957 3200.00 189 md 3206.00 RIH , Drill to 3386 @ time of report. C1-95327.20 3340.003338.00 3660.00 2971.00 3103.003100.00 3120.00 3121.00 FG 3665.00 CG 160 C1-22100.20 FG 821 FG 252 C1-30244.25 2969.00 David LaSalle /Mark Lindhoff Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) G Gas (units) C Avg Diam Max: 3649' Depth R.O.P. (ft/hr) Gas (units)78 PWD Drilling All Circ % 736 Drilling 306 3692' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 1988 2.345 $52,630.00 428 420 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 6.8 mg/l AvgMin Max Max API Filt 8.50 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 10.6 76 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 3072 Three Mile Creek Unit 15 10-15-11 3824 8.5 0.991 (ppb Eq)cP Size 269.50 AWS#1 $3,070.00 AK-AM-8370362 PVMBT 42.0 Max @ ft Current 177.0 1.3 Milltooth Siltst ClystChtSd 3088' H2S Data Sample Line Avg: 20 75 Sh Chromatograph (ppm) Depth 5.0 Lst 400 Max:Ambient Air Pit Room 5 Silt Tuff Gas Breakdown Avg: Ann Corr Cor Solids (lb/100ft2) 15,000 Sst 24 hr Max YP to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air CG 105 C1-10454 C1- 22292 FG 170 C1-201178 3623.00 277 md 3628.00 RIH , Drill to 3386 @ time of report. C1-34339 3684.003675.00 3690.00 3535.00 3575.003570.00 3600.00 3602.00 FG 3692.00 CG 182 C1-11811 FG 306 BG 48 C1-7601 3526.00 David LaSalle/Mark Lindhoff Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP New Ann Corr Cor Solids (lb/100ft2) 13,000 Sst Ambient Air Pit Room 5 Silt Tuff Gas Breakdown Avg: Depth 6.0 Lst 0' 400 Max: 55 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 40 1.0 Milltooth Siltst ClystChtSd 3088' AWS#1 $3,070.00 AK-AM-8370362 PVMBT 42.0 Max @ ft Current 292.0 16 10-16-11 4224 8.5 0.991 (ppb Eq)cP Size 169.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1847 30.90 Three Mile Creek Unit Daily Charges Avg 10.6 97 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 5.2 mg/l AvgMin Max Max API Filt 8.50 1825 2.345 $55,700.00 468 380 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 400 Drilling 363 3962' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 4221' Depth R.O.P. (ft/hr) Gas (units)80 Avg Diam Max: Gas (units) G Cto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle/Mark Lindhoff 3830.00 C1-33328.37 C1-35187.95 145 CG C1-13353.52 CG BG TG 3860.00 3940.00 3944.00 363 4010.00 228 FG C1-34609.57 493 3836.00 3863.00 4130.00 4132.00 308 4067.004065.00 43 4105.00 C1-4716.59 4005.00 277 FG POOH 500 fr wiper short trip, currently drilling. Drilled ahead from 4010 @ time of report.pumped 25 bbl sweep 100% increase in cuttings, md 4182.00 3962.003960.00 4109.00 4184.00 FG 304 CG C1-36267.62 C1-36410.35 143 FG C1-16687.93 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 16,000 Sst Ambient Air Pit Room 75 Silt Tuff Gas Breakdown Avg: Depth 5.8 Lst 400 Max: 20 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 5 1.3 Tricone Siltst ClystChtSd 4519' AWS#1 $3,070.00 AK-AM-8370362 PVMBT 48.0 Max @ ft Current 203.0 17 10-17-11 4593 8.5 0.991 (ppb Eq)cP Size 169.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1947 40.40 Three Mile Creek Unit Daily Charges Avg 6.8 103 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 5.7 mg/l AvgMin Max Max API Filt 9.50 1971 2.345 $58,770.00 426 370 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 369' Drilling 423 4550' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 4559' Depth R.O.P. (ft/hr) Gas (units)112 Avg Diam Max: Gas (units) CG Cto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle / Mark Lindhoff 4324.00 4390.00 4465.00 4468.00 327 445 FG C1-39619.86 4326.00 4395.00 POOH 500 fr wiper short trip, RIH,currently drilling ahead @ time of report Drilled ahead from 4204 to 4487 pumped 25 bbl sweep 100% increase in cuttings, md 4551.004550.00 CG 396 FG C119886.81 C1-53449.28 221 CG C1-23878.76 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 15,000 Sst Ambient Air Pit Room 20 Silt Tuff Gas Breakdown Avg: Depth 5.5 Lst 400 Max: 10 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 70 1.0 Milltooth Siltst ClystChtSd 4519' AWS#1 $3,070.00 AK-AM-8370362 PVMBT 48.0 Max @ ft Current 250.0 18 10-18-11 5012 8.5 0.991 (ppb Eq)cP Size 189.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1847 Three Mile Creek Unit Daily Charges Avg 9.3 82 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 6.1 mg/l AvgMin Max Max API Filt 8.00 2370 2.345 $61,840.00 455 415 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 419 Drilling 446 4838' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 5017' Depth R.O.P. (ft/hr) Gas (units)57 Avg Diam Max: Gas (units) G Cto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle/Mark Lindhoff 4882.00 34 BG C1-6256.12 FG 4835.00 4735.00 4737.00 329 4622.00 446 FG C1-15564.06 440 4884.00 4838.00 C1-52312.71 4956.004954.00 4620.00 Drilled ahead from 4550 . md 4696.004694.00 CG 160 CG C1-16987.12 C1-49138.43 185 FG C1-21886.35 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 14,000 Sst Ambient Air Pit Room 0 Silt Tuff Gas Breakdown Avg: Depth 5.0 Lst 400 Max: 0 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 0 1.0 Milltooth Siltst ClystChtSd 5142' AWS#1 $2,320.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 250.0 19 10-19-11 5142 8.5 0.991 (ppb Eq)cP Size 229.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 2047 57.40 Three Mile Creek Unit Daily Charges Avg 0.0 0 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 6.8 mg/l AvgMin Max Max API Filt 9.00 14 2.345 $65,660.00 0 0 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 130' Drilling 1119 5141' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 5017' Depth R.O.P. (ft/hr) Gas (units)0 Avg Diam Max: Gas (units) Gto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle/Mark Lindhoff 5139.00 CG 5150.00 5060.00 5063.00 450 5079.00 254 CG C1-26045.73 175 5141.00 5111.00 C1-23142.205075.00 pumped hi vis sweep 100% increase in cuttings,POOH @ time of report. Drilled ahead from 5012 to 5070 pumped hi vis sweep 400% increase in cuttings. Drilled ahead to 5142 TD, md 5051.005050.00 FG 308 FG C1-34499.37 C1-23863.88 1119 TG Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) Gas (units) Avg Diam Max: 0' Depth R.O.P. (ft/hr) Gas (units)0 PWD Drilling All Circ % 0 RIH clean out run 00 ' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 57 2.345 $68,052.90 15 7 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 6.0 mg/l AvgMin Max Max API Filt 9.00 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 0.0 0 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1652 64.19 Three Mile Creek Unit 20 10-20-11 5142 8.5 0.991 (ppb Eq)cP Size 169.50 AWS#1 $2,320.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 1.0 Tricone Siltst ClystCht 5142' Sd 5142' H2S Data Sample Line Avg: 0 2134' 0 Sh Chromatograph (ppm) Depth 5.0 Lst 3008' 400 Max:Ambient Air Pit Room 0 Silt Tuff Gas Breakdown Avg: 5-5-WT-A-F-ER-TD Ann Corr Cor Solids (lb/100ft2) 12,000 Sst 24 hr Max YP 7117 to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air md TOOH, Tested BOPs, RIH with wire line tools stuck at 1960', Change wire line RIH for clean out run. David LaSalle/Mark Lindhoff Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) Gas (units) G C Avg Diam Max: 5158' Depth R.O.P. (ft/hr) Gas (units)0 PWD Drilling All Circ % 17 Drill to 5159,POOH 238 5158' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 25 2.345 $70,372.00 0 0 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 6.0 mg/l AvgMin Max Max API Filt 8.50 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 0.3 145 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1545 Three Mile Creek Unit 21 10-21-11 5159 8.5 0.991 (ppb Eq)cP Size 159.50 AWS#1 $2,320.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 138.0 1.0 Tricone Siltst ClystChtSd 5142' H2S Data Sample Line Avg: 59 5 Sh Chromatograph (ppm) Depth 5.0 Lst 500 Max:Ambient Air Pit Room 0 Silt Tuff Gas Breakdown Avg: Ann Corr Cor Solids (lb/100ft2) 12,000 Sst 24 hr Max YP to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air 261 CG 238 FG C1-28403.13 md RIH clean out run, Drill to 5159, POOH to 1800 Circulated hole clean,TOOH,RU wire line. 5158.00 5135.005130.00 1890.00 1892.00 226 CG 5155.00 David LaSalle/Mark Lindhoff Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP 8022.5 3-3-WT-A-E-I-NO-LOG Ann Corr Cor Solids (lb/100ft2) 15,000 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 4.5 Lst 5142' 500 Max: 17' Sh Chromatograph (ppm) H2S Data Sample Line Avg: 1.0 Tricone Siltst ClystCht 5159' Sd 5159' AWS#1 $2,320.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 22 10-22-11 5159 8.5 0.991 (ppb Eq)cP Size 249.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1752 0.00 Three Mile Creek Unit Daily Charges Avg 0.0 0 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 5.7 mg/l AvgMin Max Max API Filt 8.50 29 2.345 $72,692.00 0 4 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 0 Wireline 00 ' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 0' Depth R.O.P. (ft/hr) Gas (units)0 Avg Diam Max: Gas (units) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle / Mark Lindhoff TOOH, RU Wireline, Running wireline logs. md Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) Gas (units) G Avg Diam Max: 0' Depth R.O.P. (ft/hr) Gas (units)0 PWD Drilling All Circ % 0 TOOH,LD, Pipe 261 5159' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 25 2.345 $75,012.00 36 6 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 5.7 mg/l AvgMin Max Max API Filt 8.50 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 0.0 39 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1965 0.00 Three Mile Creek Unit 23 10-23-11 4464 8.5 0.991 (ppb Eq)cP Size 239.50 AWS#1 $2,320.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 1.0 Tricone Siltst ClystCht 5159' Sd 5159' H2S Data Sample Line Avg: 0' Sh Chromatograph (ppm) Depth 4.5 Lst 5159' 600 Max:Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: N/A Ann Corr Cor Solids (lb/100ft2) 15,000 Sst 24 hr Max YP 700.00 to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air 261 WTG md finished wireline logs, RD wireline,RIH for cleanout run,Circulateed hole,TOOH, laying down drill string. 5159.005159.00 David LaSalle / Mark Lindhoff Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) Gas (units) Avg Diam Max: 0' Depth R.O.P. (ft/hr) Gas (units)0 PWD Drilling All Circ % 0 RIH,with caseing 00 ' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 0 2.345 $77,332.00 0 0 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 5.9 mg/l AvgMin Max Max API Filt 8.50 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 0.0 0 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 2268 0.00 Three Mile Creek Unit 24 10-24-11 5159 8.5 0.991 (ppb Eq)cP Size 279.50 AWS#1 $2,320.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 1.0 Tricone Siltst ClystChtSd 5159' H2S Data Sample Line Avg: Sh Chromatograph (ppm) Depth 4.0 Lst 600 Max:Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Ann Corr Cor Solids (lb/100ft2) 13,000 Sst 24 hr Max YP to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air md layed down drill string.RIH with CSG David LaSalle / Mark Lindhoff Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP New Ann Corr Cor Solids (lb/100ft2) 128,000 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth N/A Lst 0' 600 Max: Sh Chromatograph (ppm) H2S Data Sample Line Avg: N/A Milltooth Siltst ClystChtSd 4662' AWS#1 $2,320.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 25 10-25-11 5159 8.5 0.991 (ppb Eq)cP Size N/A9.60 Aurora Gas LLC TMCU #3 North Cook Inlet 9.60 N/A27 0.00 Three Mile Creek Unit Daily Charges Avg 0.0 0 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal N/A mg/l AvgMin Max Max API Filt 7.00 0 2.345 $77,332.00 21 0 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 0 Cementing 00 ' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 0' Depth R.O.P. (ft/hr) Gas (units)0 Avg Diam Max: Gas (units) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle / Mark Lindhoff Circulated hole, Pumped Cement,displaced with brine, waiting on Cement. md Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 128,000 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth N/A Lst Max: Sh Chromatograph (ppm) H2S Data Sample Line Avg: N/A Siltst ClystChtSd 4662' AWS#1 $2,320.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 26 10-26-11 5159 (ppb Eq)cP Size N/A9.60 Aurora Gas LLC TMCU #3 North Cook Inlet 9.60 N/A27 Three Mile Creek Unit Daily Charges Avg 0.0 0 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal N/A mg/l AvgMin Max Max API Filt 7.00 0 1763 $77,332.00 11 2 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 0 RIH w/t Tubing 00 ' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 0' Depth R.O.P. (ft/hr) Gas (units)0 Avg Diam Max: Gas (units) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle / Mark Lindhoff Wait on Cement, tested BOPs, RIH with tubing. md WE L L N A M E : Th r e e M i l e C r e e k # 3 LO C A T I O N : Three Mile Creek Gas Field OP E R A T O R : Au r o r a G a s , L L C AR E A : Kenai, AK MU D C O : Ba r o i d ST A T E : Alaska RI G : AW S - 1 SP U D : 28-Sep-11 SP E R R Y J O B : AK - A M - 0 0 0 8 3 7 0 3 6 2 TD : 18-Oct-11 BI T RE C O R D BH A # B i t # B i t T y p e B i t Si z e De p t h In De p t h Ou t Fo o t a g e B i t Ho u r s TF A A V G RO P WO B (m a x ) RP M (m a x ) SP P (m a x ) FL O W G P M (m a x ) Bi t G r a d e R e m a r k s 1 1 H u g h e s G T - C 1 1 2 . 5 0 9 3 9 0 0 8 0 7 2 8 . 6 1 1 . 0 3 0 8 28 . 2 10 80 6 9 0 4 5 5 1- 1 - N O - A - E - I - N O - T D TD 12 1/4" section 2 2 Q H C 1 R T r i c o n e 8 . 5 0 9 0 0 9 0 0 0 0 . 0 0 0 . 9 9 1 0 0. 0 0 0 0 0 0- 0 - N O - A - E - I - N O - H P Casing Pressure test failed, POOH to run RTTS 3 2 r r Q H C 1 R T r i c o n e 8 . 5 0 9 0 0 3 0 0 9 2 1 0 9 6 4 . 1 9 0 . 9 9 1 0 38 . 0 18 90 2 0 5 0 4 9 5 1- 1 - C T - A - E - I - N O - R I G POOH for Bit Trip 4 3 Q H C 1 R T r i c o n e 8 . 5 0 3 0 0 9 5 1 4 2 2 1 3 3 6 4 . 1 9 0 . 9 9 1 0 33 . 2 25 8 0 2 6 5 0 4 6 0 5 - 5 - W T - A - F - E R - T D T D T M C U 3 5 4 R R 2 Q H C 1 R T r i c o n e 8 . 5 0 5 1 4 2 5 1 5 9 1 7 0 . 6 7 0 . 9 9 1 0 25 . 0 23 9 0 19 0 0 4 2 5 3- 3 - E T - A - E - I - N O - L O G Drill 17" extra for Casing 6 0 7 8 11 13 14 17 18 W E L L N A M E : Th r e e M i l e C r e e k # 3 LO C A T I O N : Th r e e M i l e C r e e k G a s F i e l d OP E R A T O R : Au r o r a G a s , L L C AR E A : Ke n a i , A K MU D C O : Ba r o i d ST A T E : A la s k a RI G : A WS - 1 SP U D : 28 - S e p - 1 1 SP E R R Y J O B : A K- A M - 0 0 0 8 3 7 0 3 6 2 TD : 51 5 9 ' W a t e r B a s e d M u d R e c o r d Da t e D e p t h W t V i s P V Y P G e l s F i l t R6 0 0 / R 3 0 0 / R 2 0 0 / R 1 0 0 / R6 / R 3 Ca k e S o l i d s Oi l / W a t e r Sd P m p H M B T P f / M f C h l o r H a r d R e m a r k s ft - M D p p g s e c c P l b / 1 0 0 l b / 1 0 0 f t 2 m / 3 0 m R h e o m e t e r 3 2 n d s % % % p p b E q v m g / l C a + + 28 - S e p 0 9. 2 0 82 1 3 3 5 2 4 / 3 5 / 4 5 1 5 . 0 6 1 / 4 8 / 4 1 / 3 6 / 2 2 / 2 1 2 6 . 8 0. 0 / 9 3 . 0 - 0 . 3 9 2 0 0 . 3 0 / 0 . 6 0 5 0 0 4 0 R i g u p 29 - S e p 0 10 . 0 0 80 1 9 2 6 2 3 / 3 3 / 4 3 1 5 . 0 6 3 / 4 4 / 3 7 / 2 8 / 1 7 / 1 6 2 6 . 8 0 . 0 / 9 3 . 0 - 0 . 2 8 . 5 2 0 8 . 5 / 6 2 5 0 0 4 0 R i g u p 30 - S e p 2 0 0 10 . 0 0 83 2 6 3 3 1 4 / 3 5 / 4 5 5 . 0 8 5 / 5 9 / 4 8 / 3 6 / 1 5 / 1 4 2 6 . 8 0. 0 / 9 3 . 0 - 0 . 1 8 2 0 0 . 1 0 / 0 . 2 0 5 0 0 4 0 D r i l l i n g 1- O c t 90 0 1 0 . 0 0 8 1 1 6 4 8 9 / 1 8 / 2 9 5 . 0 8 0 / 6 4 / 5 2 / 3 8 / 1 2 / 8 2 / 0 6 . 8 0 . 0 / 9 3 . 0 - 0. 1 0 8 . 5 2 0 . 0 0 . 1 0 / 0 . 3 0 5 0 0 4 0 Drilling/Circulating hole clean 2- O c t 90 0 1 0 . 0 0 4 8 2 3 1 2 4 / 6 / 7 7 . 0 5 8 / 3 5 / 2 6 / 1 5 / 4 / 3 2 / 0 6 . 8 0 . 0 / 9 3 . 0 - 0. 3 0 9 . 0 2 0 . 0 0 . 1 0 / 0 . 7 0 5 0 0 4 0 Circulating //POOH 3- O c t 90 0 1 0 . 0 0 4 8 2 2 1 5 5 / 7 / 8 7 . 0 5 9 / 3 7 / 2 8 / 1 6 / 5 / 4 2 / 0 6 . 8 9 3 . 0 - 0. 2 0 9 . 0 2 0 . 0 0 . 1 0 / 0 . 6 0 5 0 0 4 0 Cementing 4- O c t 90 0 1 0 . 0 0 4 9 2 3 1 4 4 / 6 / 7 7 . 0 6 0 / 3 7 / 2 9 / 1 7 / 6 / 4 2 / 0 6 . 8 9 3 . 0 - 0. 2 0 9 . 0 2 0 . 0 0 . 1 0 / 0 . 6 0 5 0 0 4 0 Testing BOPs 5- O c t 90 0 9 . 5 0 4 6 2 2 1 4 4 / 5 / 7 9 . 0 5 8 / 3 6 / 2 7 / 1 6 / 5 / 4 2 / 0 6 . 8 9 3 . 0 - 0. 4 0 8 . 5 2 0 . 0 0 . 1 0 / 0 . 3 0 5 0 0 4 0 RIH w/ RTPS 6- O c t 90 0 9 . 5 0 4 5 2 4 1 1 5 / 6 / 7 9 . 0 5 9 / 3 5 / 1 7 / 1 7 / 6 / 5 2 / 0 6 . 8 9 3 . 0 - 0. 4 0 8 . 5 2 0 . 0 0 . 1 0 / 0 . 3 0 5 0 0 4 0 pressure test csg/drill cement 7- O c t 95 0 9 . 4 0 5 5 1 1 2 2 8 / 1 2 / 1 5 5 . 0 4 4 / 3 3 / 2 9 / 2 1 / 8 / 6 1 . 0 3 . 8 0 . 0 / 9 5 . 0 - 0. 1 8 8 . 0 0 . 3 0 . 1 0 / 0 . 6 0 1 4 , 0 0 0 8 0 0 Circulating /drill to 973 8- O c t 15 1 0 9 . 5 0 5 2 1 8 2 2 5 / 8 / 1 0 4 . 6 5 8 / 4 0 / 3 2 / 2 2 / 6 / 4 1 . 0 4 . 8 0 . 0 / 9 4 . 0 - 0. 9 4 9 . 0 0 . 5 0 . 1 0 / 0 . 4 5 1 4 , 0 0 0 8 0 0 wiper trip to shoe drill to 1510 9- O c t 20 4 6 9 . 5 0 5 0 2 1 2 0 4 / 5 / 6 4 . 3 6 2 / 4 1 / 3 2 / 2 1 / 6 / 3 1 . 0 5 . 9 0 . 0 / 9 3 . 0 - 0. 5 0 8 . 5 0 . 5 0 . 1 0 / 0 . 3 5 1 3 , 0 0 0 8 0 0 drill 1910,POOH, for wiper trip T 10 - O c t 25 6 6 9 . 5 0 4 7 1 9 1 6 3 / 4 / 7 4 . 5 5 4 / 3 5 / 2 8 / 1 8 / 5 / 3 1 . 0 5 . 8 0 . 0 / 9 3 . 0 - 0. 3 8 8 . 5 0 . 4 0 . 1 0 / 0 . 3 5 1 4 , 0 0 0 8 0 0 Drill to 2566 11 O t 30 0 8 96 0 79 28 25 6/ 1 0 / 1 5 43 81 / 5 3 / 4 2 / 2 0 / 9 / 5 1/ 0 57 00 / 9 3 0 04 5 95 10 0 1 0 / 0 5 0 15 0 0 0 800 d POOH bit t i 11 -O c t 30 0 8 9 .60 79 28 25 6/ 1 0 / 1 5 4 .3 81 / 5 3 / 4 2 / 2 0 / 9 / 5 1/ 0 5 .7 0 .0/ 9 3 .0 - 0 .45 9 .5 1 .0 0 .10 / 0 .50 15 ,00 0 800 pumpe d sweep POOH bit t r i p 12 - O c t 30 0 8 9 . 7 0 8 8 2 5 2 7 7 / 1 4 / 1 8 4 . 2 7 7 / 5 2 / 3 9 / 2 6 / 1 0 / 7 1 / 0 6 . 8 0 . 0 / 9 2 . 0 - 0. 2 5 8 . 5 1 . 3 0 . 1 0 / 0 . 3 0 1 5 , 0 0 0 8 0 0 Chg bit and motor/RIH 13 - O c t 33 8 6 9 . 5 0 5 6 2 3 2 5 1 0 / 1 6 / 2 0 4 . 8 7 1 / 4 8 / 3 9 / 2 6 / 8 / 6 1 / 0 6 . 8 0 . 0 / 9 2 . 0 - 0. 2 0 8 . 0 1 . 0 0 . 1 0 / 0 . 8 0 1 5 , 0 0 0 8 0 0 RIH,Drill to 3386 14 - O c t 35 6 0 9 . 5 0 7 2 2 6 3 0 8 / 1 7 / 2 0 2 4 5 . 0 8 2 / 5 6 / 4 5 / 3 0 / 1 4 / 8 1 / 0 6 . 8 0 . 0 / 9 2 . 0 - 0. 2 5 8 . 5 1 . 3 0 . 1 0 / 1 . 0 0 1 5 , 0 0 0 4 0 0 wiper trip, RIH, drill to 3800 15 - O c t 42 0 0 9 . 5 0 4 7 1 6 1 8 7 / 1 2 / 2 0 1 5 6 . 0 5 0 / 3 4 / 2 8 / 1 9 / 6 / 3 1 / 0 5 . 2 0 . 0 / 9 4 . 0 - 0. 4 0 8 . 5 1 . 0 0 . 1 8 / 0 . 8 5 1 3 , 0 0 0 4 0 0 wiper trip, RIH, drill to 4204 16 - O c t 45 1 9 9 . 5 0 4 7 1 6 1 9 1 0 / 1 8 / 2 5 5 . 8 5 1 / 3 5 / 2 9 / 2 0 / 8 / 6 2 . 0 5 . 7 0 . 0 / 9 3 . 0 - 0. 4 8 9 . 5 1 . 3 0 . 1 6 / 1 . 0 0 1 6 , 0 0 0 3 0 0 wiper trip, RIH, drill to 4550 17 - O c t 49 5 0 9 . 5 0 4 7 1 8 1 8 6 / 1 6 / 2 0 5 . 5 5 4 / 3 6 / 2 9 / 1 9 / 5 / 3 1 . 0 6 . 1 0 . 0 / 9 3 . 0 - 0. 4 2 8 . 5 1 . 0 0 . 1 0 / 1 . 0 0 1 5 , 0 0 0 4 0 0 drill to 5142, POOH , wiper trip 18 - O c t 51 4 2 9 . 5 0 4 7 2 2 2 0 6 / 1 4 / 1 9 5 . 0 6 4 / 4 2 / 3 3 / 1 9 / 5 / 4 1 . 0 6 . 8 0 . 0 / 9 2 . 0 - 0. 6 0 9 . 0 1 . 0 0 . 1 5 / 1 . 0 0 1 4 , 0 0 0 5 0 0 drill to 5013 19 - O c t 51 4 2 9 . 5 0 5 2 1 6 1 6 3 / 1 8 / 1 2 5 . 0 4 8 / 3 2 / 2 4 / 1 6 / 4 / 3 1 . 0 6 . 0 0 . 0 / 9 3 . 0 - 0. 6 0 9 . 0 1 . 0 0 . 1 5 / 0 . 8 0 1 2 , 0 0 0 5 0 0 TOOH,Test BOP,RIH wire line,stuck 20 - O c t 51 5 9 9 . 5 0 4 5 1 5 1 5 3 / 1 9 / 1 3 5 . 0 4 5 / 3 0 / 2 3 / 1 5 / 3 / 2 1 . 0 6 . 0 0 . 0 / 9 3 . 0 - 0. 2 0 8 . 5 1 . 0 0 . 0 0 / 0 . 8 0 1 2 , 0 0 0 5 0 0 Drill to 5159, TOOH,RU wireline 21 - O c t 51 5 9 9 . 5 0 5 2 2 4 1 7 3 / 1 0 / 1 4 4 . 5 6 5 / 4 1 / 3 1 / 2 0 / 3 / 2 1 5 . 7 0 . 0 0 / 9 3 . 0 0 . 2 5 0 . 1 0 8 . 5 1 . 0 0 . 0 0 / 0 . 9 0 1 5 , 0 0 0 5 0 0 Wire Line logs 22 - O c t 51 5 9 9 . 5 0 6 5 2 3 1 6 4 / 1 5 / 2 0 4 . 5 6 5 / 4 2 / 3 2 / 2 1 / 5 / 4 1 5 . 7 0 . 0 0 / 9 3 . 0 0 . 2 5 0 . 1 0 8 . 5 1 . 0 0 . 0 0 / 9 3 . 0 1 5 , 0 0 0 5 0 0 Tripping 23 - O c t 51 5 9 9 . 5 0 6 8 2 7 2 2 4 / 1 0 / 1 6 4 . 0 7 6 / 4 9 / 3 2 / 2 4 / 5 / 3 1 5 . 9 0 . 0 0 / 9 3 . 0 0 . 2 5 0 . 1 0 8 . 5 1 . 0 0 . 0 0 / 1 . 1 0 1 3 , 0 0 0 5 0 0 Run Casing and cement 24 - O c t 51 5 9 9 . 6 0 2 7 - - - - - - - - - - - - - - - W a i t o n C e m e n t 25 - O c t 51 5 9 9 . 6 0 2 7 - - - - - - - - - - - - - - - R i g F d o w n Ca s i n g R e c o r d 16 " C o n d u c t o r @ 9 3 12 . 7 5 " @ 8 8 4 ' Marker MD INC AZ TVD TVDSS Beluga Tsuga 2-4 2025.0 23.45 289.64 1980.18 1677 Beluga Tsuga 2-5 3210.0 22.20 291.92 3034.96 2731 Beluga Tsuga 2-6 4050.0 22.99 294.25 3780.60 3477 Beluga Tsuga 2-7 4770.0 26.23 293.97 4420.95 4117 Three Mile Creek #3 Interpolated Tops 16 November, 2011 Cook Inlet Three Mile Creek Unit TMCU#3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Three Mile Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: TMCU#3 TMCU#3 Survey Calculation Method:Minimum Curvature TMCU # 3 081611 @ 303.50ft (287.5 + 16) Design:TMCU #3 Database:.Sperry EDM .16 PRD MD Reference:TMCU # 3 081611 @ 303.50ft (287.5 + 16) North Reference: Well TMCU#3 Grid Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Cook Inlet, COOK INLET BASIN Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Well Well Position Longitude: Latitude: Easting: Northing: ft +E/-W +N/-S Position Uncertainty ft ft ftGround Level: TMCU#3 ft ft 0.00 0.00 2,621,669.89 285,834.57 287.50Wellhead Elevation:303.50 ft0.00 61° 10' 12.894 N 151° 12' 47.03 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) TMCU#3 Model NameMagnetics BGGM2011 10/1/2011 17.96 73.99 55,679 Phase:Version: Audit Notes: Design TMCU #3 1.0 ACTUAL Vertical Section: Depth From (TVD) (ft) +N/-S (ft) Direction (°) +E/-W (ft) Tie On Depth:16.00 296.910.000.0016.00 From (ft) Survey Program DescriptionTool NameSurvey (Wellbore) To (ft) Date 11/16/2011 Survey Start Date BLIND Blind drilling93.00 993.05 TMCU #3 (Blind) (TMCU#3)09/27/2011 MWD MWD - Standard1,025.30 5,046.46 TMCU #3 (MWD) (TMCU#3)10/11/2011 MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 16.00 0.00 0.00 16.00 0.00 0.00-287.50 2,621,669.89 285,834.57 0.00 0.00 UNDEFINED 93.00 0.00 0.00 93.00 0.00 0.00-210.50 2,621,669.89 285,834.57 0.00 0.00 BLIND (1) 136.91 2.12 328.34 136.90 0.69 -0.43-166.60 2,621,670.58 285,834.14 4.83 0.69 BLIND (1) 167.23 2.49 326.42 167.20 1.72 -1.08-136.30 2,621,671.61 285,833.49 1.25 1.74 BLIND (1) 197.51 2.50 328.53 197.45 2.83 -1.79-106.05 2,621,672.72 285,832.78 0.31 2.88 BLIND (1) 227.71 2.66 325.62 227.62 3.97 -2.53-75.88 2,621,673.86 285,832.04 0.68 4.05 BLIND (1) 258.04 2.85 325.50 257.91 5.17 -3.36-45.59 2,621,675.06 285,831.21 0.63 5.33 BLIND (1) 288.07 3.22 323.45 287.90 6.46 -4.28-15.60 2,621,676.35 285,830.29 1.28 6.74 BLIND (1) 318.36 3.21 323.09 318.14 7.83 -5.3014.64 2,621,677.71 285,829.27 0.07 8.27 BLIND (1) 348.85 3.36 322.58 348.58 9.22 -6.3545.08 2,621,679.11 285,828.22 0.50 9.84 BLIND (1) 379.31 3.45 320.27 378.99 10.63 -7.4875.49 2,621,680.52 285,827.09 0.54 11.48 BLIND (1) 409.48 3.75 321.27 409.10 12.10 -8.68105.60 2,621,681.99 285,825.89 1.02 13.22 BLIND (1) 439.68 4.02 323.32 439.23 13.72 -9.93135.73 2,621,683.61 285,824.64 1.01 15.06 BLIND (1) 11/16/2011 9:48:44AM COMPASS 2003.16 Build 71 Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Three Mile Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: TMCU#3 TMCU#3 Survey Calculation Method:Minimum Curvature TMCU # 3 081611 @ 303.50ft (287.5 + 16) Design:TMCU #3 Database:.Sperry EDM .16 PRD MD Reference:TMCU # 3 081611 @ 303.50ft (287.5 + 16) North Reference: Well TMCU#3 Grid MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 469.19 4.31 322.01 468.66 15.42 -11.23165.16 2,621,685.31 285,823.34 1.03 16.99 BLIND (1) 503.93 4.75 322.16 503.29 17.59 -12.92199.79 2,621,687.48 285,821.65 1.27 19.48 BLIND (1) 534.33 5.08 323.72 533.58 19.67 -14.49230.08 2,621,689.55 285,820.09 1.17 21.82 BLIND (1) 595.69 5.64 323.54 594.67 24.28 -17.88291.17 2,621,694.17 285,816.69 0.91 26.94 BLIND (1) 627.13 5.62 322.05 625.96 26.74 -19.75322.46 2,621,696.63 285,814.82 0.47 29.71 BLIND (1) 658.57 5.70 321.99 657.25 29.18 -21.66353.75 2,621,699.07 285,812.91 0.26 32.52 BLIND (1) 689.97 6.09 322.77 688.48 31.74 -23.63384.98 2,621,701.62 285,810.95 1.27 35.43 BLIND (1) 721.35 6.33 322.61 719.68 34.44 -25.68416.18 2,621,704.32 285,808.89 0.77 38.49 BLIND (1) 752.75 6.41 322.97 750.88 37.21 -27.79447.38 2,621,707.10 285,806.78 0.28 41.62 BLIND (1) 784.11 7.05 323.83 782.03 40.16 -29.98478.53 2,621,710.05 285,804.59 2.07 44.91 BLIND (1) 815.55 7.06 323.22 813.23 43.27 -32.28509.73 2,621,713.15 285,802.30 0.24 48.36 BLIND (1) 930.19 8.13 323.00 926.86 55.38 -41.37623.36 2,621,725.27 285,793.20 0.93 61.96 BLIND (1) 961.59 8.17 323.14 957.94 58.94 -44.05654.44 2,621,728.83 285,790.53 0.14 65.95 BLIND (1) 993.05 8.19 322.57 989.08 62.51 -46.75685.58 2,621,732.40 285,787.82 0.27 69.98 BLIND (1) 1,025.30 8.14 323.43 1,021.01 66.17 -49.51717.51 2,621,736.05 285,785.07 0.41 74.09 MWD (2) 1,055.88 8.34 321.57 1,051.27 69.64 -52.17747.77 2,621,739.53 285,782.40 1.09 78.04 MWD (2) 1,087.38 8.32 319.33 1,082.44 73.16 -55.08778.94 2,621,743.05 285,779.49 1.03 82.23 MWD (2) 1,118.86 8.51 317.10 1,113.58 76.60 -58.15810.08 2,621,746.48 285,776.42 1.20 86.52 MWD (2) 1,150.30 8.82 314.30 1,144.66 79.98 -61.46841.16 2,621,749.87 285,773.11 1.66 91.00 MWD (2) 1,181.74 8.96 311.76 1,175.72 83.30 -65.01872.22 2,621,753.18 285,769.56 1.33 95.67 MWD (2) 1,244.57 9.48 307.42 1,237.74 89.70 -72.77934.24 2,621,759.59 285,761.80 1.38 105.49 MWD (2) 1,275.89 10.07 306.48 1,268.61 92.90 -77.02965.11 2,621,762.78 285,757.55 1.95 110.72 MWD (2) 1,307.31 10.36 305.00 1,299.53 96.15 -81.54996.03 2,621,766.03 285,753.03 1.24 116.23 MWD (2) 1,338.74 10.77 301.98 1,330.43 99.33 -86.351,026.93 2,621,769.21 285,748.23 2.19 121.95 MWD (2) 1,370.14 11.01 297.80 1,361.26 102.28 -91.491,057.76 2,621,772.16 285,743.09 2.63 127.87 MWD (2) 1,401.45 11.60 294.95 1,391.96 105.00 -96.991,088.46 2,621,774.89 285,737.59 2.59 134.01 MWD (2) 1,433.00 12.29 290.86 1,422.83 107.53 -103.001,119.33 2,621,777.42 285,731.57 3.46 140.52 MWD (2) 1,464.47 12.90 289.90 1,453.54 109.92 -109.431,150.04 2,621,779.81 285,725.14 2.05 147.33 MWD (2) 1,496.00 13.58 290.01 1,484.24 112.39 -116.221,180.74 2,621,782.27 285,718.35 2.16 154.50 MWD (2) 1,527.46 14.61 288.47 1,514.75 114.91 -123.461,211.25 2,621,784.79 285,711.12 3.48 162.09 MWD (2) 1,558.87 15.55 287.35 1,545.08 117.42 -131.231,241.58 2,621,787.30 285,703.34 3.13 170.16 MWD (2) 1,589.81 16.37 286.33 1,574.82 119.88 -139.381,271.32 2,621,789.77 285,695.20 2.80 178.54 MWD (2) 1,621.27 17.31 286.87 1,604.93 122.49 -148.111,301.43 2,621,792.37 285,686.47 3.03 187.51 MWD (2) 1,652.67 18.13 287.36 1,634.84 125.30 -157.241,331.34 2,621,795.18 285,677.34 2.65 196.92 MWD (2) 1,684.11 18.73 287.32 1,664.67 128.26 -166.731,361.17 2,621,798.15 285,667.85 1.91 206.72 MWD (2) 1,715.49 19.41 286.63 1,694.33 131.25 -176.541,390.83 2,621,801.14 285,658.04 2.28 216.82 MWD (2) 1,746.91 20.22 286.28 1,723.89 134.27 -186.751,420.39 2,621,804.15 285,647.83 2.61 227.30 MWD (2) 1,778.48 21.25 286.61 1,753.41 137.44 -197.471,449.91 2,621,807.32 285,637.11 3.28 238.29 MWD (2) 1,809.81 22.19 286.43 1,782.52 140.73 -208.591,479.02 2,621,810.61 285,625.99 3.01 249.69 MWD (2) 1,841.28 23.07 286.53 1,811.57 144.17 -220.201,508.07 2,621,814.05 285,614.38 2.80 261.60 MWD (2) 11/16/2011 9:48:44AM COMPASS 2003.16 Build 71 Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Three Mile Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: TMCU#3 TMCU#3 Survey Calculation Method:Minimum Curvature TMCU # 3 081611 @ 303.50ft (287.5 + 16) Design:TMCU #3 Database:.Sperry EDM .16 PRD MD Reference:TMCU # 3 081611 @ 303.50ft (287.5 + 16) North Reference: Well TMCU#3 Grid MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 1,872.67 23.45 285.81 1,840.40 147.62 -232.101,536.90 2,621,817.50 285,602.48 1.51 273.78 MWD (2) 1,903.94 23.61 286.09 1,869.07 151.05 -244.111,565.57 2,621,820.93 285,590.48 0.62 286.04 MWD (2) 1,935.28 23.39 286.15 1,897.82 154.52 -256.111,594.32 2,621,824.40 285,578.47 0.71 298.31 MWD (2) 1,966.66 23.33 286.37 1,926.62 158.00 -268.061,623.12 2,621,827.88 285,566.53 0.34 310.54 MWD (2) 1,998.13 23.34 285.56 1,955.52 161.43 -280.041,652.02 2,621,831.31 285,554.54 1.02 322.78 MWD (2) 2,029.52 23.45 285.81 1,984.33 164.80 -292.041,680.83 2,621,834.68 285,542.54 0.47 335.00 MWD (2) 2,060.95 23.35 286.17 2,013.17 168.24 -304.041,709.67 2,621,838.12 285,530.54 0.56 347.26 MWD (2) 2,092.43 23.30 286.09 2,042.08 171.70 -316.011,738.58 2,621,841.58 285,518.57 0.19 359.51 MWD (2) 2,123.89 23.28 286.21 2,070.98 175.16 -327.961,767.48 2,621,845.04 285,506.62 0.16 371.73 MWD (2) 2,155.26 23.20 285.44 2,099.80 178.54 -339.871,796.30 2,621,848.42 285,494.72 1.00 383.87 MWD (2) 2,186.64 23.12 285.71 2,128.65 181.85 -351.761,825.15 2,621,851.73 285,482.83 0.42 395.97 MWD (2) 2,217.98 23.20 285.05 2,157.47 185.12 -363.641,853.97 2,621,855.00 285,470.94 0.87 408.05 MWD (2) 2,249.22 23.91 284.94 2,186.10 188.35 -375.701,882.60 2,621,858.23 285,458.89 2.28 420.27 MWD (2) 2,280.63 24.80 285.09 2,214.72 191.71 -388.211,911.22 2,621,861.59 285,446.38 2.84 432.94 MWD (2) 2,312.17 25.71 284.84 2,243.24 195.18 -401.211,939.74 2,621,865.06 285,433.38 2.90 446.11 MWD (2) 2,343.56 26.62 284.94 2,271.42 198.74 -414.591,967.92 2,621,868.62 285,420.00 2.90 459.64 MWD (2) 2,375.00 27.40 284.82 2,299.43 202.40 -428.391,995.93 2,621,872.28 285,406.20 2.49 473.61 MWD (2) 2,406.42 28.05 284.36 2,327.24 206.09 -442.542,023.74 2,621,875.97 285,392.06 2.18 487.89 MWD (2) 2,437.85 28.27 284.35 2,354.95 209.76 -456.912,051.45 2,621,879.64 285,377.69 0.70 502.37 MWD (2) 2,469.24 28.34 284.55 2,382.59 213.48 -471.322,079.09 2,621,883.36 285,363.27 0.38 516.90 MWD (2) 2,500.41 28.75 283.78 2,409.97 217.12 -485.762,106.47 2,621,887.00 285,348.83 1.77 531.43 MWD (2) 2,531.84 29.31 283.78 2,437.45 220.75 -500.572,133.95 2,621,890.63 285,334.02 1.78 546.28 MWD (2) 2,563.24 29.17 283.80 2,464.85 224.41 -515.472,161.35 2,621,894.29 285,319.13 0.45 561.22 MWD (2) 2,594.69 29.15 284.08 2,492.31 228.10 -530.342,188.81 2,621,897.98 285,304.25 0.44 576.15 MWD (2) 2,626.05 29.17 284.85 2,519.70 231.92 -545.142,216.20 2,621,901.80 285,289.46 1.20 591.07 MWD (2) 2,657.52 29.00 283.80 2,547.20 235.70 -559.962,243.70 2,621,905.58 285,274.64 1.71 606.00 MWD (2) 2,689.00 28.68 285.55 2,574.78 239.55 -574.652,271.28 2,621,909.43 285,259.95 2.87 620.84 MWD (2) 2,720.42 28.58 286.17 2,602.35 243.66 -589.132,298.85 2,621,913.54 285,245.47 1.00 635.62 MWD (2) 2,751.77 28.51 286.99 2,629.89 247.94 -603.492,326.39 2,621,917.82 285,231.11 1.27 650.36 MWD (2) 2,783.09 28.40 286.93 2,657.43 252.29 -617.762,353.93 2,621,922.17 285,216.84 0.36 665.05 MWD (2) 2,814.56 28.33 286.26 2,685.12 256.56 -632.092,381.62 2,621,926.44 285,202.51 1.04 679.76 MWD (2) 2,845.86 28.41 286.79 2,712.66 260.79 -646.352,409.16 2,621,930.67 285,188.25 0.84 694.39 MWD (2) 2,877.27 28.08 288.79 2,740.33 265.33 -660.502,436.83 2,621,935.21 285,174.10 3.19 709.07 MWD (2) 2,908.71 28.04 290.33 2,768.08 270.28 -674.432,464.58 2,621,940.16 285,160.17 2.31 723.73 MWD (2) 2,940.17 27.79 291.53 2,795.88 275.54 -688.192,492.38 2,621,945.42 285,146.41 1.95 738.38 MWD (2) 2,971.60 27.53 291.78 2,823.71 280.93 -701.752,520.21 2,621,950.80 285,132.85 0.91 752.91 MWD (2) 3,002.98 27.77 291.72 2,851.51 286.32 -715.282,548.01 2,621,956.20 285,119.33 0.77 767.41 MWD (2) 3,034.44 27.83 292.12 2,879.34 291.80 -728.892,575.84 2,621,961.68 285,105.72 0.62 782.03 MWD (2) 3,065.88 27.82 291.72 2,907.15 297.28 -742.502,603.65 2,621,967.15 285,092.10 0.59 796.65 MWD (2) 3,097.27 27.74 291.86 2,934.92 302.71 -756.092,631.42 2,621,972.58 285,078.52 0.33 811.22 MWD (2) 11/16/2011 9:48:44AM COMPASS 2003.16 Build 71 Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Three Mile Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: TMCU#3 TMCU#3 Survey Calculation Method:Minimum Curvature TMCU # 3 081611 @ 303.50ft (287.5 + 16) Design:TMCU #3 Database:.Sperry EDM .16 PRD MD Reference:TMCU # 3 081611 @ 303.50ft (287.5 + 16) North Reference: Well TMCU#3 Grid MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 3,128.73 27.48 291.45 2,962.79 308.09 -769.642,659.29 2,621,977.96 285,064.97 1.02 825.74 MWD (2) 3,160.16 27.41 291.92 2,990.69 313.44 -783.102,687.19 2,621,983.32 285,051.51 0.72 840.17 MWD (2) 3,191.66 27.35 292.14 3,018.66 318.88 -796.532,715.16 2,621,988.75 285,038.08 0.37 854.60 MWD (2) 3,223.09 27.09 291.76 3,046.61 324.25 -809.862,743.11 2,621,994.12 285,024.75 1.00 868.92 MWD (2) 3,254.55 27.15 291.58 3,074.61 329.55 -823.192,771.11 2,621,999.42 285,011.42 0.32 883.20 MWD (2) 3,285.83 26.87 292.22 3,102.48 334.84 -836.372,798.98 2,622,004.72 284,998.24 1.29 897.36 MWD (2) 3,317.34 26.75 292.01 3,130.60 340.19 -849.542,827.10 2,622,010.07 284,985.07 0.49 911.52 MWD (2) 3,348.73 26.79 291.63 3,158.63 345.45 -862.662,855.13 2,622,015.32 284,971.95 0.56 925.60 MWD (2) 3,380.14 26.82 291.97 3,186.66 350.71 -875.812,883.16 2,622,020.58 284,958.80 0.50 939.71 MWD (2) 3,411.58 26.83 292.43 3,214.72 356.07 -888.952,911.22 2,622,025.94 284,945.66 0.66 953.85 MWD (2) 3,443.05 27.28 292.49 3,242.74 361.54 -902.182,939.24 2,622,031.41 284,932.44 1.43 968.12 MWD (2) 3,474.57 27.21 292.89 3,270.77 367.10 -915.492,967.27 2,622,036.98 284,919.12 0.62 982.51 MWD (2) 3,506.00 27.27 293.14 3,298.71 372.73 -928.732,995.21 2,622,042.60 284,905.88 0.41 996.86 MWD (2) 3,537.47 27.49 292.88 3,326.66 378.39 -942.053,023.16 2,622,048.26 284,892.56 0.80 1,011.30 MWD (2) 3,568.84 27.21 292.73 3,354.52 383.97 -955.343,051.02 2,622,053.84 284,879.28 0.92 1,025.68 MWD (2) 3,600.34 27.26 292.93 3,382.53 389.57 -968.623,079.03 2,622,059.44 284,865.99 0.33 1,040.06 MWD (2) 3,631.74 27.31 293.75 3,410.43 395.27 -981.843,106.93 2,622,065.14 284,852.78 1.21 1,054.42 MWD (2) 3,663.12 27.17 293.80 3,438.33 401.06 -994.983,134.83 2,622,070.93 284,839.63 0.45 1,068.76 MWD (2) 3,694.52 26.98 293.37 3,466.29 406.78 -1,008.083,162.79 2,622,076.65 284,826.54 0.87 1,083.03 MWD (2) 3,725.95 27.08 293.71 3,494.29 412.48 -1,021.183,190.79 2,622,082.35 284,813.44 0.59 1,097.29 MWD (2) 3,757.37 27.25 293.78 3,522.24 418.26 -1,034.313,218.74 2,622,088.13 284,800.31 0.55 1,111.61 MWD (2) 3,788.90 27.99 293.89 3,550.18 424.17 -1,047.683,246.68 2,622,094.04 284,786.94 2.35 1,126.21 MWD (2) 3,820.31 28.31 294.13 3,577.87 430.20 -1,061.213,274.37 2,622,100.06 284,773.41 1.08 1,141.01 MWD (2) 3,851.76 28.14 293.82 3,605.59 436.24 -1,074.813,302.09 2,622,106.11 284,759.82 0.71 1,155.86 MWD (2) 3,883.19 27.96 294.01 3,633.32 442.23 -1,088.323,329.82 2,622,112.10 284,746.31 0.64 1,170.62 MWD (2) 3,914.64 27.98 293.65 3,661.10 448.19 -1,101.813,357.60 2,622,118.06 284,732.81 0.54 1,185.35 MWD (2) 3,946.08 28.07 294.28 3,688.85 454.19 -1,115.313,385.35 2,622,124.06 284,719.32 0.98 1,200.11 MWD (2) 3,977.52 27.99 293.56 3,716.61 460.18 -1,128.813,413.11 2,622,130.05 284,705.81 1.11 1,214.86 MWD (2) 4,008.93 28.03 293.89 3,744.34 466.12 -1,142.323,440.84 2,622,135.98 284,692.31 0.51 1,229.59 MWD (2) 4,040.43 28.02 294.24 3,772.14 472.15 -1,155.833,468.64 2,622,142.02 284,678.79 0.52 1,244.37 MWD (2) 4,071.84 27.93 294.27 3,799.88 478.20 -1,169.263,496.38 2,622,148.07 284,665.36 0.29 1,259.09 MWD (2) 4,103.29 27.75 294.62 3,827.69 484.28 -1,182.643,524.19 2,622,154.15 284,651.99 0.77 1,273.76 MWD (2) 4,134.76 27.66 294.64 3,855.55 490.38 -1,195.943,552.05 2,622,160.25 284,638.69 0.29 1,288.38 MWD (2) 4,166.21 27.67 293.98 3,883.41 496.39 -1,209.243,579.91 2,622,166.26 284,625.39 0.97 1,302.97 MWD (2) 4,197.65 27.73 294.17 3,911.25 502.35 -1,222.593,607.75 2,622,172.22 284,612.04 0.34 1,317.57 MWD (2) 4,228.99 27.80 294.56 3,938.98 508.38 -1,235.883,635.48 2,622,178.24 284,598.74 0.62 1,332.15 MWD (2) 4,260.50 27.74 294.96 3,966.86 514.52 -1,249.223,663.36 2,622,184.39 284,585.41 0.62 1,346.82 MWD (2) 4,291.92 27.72 294.36 3,994.67 520.62 -1,262.503,691.17 2,622,190.49 284,572.13 0.89 1,361.43 MWD (2) 4,323.44 27.36 293.98 4,022.62 526.59 -1,275.803,719.12 2,622,196.46 284,558.83 1.27 1,375.99 MWD (2) 4,354.83 27.25 293.61 4,050.51 532.40 -1,288.973,747.01 2,622,202.27 284,545.66 0.64 1,390.37 MWD (2) 11/16/2011 9:48:44AM COMPASS 2003.16 Build 71 Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Three Mile Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: TMCU#3 TMCU#3 Survey Calculation Method:Minimum Curvature TMCU # 3 081611 @ 303.50ft (287.5 + 16) Design:TMCU #3 Database:.Sperry EDM .16 PRD MD Reference:TMCU # 3 081611 @ 303.50ft (287.5 + 16) North Reference: Well TMCU#3 Grid MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 4,386.27 27.21 294.27 4,078.47 538.24 -1,302.123,774.97 2,622,208.10 284,532.51 0.97 1,404.73 MWD (2) 4,417.82 27.27 294.51 4,106.52 544.20 -1,315.273,803.02 2,622,214.07 284,519.36 0.40 1,419.16 MWD (2) 4,449.31 27.10 294.47 4,134.53 550.17 -1,328.373,831.03 2,622,220.03 284,506.27 0.54 1,433.53 MWD (2) 4,480.73 26.90 294.50 4,162.52 556.08 -1,341.353,859.02 2,622,225.94 284,493.29 0.64 1,447.78 MWD (2) 4,512.19 26.83 294.64 4,190.59 561.99 -1,354.283,887.09 2,622,231.85 284,480.36 0.30 1,461.99 MWD (2) 4,543.62 26.87 294.25 4,218.63 567.86 -1,367.203,915.13 2,622,237.73 284,467.43 0.57 1,476.17 MWD (2) 4,574.89 26.89 295.29 4,246.52 573.79 -1,380.043,943.02 2,622,243.65 284,454.60 1.51 1,490.30 MWD (2) 4,606.37 26.86 295.04 4,274.60 579.84 -1,392.923,971.10 2,622,249.70 284,441.72 0.37 1,504.52 MWD (2) 4,637.83 26.87 293.66 4,302.67 585.70 -1,405.873,999.17 2,622,255.56 284,428.77 1.98 1,518.72 MWD (2) 4,669.79 26.79 293.06 4,331.19 591.42 -1,419.114,027.69 2,622,261.28 284,415.53 0.88 1,533.12 MWD (2) 4,700.71 26.63 293.60 4,358.81 596.92 -1,431.874,055.31 2,622,266.78 284,402.77 0.94 1,546.99 MWD (2) 4,732.16 26.49 293.95 4,386.94 602.59 -1,444.744,083.44 2,622,272.45 284,389.90 0.67 1,561.03 MWD (2) 4,763.59 26.25 293.92 4,415.10 608.25 -1,457.504,111.60 2,622,278.12 284,377.14 0.76 1,574.97 MWD (2) 4,795.01 26.15 294.15 4,443.29 613.90 -1,470.174,139.79 2,622,283.77 284,364.47 0.45 1,588.83 MWD (2) 4,826.46 26.09 294.82 4,471.53 619.64 -1,482.774,168.03 2,622,289.50 284,351.87 0.96 1,602.66 MWD (2) 4,857.87 26.14 294.60 4,499.73 625.42 -1,495.334,196.23 2,622,295.28 284,339.31 0.35 1,616.48 MWD (2) 4,889.29 26.15 294.92 4,527.94 631.22 -1,507.904,224.44 2,622,301.08 284,326.74 0.45 1,630.31 MWD (2) 4,920.77 26.02 294.50 4,556.21 637.01 -1,520.484,252.71 2,622,306.87 284,314.17 0.72 1,644.15 MWD (2) 4,952.23 25.93 295.04 4,584.49 642.78 -1,532.994,280.99 2,622,312.64 284,301.66 0.80 1,657.91 MWD (2) 4,983.50 25.79 295.04 4,612.63 648.55 -1,545.354,309.13 2,622,318.41 284,289.30 0.45 1,671.55 MWD (2) 5,014.97 25.75 294.89 4,640.97 654.33 -1,557.754,337.47 2,622,324.19 284,276.90 0.24 1,685.22 MWD (2) 5,046.46 25.78 295.44 4,669.33 660.15 -1,570.144,365.83 2,622,330.01 284,264.51 0.77 1,698.90 MWD (2) 5,142.00 25.78 295.44 4,755.36 678.00 -1,607.664,451.86 2,622,347.85 284,226.99 0.00 1,740.44 PROJECTED to TD 11/16/2011 9:48:44AM COMPASS 2003.16 Build 71 Page 6 0 1000 2000 D ep t h Three Mile Creek #3 SDL Crew Arrived Set 9 5/8" Casing 8850', 660' TVD LOT to 16.2 ppg EMW End of Run 300 Drill to 3009, POOH for Bit Trip 10/11/2011 @ 17:30 TD 12 1/4" Surface Hole 900' MD, 897' TVD Begin Drilling 12 1/4" Section Start Run 300 Begin 8 1/2" Section Failed Casing Test , POOH Begin Drilling 8 1/2" Section 7 Oct 2011 @ 13:46 Start Run 400 10/13/2011 @ 06:40 3000 4000 5000 6000 0 1 02 03 04 05 06 0 Me a s u r e d D Rig Days Run E-Logs TD Well 5142' MD, 4755.44' TVD On 10:01 , 18-Oct-2011 CBU, Short Trip to shoe Run 5 1/2" production liner.and cement Off Location11/2/2011 On 10/20/2011 @ 11:42 Drill extra 15' for Casing. From 5142' MD to 5157' MD POOH, R/U and Run E-LogsLogs. No go, Pull Out and RIH to clean hole. Surface Data Logging After Action Review Employee Name: Mark Lindloff Date: 11/3/2011 Well: TMC #3 Hole Section: Production What went as, or better than, planned: Three Mile Creek Unit 3 went very well for the mudloggers. Phone communications was 100% better making it easier to contact resources and resolve issues as they arose. Difficulties experienced: None. Recommendations: Maybe put some thought on how we can track depth better. Innovations and/or cost savings: Saved Aurora thousands of dollars by providing rig monitor service therefore Aurora did not have to purchase a stand alone monitoring system. Technical Report Title Date Client: Aurora Gas, LLC Field: Three Mile Creek Gas Field Rig: AWS #1 Date: November 1, 2011 Surface Data Logging End of Well Report Three Mile Creek #3 TABLE OF CONTENTS 1. General Information 2. Daily Summary 3. Morning Reports 4. Bit Record 5. Mud Record 6. Formation Tops 7. Survey Report 8. Days vs. Depth Digital Data to include: Final Logs Halliburton Log Viewer EMF Log Viewer ASCII/LAS Files End of Well Report in PDF format ADI Backup GENERAL WELL INFORMATION Company: Aurora Gas, LLC Rig: AWS-1 Well: Three Mile Creek #3 Field: Three Mile Creek Gas Field Borough: Kenai State: Alaska Country: United States API Number: 50-283-20156-00 Sperry Job Number: AK-AM-8370362 Job Start Date: 28 Sept 2011 Spud Date: 28-Sept-2011 Total Depth: 5159.00 North Reference: True Declination: 17.956 Dip Angle: 73.989 Total Field Strength: 55682 Date Of Magnetic Data: 01 Oct 2011 Wellhead Coordinates N: 61° 10’ 12.89” N Wellhead Coordinates W: 151° 12’ 47.03” W Drill Floor Elevation 302.17’ Ground Elevation: 287.5 Permanent Datum: Mean Sea Level SDL Engineers: Steve Gales David LaSalle Mark Lindloff Company Geologist: Ed Jones Company Representatives: Gary Goerlich, Mike Grubb Shane McGeeham SSDS Unit Number: 117 DAILY SUMMARY 9/27-9/29/2011 Mudloggers arrived on location. Performed rig site assessment and inspected mudlogging unit. Met with Company Man and Tool Pusher to discuss logistics and rig timelines. Mudloggers ran preliminary sensor cables. Rig began picking up BHA to clean out the conductor. 9/30/2011 Run in the hole with bottom hole assembly (BHA). Drill to 480’. Crown wheel down for repair. No depth tracked for 12 ¼” section. No gas to report. 10/01/2011 Continue Drilling to 900’ MD. Circulate hole clean. Crown wheel in operation. 10/02/2011 Circulate until clean returns, pull out of hole. Make a wiper trip then pull out of hole. Lay down BHA. Run 9.625” casing to 865’. Circulate hole clean for cement job the cement casing. 10/03/2011 Rig down cementers and then nipple down diverter. Cut casing and wait for it to cool. 10/04/2011 Rig up and test Blow out preventer stack (BOPS) and choke. Currently testing BOPS at report time. 10/05/2011 Finish testing BOPs. Pick up and Run in hole with 8 ½ " Mill Tooth BHA.. Tagged cement at 821'. Try to test casing to 1500 PSI. Unable to test. Pull out of hole (POOH) and lay down BHA. Rig up to run in the hole (RIH) with RTPS and RIH with the same 10/06/2011 Pressure test casing with RTPS. Pressure bled off at shoe. POOH and Lay Down RTPS Pick Up BHA and run in the hole. Drill out cement. Currently dumping and cleaning pits. 10/07/2011 Drill out cement from 825’ to shoe track at 900 ft. Circulate until clean and pull into casing and build 200 bbls of mud. Displace well with new mud and drill 20’ of new formation Circulate well clean and run Formation Integrity Test to 16.2 ppg Estimated mud weight Drill ahead to 973’ MD. 10/08/2011 Drilled from 979 to 1400, Perform wiper trip to shoe, RIH, Drill ahead to 1510’ MD. No losses down hole to report for the day. Average rate of penetration (ROP) for the day was 20 ft/hr with a max ROP of 72 ft/hr. Average Gas was 24 units with a Max Gas of 205 units. Samples 100% Claystone: grey, soft, gummy, amorphous. 10/09/2011 Continue to drill from 1510’ to 1910’, POOH to 1510’ for a wiper trip , RIH, Drill ahead to 2046. No losses to report down hole for the day. Average ROP for the day 34 ft/hr with a max ROP of 175 ft/hr at 1528’MD Average Gas for the day 95 units with a max gas of 362 units at 1758’ MD. Samples remain predominately claystone with a coal stringer starting at 1910’ to 1930’. 10/10/2011 Drill ahead from 2046' to 2410'. POOH 500' for wiper trip. No problems. RIH and drill ahead to 2566'. No losses to report down hole for the day. Average ROP for the day 45 ft/hr with a max ROP of 286 ft/hr at 2443’ md. Average gas for the day 145 units with a Max Gas of 1198 units at 2186’MD. Sample becoming sandier with increase in sand stringers and more coal was observed, 10/11/2011 Drill ahead from 2566' to 3008'. Pump 25 bbl Hi-Vis sweep (100% increase in cutting at shakers). POOH to check bit. Currently pulling out of the hole. Average ROP for the day 62 ft/hr with a max ROP of 137 ft/hr at 2932’ MD. Average gas for the day 107 units with a Max Gas of 464 units at 2861’ MD. 10/12/2011 POOH from 1900' to change out motor, check bit and change pump liners. 10/13/2011 POOH from 1900, changed out bit, motor and pump liners. 10/14/2011 Finish changing pump liners. Run in hole to bottom and circulate to condition mud. Drill from 3008’ to 3386' MD. Average ROP for the day 43 ft/hr with a max ROP of 167 ft/hr at 2932’ MD. Average gas for the day 76 units with a Max Gas of 960 units of trip gas at bottoms up. Samples remain claystone with an occasional coal and sand stringer. 10/15/2011 Drill ahead from 3800' to 4010'. Pump 25 bbl Hi-Vis sweep (100% increase in cuttings at shakers). Short Trip 500' for short/wiper trip. Circulate hole clean and Run in hole. Circulate hole clean again and drill ahead to 4224' MD. Average ROP for the day 10 ft/hr with a max ROP of 292 ft/hr at 4221’ MD. Average gas for the day 97 units with a Max Gas of 490 units of short trip gas at bottoms up. Samples increasingly sandy with scattered coal stringers. 10/16/2011 Drill ahead from 4204' to 4487'. Pump 25 bbl Hi-Vis sweep (150% increase in cuttings at shakers).Pull out of hole 500' for short/wiper trip. Circulate hole clean. Run in hole to bottom and circulate hole clean. Drill ahead to 4578'. Average ROP for the day 45 ft/hr with a max ROP of 204 ft/hr at 4559’ md. Average gas for the day 111 units with a Max Gas of 446 units at 4395’ md. Samples remaining sandy with scattered coal stringers, samples becoming heavily contaminated with calcium chloride. 10/17/2011 Drill ahead from 4550' to 5012'. Average ROP for the day 10 ft/hr with a max ROP of 292 ft/hr at 4221’ MD. Average gas for the day 75 units with a Max Gas of 446 units at 4837’ MD. Samples increasing in claystone until 5000’ md then becoming sandy. Samples continue to be contaminated with calcium chloride 10/18/2011 Drill ahead from 5012' to 5070'. Pump 25 bbl Hi-Vis sweep (400% increase in cuttings at shakers). Drill ahead to 5127’, circulate bottoms up, coal increase to 75% in samples, drill another 15 feet to 5142’ md. Circulated bottoms up and coal decreased to less than 10%.TD well at 5142'. Pull out of the hole 500’ for short/wiper trip. Run in hole to bottom and Pump 25 bbl Hi-Vis sweep (100% increase in cuttings at the shakers). Begin pulling out of hole with no problems. Average ROP for the day 10 ft/hr with a max ROP of 250 ft/hr at 5017’ MD. Average gas for the day 88 units with a Max Gas of 450 units at 5141’ MD. Samples increasing to 100% claystone at TD. 10/19/2011 Finish pulling out of hole. Lay down bottom hole assembly. Test BOPS Rig up and run in with wire line tools, Could not get past 1960’ md. Pull out and run in hole with a clean out assembly for a cleanout run. 10/20/2011 Continue to run in the hole with a for clean-out bottom hole assembly. Started circulating, mud really thick, continue to circulate till mud is even in and out, Trip Gas 365 units. Continue circulating to condition mud and drilled an extra 17’ to 5159’. Pull out of hole to 1800’ and circulate hole clean. Continue to pull out of the hole. 10/21/2011 Finish Pulling out of the hole then rig up and run wireline logs 10/22/2011 Finished wireline logs, rig down wireline, Pick up and run in hole for cleanout run. Circulated and conditioned hole 261 units of trip gas. Pull out of hole. Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth Lst 92' 100 Max: Sh Chromatograph (ppm) H2S Data Sample Line Avg: Milltooth Siltst ClystChtSd AWS#1 AK-AM-8370362 PVMBT Max @ ft Current 1 09/30/2011 100 12.25 1.031 (ppb Eq)cP Size Aurora Gas TMCU #3 North Cook Inlet Three Mile Creek Unit Daily Charges Avg ml/30min Min Avg pH Chlorides GvlCoal mg/l AvgMin Max Max API Filt 2.7900 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke22 TIH 85 Flow In (gpm) Current Pump & Flow Data: PWD Drilling All Circ % Depth R.O.P. (ft/hr) Gas (units) Hole Condition On Bot Hrs Avg Diam Max: Gas (units) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air We are continuing to Rigup and Troubleshoot equipment while they are TIH. md Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) Gas (units) Avg Diam Max: Depth R.O.P. (ft/hr) Gas (units)47 PWD Drilling All Circ % 542' TIH 89 481.48'MD Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 948 2.7900 389 154 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 6.8 mg/l AvgMin Max Max API Filt 8.00 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 22 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 10.00 3393 Three Mile Creek Unit 2 10/01/2011 542'MD 12.25 1.031 (ppb Eq)cP Size 2610.00 AWS#1 AK-AM-8370362 PVMBT Max @ ft Current 20.0 Milltooth Siltst ClystChtSd 480' H2S Data Sample Line Avg: 25 75 Sh Chromatograph (ppm) Depth 5.0 Lst 100 Max: Avg:Ambient Air Pit Room Silt Tuff Gas Breakdown Ann Corr Cor Solids (lb/100ft2) 500 Sst 24 hr Max YP to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air md We continued to rigup while the rig continued to Drill. A lot of progress was made today, the rig floor monitor and the Stoke Counters were both fixed and are up and running. We calibrated and set flows on the THA. We have had a Backbground Gas of 35 units of gas since hitting Coal at approximately 451'MD. Steve Gales, Jr Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 500 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 6.0 Lst 92' 100 Max: 75 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 25 20.0 Milltooth Siltst ClystChtSd 900' AWS#1 AK-AM-8370362 PVMBT Max @ ft Current 3 10/03/2011 900'MD 12.25 1.031 (ppb Eq)cP Size 1610.00 Aurora Gas LLC TMCU #3 North Cook Inlet 10.00 4680 Three Mile Creek Unit Daily Charges Avg 0 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 6.8 mg/l AvgMin Max Max API Filt 8.50 261 2.7900 0 0 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 0 Casing/Cement 0 900' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % Depth R.O.P. (ft/hr) Gas (units)0 Avg Diam Max: Gas (units) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In AirSteve Gales, Jr./David LaSalle POOH,LD, Run in Casing ,LD BHA, RIC,Cemen Casing. md Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP 726 1-1-NO-A-E-I-NO-TD Ann Corr Cor Solids (lb/100ft2) 500 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 7.0 Lst 92' 100 Max: 808' 0 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 0 20.0 Milltooth Siltst ClystCht 900' Sd 900' AWS#1 $3,445.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 4 10/04/2011 900'MD 12.25 1.031 (ppb Eq)cP Size 2210.00 Aurora Gas LLC TMCU #3 North Cook Inlet 10.00 1548 28.61 Three Mile Creek Unit Daily Charges Avg 0.0 0 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 6.8 mg/l AvgMin Max Max API Filt 9.00 24 2.7900 $16,880.00 0 0 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 0 Cement 0 900' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 0' Depth R.O.P. (ft/hr) Gas (units)0 Avg Diam Max: Gas (units) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In AirSteve Gales, Jr. / David LaSalle RD Cementers, nipple down diverter, Cut Casing, waitint on casing to cool. md Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) Gas (units) Avg Diam Max: 0' Depth R.O.P. (ft/hr) Gas (units)0 PWD Drilling All Circ % 0 Testing BOP 0 900' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 10 2.7900 $19,950.00 0 0 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 6.8 mg/l AvgMin Max Max API Filt 9.00 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 0.0 0 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 10.00 1449 28.61 Three Mile Creek Unit 5 10/05/2011 900'MD 12.25 1.031 (ppb Eq)cP Size 2310.00 AWS#1 $3,070.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 20.0 Milltooth Siltst ClystCht 900' Sd 900' H2S Data Sample Line Avg: 0 808' 0 Sh Chromatograph (ppm) Depth 7.0 Lst 92' 100 Max:Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: 1-1-NO-A-E-I-NO-TD Ann Corr Cor Solids (lb/100ft2) 500 Sst 24 hr Max YP 726 to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air md Testing BOP stack and choke. Steve Gales, Jr. / David LaSalle Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP 00 0-0-NO-A-E-I-NO-HP Ann Corr Cor Solids (lb/100ft2) 500 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 7.0 Lst 900' 200 Max: 0' 0 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 0 20.0 Milltooth Siltst ClystCht 900' Sd 900' AWS#1 $3,070.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 6 10/06/2011 900'MD 12.25 1.031 (ppb Eq)cP Size 229.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1446 0.00 Three Mile Creek Unit Daily Charges Avg 0.0 0 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 6.8 mg/l AvgMin Max Max API Filt 9.00 5 2.7900 $23,020.00 0 0 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 0 RIH, w/t RTPS 0 900' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 0' Depth R.O.P. (ft/hr) Gas (units)0 Avg Diam Max: Gas (units) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In AirMark Lindloff / David LaSalle Testing BOP stack and choke.tested casing, unable to test, POOH and LD, BHA, RIH, w/t RTPS @ time of report. md Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) Gas (units) Avg Diam Max: 876' 0' Depth R.O.P. (ft/hr) Gas (units)0 PWD Drilling All Circ % 0 RIH, w/t RTPS 4 876' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 385 2.79 $27,080.00 306 140 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 6.8 mg/l AvgMin Max Max API Filt 9.00 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 0.0 1 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1145 Three Mile Creek Unit 7 10/07/2011 900'MD 8.5 0.991 (ppb Eq)cP Size 249.50 AWS#1 $4,060.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 20.0 Tricone Siltst ClystChtSd 900' H2S Data Sample Line Avg: 00 Sh Chromatograph (ppm) Depth 9.0 Lst 300 Max:Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Ann Corr Cor Solids (lb/100ft2) 500 Sst 24 hr Max YP to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air md POOH and LD, BHA, RIH, w/t RTPS /PU BHA,TIH,Drill out cement @ time of report Mark Lindloff/ David LaSalle Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 500 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 5.0 Lst 300 Max: 100 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 0 0.3 Tricone Siltst ClystChtSd 950' AWS#1 $4,060.00 AK-AM-8370362 PVMBT 32.0 Max @ ft Current 46.0 8 10/08/2011 970'MD 8.5 0.991 (ppb Eq)cP Size 119.40 Aurora Gas LLC TMCU #3 North Cook Inlet 9.40 2255 Three Mile Creek Unit Daily Charges Avg 8.3 24 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 3.8 mg/l AvgMin Max Max API Filt 8.00 684 2.79 $31,140.00 344 140 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 0 RIH, w/t RTPS 71 966' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 972' Depth R.O.P. (ft/hr) Gas (units)20 973' Avg Diam Max: Gas (units) G Cto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In AirMark Lindloff/ David LaSalle 929.00 930.00 POOH and LD, BHA, RIH, w/t RTPS /PU BHA,TIH,Drill out cement @ time of report md 7 BG C1-2700 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 14,000 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 4.6 Lst 300 Max: 100 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 0 0.5 Tricone Siltst ClystChtSd 1510' AWS#1 $3,070.00 PVMBT 10.0 Max @ ft Current 72.0 9 10/09/2011 970'MD 8.5 0.991 (ppb Eq)cP Size 189.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 2252 Three Mile Creek Unit Daily Charges Avg 19.9 24 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 4.8 mg/l AvgMin Max Max API Filt 9.00 1551 2.79 $34,210.00 502 173 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 0 RIH, w/t RTPS 205 1361' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 1320' Depth R.O.P. (ft/hr) Gas (units)46 Avg Diam Max: Gas (units) G Cto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air Mark Lindloff/David LaSalle 1360.00 1320.00 130 BG 1361.00 1322.00 Drilled from 979 to 1400, POOH, wiper trip to shoe, RIH, Drill ahead to 1510 @ time of report. md C1-13577 205 FG C1-22101 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 13,000 Sst Ambient Air Pit Room 10 Silt Tuff Gas Breakdown Avg: Depth 4.3 Lst 300 Max: 90 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 0 0.5 Tricone Siltst ClystChtSd 2046' AWS#1 $3,070.00 PVMBT 23.0 Max @ ft Current 175.0 10 10/10/2011 970'MD 8.5 0.991 (ppb Eq)cP Size 219.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 2050 Three Mile Creek Unit Daily Charges Avg 34.0 95 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 5.9 mg/l AvgMin Max Max API Filt 8.50 1785 2.79 $37,280.00 493 170 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 0 Drilling 362 1758' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 1528' Depth R.O.P. (ft/hr) Gas (units)92 Avg Diam Max: Gas (units) CG Cto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air Mark Lindloff/David LaSalle 1559.00 1755.00 1990.00 1993.00 304 362 CG C1-11985 1560.00 1758.00 Drilled from 1510 to 1910, POOH, to 1510 wiper trip , RIH, Drill ahead to 2046 @ time of report. md 2024.002022.00 FG 103 BG C1-36296 C1-42982 299 CG C1-25814 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP C Ann Corr Cor Solids (lb/100ft2) 14,000 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 4.5 Lst 300 Max: 90 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 10 0.4 Tricone Siltst ClystChtSd 2566' AWS#1 $3,070.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 137.0 11 10/11/2011 2566'MD 8.5 0.991 (ppb Eq)cP Size 199.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1647 Three Mile Creek Unit Daily Charges Avg 46.0 109.0 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 5.8 mg/l AvgMin Max Max API Filt 8.50 1807 2.79 $40,350.00 470 160 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 0 Drilling 464.0 3009' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 3008' Depth R.O.P. (ft/hr) Gas (units)1 Avg Diam Max: Gas (units) G Cto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air C2-8.72 David LaSalle Mark Lindhoff 2384.00 2410.00 1521.00 1522.00 72 395 T 2390.00 2412.00 Drilled from 2046 to 2410, POOH, 500' wiper trip , RIH, Drill ahead to 2566 @ time of report. md 2455.002453.00 BG 251 CG C1-36352 740 FG C1-76437 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 15,000 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 4.3 Lst 300 Max: 0 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 0 1.0 Tricone Siltst ClystChtSd 3008' AWS#1 $3,070.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 187.0 12 10/12/2011 3008'MD 8.5 0.991 (ppb Eq)cP Size 289.60 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 2579 Three Mile Creek Unit Daily Charges Avg 62.0 119 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 5.7 mg/l AvgMin Max Max API Filt 9.50 20 2.79 $43,420.00 0 0 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 0 Tripping 464 2584' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 2567' Depth R.O.P. (ft/hr) Gas (units)1 Avg Diam Max: G Gas (units) Cto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle/ Mark Lindhoff 2649.00 FG 272 C1-33028.92 134 464 2662.00 2672.00 2675.00 CG 2861.00 CG 168 C1-41046.70 FG 2650.00 2664.00 C1-46607.30 230.002929.00 BG2985.00 C1-14775.17 2860.00 Drilled from 2066 to 3008, POOH, pumped 25 bbl sweep Hi Vis(100%) increase in cuttings at shakers POOH. md 2722.002720.00 2989.00 358 FG 234 C1-24131.99 C1-16881.45 BG 176 C1-8357.90 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP 4510.49 1-1-CT-A-E-I-NO-RIG Ann Corr Cor Solids (lb/100ft2) 15,000 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 4.2 Lst 900' 300 Max: 2108' 0 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 0 1.3 Tricone Siltst ClystCht 3008' Sd 3008' AWS#1 $3,070.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 13 10-13-11 3008'MD 8.5 0.991 (ppb Eq)cP Size 259.70 Aurora Gas LLC TMCU #3 North Cook Inlet 9.70 2788 53.28 Three Mile Creek Unit Daily Charges Avg 0.0 106 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 6.8 mg/l AvgMin Max Max API Filt 8.50 0 2.34 $46,490.00 0 0 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 0 Tripping 464 2861' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 0' Depth R.O.P. (ft/hr) Gas (units)0 Avg Diam Max: Gas (units) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle /Mark Lindhoff FG 272 C1-33028.92 464 2830.00 2834.00 CG 2861.00 C1-41046.70 FG C1-46607.30 230.002929.00 2860.00 POOH from 1900, changed out bit, motor and pump liners. md 2722.002720.00 358 BG 105 C1-12890.18 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) G Gas (units) Avg Diam Max: 3380' Depth R.O.P. (ft/hr) Gas (units)78 PWD Drilling All Circ % 80 Drilling 957 2971' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 1770 2.345 $49,560.00 428 158 Total Charges: Flow (SPM) SPP (psi) Gallons/stroke 6.8 mg/l AvgMin Max Max API Filt 8.00 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 42.0 106 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 2556 Three Mile Creek Unit 14 10-14-11 3088'MD 8.5 0.991 (ppb Eq)cP Size 239.50 AWS#1 $3,070.00 AK-AM-8370362 PVMBT 34.0 Max @ ft Current 58.0 1.0 Milltooth Siltst ClystChtSd 3088' H2S Data Sample Line Avg: 40 30 Sh Chromatograph (ppm) Depth 4.8 Lst 400 Max:Ambient Air Pit Room 30 Silt Tuff Gas Breakdown Avg: Ann Corr Cor Solids (lb/100ft2) 15,000 Sst 24 hr Max YP to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air FG 151 C1-17771.43 C1- 12361.06 TG 957 3200.00 189 md 3206.00 RIH , Drill to 3386 @ time of report. C1-95327.20 3340.003338.00 3660.00 2971.00 3103.003100.00 3120.00 3121.00 FG 3665.00 CG 160 C1-22100.20 FG 821 FG 252 C1-30244.25 2969.00 David LaSalle /Mark Lindhoff Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) G Gas (units) C Avg Diam Max: 3649' Depth R.O.P. (ft/hr) Gas (units)78 PWD Drilling All Circ % 736 Drilling 306 3692' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 1988 2.345 $52,630.00 428 420 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 6.8 mg/l AvgMin Max Max API Filt 8.50 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 10.6 76 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 3072 Three Mile Creek Unit 15 10-15-11 3824 8.5 0.991 (ppb Eq)cP Size 269.50 AWS#1 $3,070.00 AK-AM-8370362 PVMBT 42.0 Max @ ft Current 177.0 1.3 Milltooth Siltst ClystChtSd 3088' H2S Data Sample Line Avg: 20 75 Sh Chromatograph (ppm) Depth 5.0 Lst 400 Max:Ambient Air Pit Room 5 Silt Tuff Gas Breakdown Avg: Ann Corr Cor Solids (lb/100ft2) 15,000 Sst 24 hr Max YP to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air CG 105 C1-10454 C1- 22292 FG 170 C1-201178 3623.00 277 md 3628.00 RIH , Drill to 3386 @ time of report. C1-34339 3684.003675.00 3690.00 3535.00 3575.003570.00 3600.00 3602.00 FG 3692.00 CG 182 C1-11811 FG 306 BG 48 C1-7601 3526.00 David LaSalle/Mark Lindhoff Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP New Ann Corr Cor Solids (lb/100ft2) 13,000 Sst Ambient Air Pit Room 5 Silt Tuff Gas Breakdown Avg: Depth 6.0 Lst 0' 400 Max: 55 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 40 1.0 Milltooth Siltst ClystChtSd 3088' AWS#1 $3,070.00 AK-AM-8370362 PVMBT 42.0 Max @ ft Current 292.0 16 10-16-11 4224 8.5 0.991 (ppb Eq)cP Size 169.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1847 30.90 Three Mile Creek Unit Daily Charges Avg 10.6 97 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 5.2 mg/l AvgMin Max Max API Filt 8.50 1825 2.345 $55,700.00 468 380 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 400 Drilling 363 3962' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 4221' Depth R.O.P. (ft/hr) Gas (units)80 Avg Diam Max: Gas (units) G Cto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle/Mark Lindhoff 3830.00 C1-33328.37 C1-35187.95 145 CG C1-13353.52 CG BG TG 3860.00 3940.00 3944.00 363 4010.00 228 FG C1-34609.57 493 3836.00 3863.00 4130.00 4132.00 308 4067.004065.00 43 4105.00 C1-4716.59 4005.00 277 FG POOH 500 fr wiper short trip, currently drilling. Drilled ahead from 4010 @ time of report.pumped 25 bbl sweep 100% increase in cuttings, md 4182.00 3962.003960.00 4109.00 4184.00 FG 304 CG C1-36267.62 C1-36410.35 143 FG C1-16687.93 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 16,000 Sst Ambient Air Pit Room 75 Silt Tuff Gas Breakdown Avg: Depth 5.8 Lst 400 Max: 20 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 5 1.3 Tricone Siltst ClystChtSd 4519' AWS#1 $3,070.00 AK-AM-8370362 PVMBT 48.0 Max @ ft Current 203.0 17 10-17-11 4593 8.5 0.991 (ppb Eq)cP Size 169.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1947 40.40 Three Mile Creek Unit Daily Charges Avg 6.8 103 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 5.7 mg/l AvgMin Max Max API Filt 9.50 1971 2.345 $58,770.00 426 370 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 369' Drilling 423 4550' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 4559' Depth R.O.P. (ft/hr) Gas (units)112 Avg Diam Max: Gas (units) CG Cto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle / Mark Lindhoff 4324.00 4390.00 4465.00 4468.00 327 445 FG C1-39619.86 4326.00 4395.00 POOH 500 fr wiper short trip, RIH,currently drilling ahead @ time of report Drilled ahead from 4204 to 4487 pumped 25 bbl sweep 100% increase in cuttings, md 4551.004550.00 CG 396 FG C119886.81 C1-53449.28 221 CG C1-23878.76 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 15,000 Sst Ambient Air Pit Room 20 Silt Tuff Gas Breakdown Avg: Depth 5.5 Lst 400 Max: 10 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 70 1.0 Milltooth Siltst ClystChtSd 4519' AWS#1 $3,070.00 AK-AM-8370362 PVMBT 48.0 Max @ ft Current 250.0 18 10-18-11 5012 8.5 0.991 (ppb Eq)cP Size 189.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1847 Three Mile Creek Unit Daily Charges Avg 9.3 82 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 6.1 mg/l AvgMin Max Max API Filt 8.00 2370 2.345 $61,840.00 455 415 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 419 Drilling 446 4838' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 5017' Depth R.O.P. (ft/hr) Gas (units)57 Avg Diam Max: Gas (units) G Cto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle/Mark Lindhoff 4882.00 34 BG C1-6256.12 FG 4835.00 4735.00 4737.00 329 4622.00 446 FG C1-15564.06 440 4884.00 4838.00 C1-52312.71 4956.004954.00 4620.00 Drilled ahead from 4550 . md 4696.004694.00 CG 160 CG C1-16987.12 C1-49138.43 185 FG C1-21886.35 Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 14,000 Sst Ambient Air Pit Room 0 Silt Tuff Gas Breakdown Avg: Depth 5.0 Lst 400 Max: 0 Sh Chromatograph (ppm) H2S Data Sample Line Avg: 0 1.0 Milltooth Siltst ClystChtSd 5142' AWS#1 $2,320.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 250.0 19 10-19-11 5142 8.5 0.991 (ppb Eq)cP Size 229.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 2047 57.40 Three Mile Creek Unit Daily Charges Avg 0.0 0 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 6.8 mg/l AvgMin Max Max API Filt 9.00 14 2.345 $65,660.00 0 0 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 130' Drilling 1119 5141' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 5017' Depth R.O.P. (ft/hr) Gas (units)0 Avg Diam Max: Gas (units) Gto to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle/Mark Lindhoff 5139.00 CG 5150.00 5060.00 5063.00 450 5079.00 254 CG C1-26045.73 175 5141.00 5111.00 C1-23142.205075.00 pumped hi vis sweep 100% increase in cuttings,POOH @ time of report. Drilled ahead from 5012 to 5070 pumped hi vis sweep 400% increase in cuttings. Drilled ahead to 5142 TD, md 5051.005050.00 FG 308 FG C1-34499.37 C1-23863.88 1119 TG Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) Gas (units) Avg Diam Max: 0' Depth R.O.P. (ft/hr) Gas (units)0 PWD Drilling All Circ % 0 RIH clean out run 00' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 57 2.345 $68,052.90 15 7 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 6.0 mg/l AvgMin Max Max API Filt 9.00 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 0.0 0 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1652 64.19 Three Mile Creek Unit 20 10-20-11 5142 8.5 0.991 (ppb Eq)cP Size 169.50 AWS#1 $2,320.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 1.0 Tricone Siltst ClystCht 5142' Sd 5142' H2S Data Sample Line Avg: 0 2134' 0 Sh Chromatograph (ppm) Depth 5.0 Lst 3008' 400 Max:Ambient Air Pit Room 0 Silt Tuff Gas Breakdown Avg: 5-5-WT-A-F-ER-TD Ann Corr Cor Solids (lb/100ft2) 12,000 Sst 24 hr Max YP 7117 to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air md TOOH, Tested BOPs, RIH with wire line tools stuck at 1960', Change wire line RIH for clean out run. David LaSalle/Mark Lindhoff Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) Gas (units) G C Avg Diam Max: 5158' Depth R.O.P. (ft/hr) Gas (units)0 PWD Drilling All Circ % 17 Drill to 5159,POOH 238 5158' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 25 2.345 $70,372.00 0 0 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 6.0 mg/l AvgMin Max Max API Filt 8.50 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 0.3 145 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1545 Three Mile Creek Unit 21 10-21-11 5159 8.5 0.991 (ppb Eq)cP Size 159.50 AWS#1 $2,320.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 138.0 1.0 Tricone Siltst ClystChtSd 5142' H2S Data Sample Line Avg: 595 Sh Chromatograph (ppm) Depth 5.0 Lst 500 Max:Ambient Air Pit Room 0 Silt Tuff Gas Breakdown Avg: Ann Corr Cor Solids (lb/100ft2) 12,000 Sst 24 hr Max YP to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air 261 CG 238 FG C1-28403.13 md RIH clean out run, Drill to 5159, POOH to 1800 Circulated hole clean,TOOH,RU wire line. 5158.00 5135.005130.00 1890.00 1892.00 226 CG 5155.00 David LaSalle/Mark Lindhoff Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP 8022.5 3-3-WT-A-E-I-NO-LOG Ann Corr Cor Solids (lb/100ft2) 15,000 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth 4.5 Lst 5142' 500 Max: 17' Sh Chromatograph (ppm) H2S Data Sample Line Avg: 1.0 Tricone Siltst ClystCht 5159' Sd 5159' AWS#1 $2,320.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 22 10-22-11 5159 8.5 0.991 (ppb Eq)cP Size 249.50 Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1752 0.00 Three Mile Creek Unit Daily Charges Avg 0.0 0 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal 5.7 mg/l AvgMin Max Max API Filt 8.50 29 2.345 $72,692.00 0 4 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 0 Wireline 00' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 0' Depth R.O.P. (ft/hr) Gas (units)0 Avg Diam Max: Gas (units) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle / Mark Lindhoff TOOH, RU Wireline, Running wireline logs. md Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) Gas (units) G Avg Diam Max: 0' Depth R.O.P. (ft/hr) Gas (units)0 PWD Drilling All Circ % 0 TOOH,LD, Pipe 261 5159' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 25 2.345 $75,012.00 36 6 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 5.7 mg/l AvgMin Max Max API Filt 8.50 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 0.0 39 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 1965 0.00 Three Mile Creek Unit 23 10-23-11 4464 8.5 0.991 (ppb Eq)cP Size 239.50 AWS#1 $2,320.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 1.0 Tricone Siltst ClystCht 5159' Sd 5159' H2S Data Sample Line Avg: 0' Sh Chromatograph (ppm) Depth 4.5 Lst 5159' 600 Max:Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: N/A Ann Corr Cor Solids (lb/100ft2) 15,000 Sst 24 hr Max YP 700.00 to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air 261 WTG md finished wireline logs, RD wireline,RIH for cleanout run,Circulateed hole,TOOH, laying down drill string. 5159.005159.00 David LaSalle / Mark Lindhoff Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) Gas (units) Avg Diam Max: 0' Depth R.O.P. (ft/hr) Gas (units)0 PWD Drilling All Circ % 0 RIH,with caseing 00' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs 0 2.345 $77,332.00 0 0 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 5.9 mg/l AvgMin Max Max API Filt 8.50 Min Avg pH Chlorides GvlCoal ml/30min Daily Charges Avg 0.0 0 Hole Condition Aurora Gas LLC TMCU #3 North Cook Inlet 9.50 2268 0.00 Three Mile Creek Unit 24 10-24-11 5159 8.5 0.991 (ppb Eq)cP Size 279.50 AWS#1 $2,320.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 1.0 Tricone Siltst ClystChtSd 5159' H2S Data Sample Line Avg: Sh Chromatograph (ppm) Depth 4.0 Lst 600 Max:Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Ann Corr Cor Solids (lb/100ft2) 13,000 Sst 24 hr Max YP to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air md layed down drill string.RIH with CSG David LaSalle / Mark Lindhoff Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP New Ann Corr Cor Solids (lb/100ft2) 128,000 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth N/A Lst 0' 600 Max: Sh Chromatograph (ppm) H2S Data Sample Line Avg: N/A Milltooth Siltst ClystChtSd 4662' AWS#1 $2,320.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 25 10-25-11 5159 8.5 0.991 (ppb Eq)cP Size N/A9.60 Aurora Gas LLC TMCU #3 North Cook Inlet 9.60 N/A27 0.00 Three Mile Creek Unit Daily Charges Avg 0.0 0 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal N/A mg/l AvgMin Max Max API Filt 7.00 0 2.345 $77,332.00 21 0 Total Charges: Flow out (gpm) SPP (psi) Gallons/stroke 0 Cementing 00' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 0' Depth R.O.P. (ft/hr) Gas (units)0 Avg Diam Max: Gas (units) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle / Mark Lindhoff Circulated hole, Pumped Cement,displaced with brine, waiting on Cement. md Customer: Report #: Well: Date: Area: Depth Location: Progress 24 hrs: Rig: Rig Activity: Job No.: Report For: ROP & Gas: . Mud Data:Density (ppg) Viscosity Depth ft in out (sec/qt) BHA Run #Bit Type TFA Hours Depth in / out Footage WOB RPM Condition Lithology (%): (current) 24 hr Max YP Ann Corr Cor Solids (lb/100ft2) 128,000 Sst Ambient Air Pit Room Silt Tuff Gas Breakdown Avg: Depth N/A Lst Max: Sh Chromatograph (ppm) H2S Data Sample Line Avg: N/A Siltst ClystChtSd 4662' AWS#1 $2,320.00 AK-AM-8370362 PVMBT 0.0 Max @ ft Current 0.0 26 10-26-11 5159 (ppb Eq)cP Size N/A9.60 Aurora Gas LLC TMCU #3 North Cook Inlet 9.60 N/A27 Three Mile Creek Unit Daily Charges Avg 0.0 0 Hole Condition ml/30min Min Avg pH Chlorides GvlCoal N/A mg/l AvgMin Max Max API Filt 7.00 0 1763 $77,332.00 11 2 Total Charges: Flow In (spm) SPP (psi) Gallons/stroke 0 RIH w/t Tubing 00' Flow In (gpm) Current Pump & Flow Data: On Bot Hrs PWD Drilling All Circ % 0' Depth R.O.P. (ft/hr) Gas (units)0 Avg Diam Max: Gas (units) to to to to to to to to to Gas Type abreviations: BG - Background Gas; GP - Gas Peak; CG - Connection Gas; WTG - Wiper Trip Gas; POG - Pumps Off Gas; PG - Produced Gas; RG - Ream Gas; T-- - Trip…; F-- - Formation…; E-- - Early… 24 hr Recap: Logging Engineer:* 10000 units = 100% Gas In Air David LaSalle / Mark Lindhoff Wait on Cement, tested BOPs, RIH with tubing. md WELL NAME:Three Mile Creek #3LOCATION:Three Mile Creek Gas FieldOPERATOR:Aurora Gas, LLCAREA:Kenai, AKMUD CO:BaroidSTATE:AlaskaRIG:AWS-1SPUD:28-Sep-11SPERRY JOB:AK-AM-0008370362TD:18-Oct-11BIT RECORDBHA # Bit # Bit Type Bit SizeDepth InDepth OutFootage Bit HoursTFA AVG ROPWOB (max)RPM (max)SPP(max)FLOW GPM (max)Bit Grade Remarks1 1 Hughes GT-C1 12.50 93 900 807 28.61 1.030828.2 1080 690 455 1-1-NO-A-E-I-NO-TDTD 12 1/4" section2 2 QHC1R Tricone 8.50 900 900 0 0.00 0.99100.0 00 0 0 0-0-NO-A-E-I-NO-HPCasing Pressure test failed, POOH to run RTTS3 2rr QHC1R Tricone 8.50 900 3009 2109 64.19 0.991038.0 1890 2050 495 1-1-CT-A-E-I-NO-RIGPOOH for Bit Trip4 3 QHC1R Tricone 8.50 3009 5142 2133 64.19 0.991033.2 25 80 2650 460 5-5-WT-A-F-ER-TD TD TMCU 3 5 4RR2 QHC1R Tricone 8.50 5142 5159 17 0.67 0.991025.0 23 901900 425 3-3-ET-A-E-I-NO-LOGDrill 17" extra for Casing6 0 7 8 1113141718 WELL NAME:Three Mile Creek #3LOCATION:Three Mile Creek Gas FieldOPERATOR:Aurora Gas, LLCAREA:Kenai, AKMUD CO:BaroidSTATE:AlaskaRIG:AWS-1SPUD:28-Sep-11SPERRY JOB:AK-AM-0008370362TD:5159' Water Based Mud RecordDate Depth Wt Vis PV YP Gels FiltR600/R300/R200/R100/R6/R3Cake SolidsOil/WaterSd Pm pH MBT Pf/Mf Chlor Hard Remarksft - MD ppg sec cP lb/100 lb/100ft2 m/30m Rheometer 32nds % % % ppb Eqv mg/l Ca++28-Sep 09.20 82 13 35 24/35/45 15.0 61/48/41/36/22/21 2 6.8 0.0/93.0 - 0.3 9 20 0.30/0.60 500 40 Rig up29-Sep 010.00 80 19 26 23/33/43 15.0 63/44/37/28/17/16 2 6.8 0.0/93.0 - 0.2 8.5 20 8.5/62 500 40 Rig up30-Sep 20010.00 83 26 33 14/35/45 5.0 85/59/48/36/15/14 2 6.8 0.0/93.0 - 0.1 8 20 0.10/0.20 500 40 Drilling1-Oct900 10.00 81 16 48 9/18/29 5.0 80/64/52/38/12/8 2/0 6.8 0.0/93.0-0.10 8.5 20.0 0.10/0.30 500 40Drilling/Circulating hole clean2-Oct900 10.00 48 23 12 4/6/7 7.0 58/35/26/15/4/3 2/0 6.8 0.0/93.0-0.30 9.0 20.0 0.10/0.70 500 40Circulating //POOH3-Oct900 10.00 48 22 15 5/7/8 7.0 59/37/28/16/5/4 2/0 6.8 93.0-0.20 9.0 20.0 0.10/0.60 500 40Cementing4-Oct900 10.00 49 23 14 4/6/7 7.0 60/37/29/17/6/4 2/0 6.8 93.0-0.20 9.0 20.0 0.10/0.60 500 40Testing BOPs5-Oct900 9.50 46 22 14 4/5/7 9.0 58/36/27/16/5/4 2/0 6.8 93.0-0.40 8.5 20.0 0.10/0.30 500 40RIH w/ RTPS6-Oct900 9.50 45 24 11 5/6/7 9.0 59/35/17/17/6/5 2/0 6.8 93.0-0.40 8.5 20.0 0.10/0.30 500 40pressure test csg/drill cement7-Oct950 9.40 55 11 22 8/12/15 5.0 44/33/29/21/8/6 1.0 3.8 0.0/95.0-0.18 8.0 0.3 0.10/0.60 14,000 800Circulating /drill to 9738-Oct1510 9.50 52 18 22 5/8/10 4.6 58/40/32/22/6/4 1.0 4.8 0.0/94.0-0.94 9.0 0.5 0.10/0.45 14,000 800wiper trip to shoe drill to 15109-Oct2046 9.50 50 21 20 4/5/6 4.3 62/41/32/21/6/3 1.0 5.9 0.0/93.0-0.50 8.5 0.5 0.10/0.35 13,000 800drill 1910,POOH, for wiper tripT10-Oct2566 9.50 47 19 16 3/4/7 4.5 54/35/28/18/5/3 1.0 5.8 0.0/93.0-0.38 8.5 0.4 0.10/0.35 14,000 800Drill to 256611 O t30089607928256/10/154381/53/42/20/9/51/05700/93004595100 10/0 5015 000800d POOH bit t i11-Oct30089.60 79 28 25 6/10/154.3 81/53/42/20/9/51/05.7 0.0/93.0-0.459.5 1.0 0.10/0.5015,000800pumped sweep POOH bit trip12-Oct3008 9.70 88 25 27 7/14/18 4.2 77/52/39/26/10/7 1/0 6.8 0.0/92.0-0.25 8.5 1.3 0.10/0.30 15,000 800Chg bit and motor/RIH13-Oct3386 9.50 56 23 25 10/16/20 4.8 71/48/39/26/8/6 1/0 6.8 0.0/92.0-0.20 8.0 1.0 0.10/0.80 15,000 800RIH,Drill to 338614-Oct3560 9.50 72 26 30 8/17/2024 5.0 82/56/45/30/14/8 1/0 6.8 0.0/92.0-0.25 8.5 1.3 0.10/1.00 15,000 400 wiper trip, RIH, drill to 380015-Oct4200 9.50 47 16 18 7/12/2015 6.0 50/34/28/19/6/3 1/0 5.2 0.0/94.0-0.40 8.5 1.0 0.18/0.85 13,000 400 wiper trip, RIH, drill to 420416-Oct4519 9.50 47 16 19 10/18/25 5.8 51/35/29/20/8/6 2.0 5.7 0.0/93.0-0.48 9.5 1.3 0.16/1.00 16,000 300 wiper trip, RIH, drill to 455017-Oct4950 9.50 47 18 18 6/16/20 5.5 54/36/29/19/5/3 1.0 6.1 0.0/93.0-0.42 8.5 1.0 0.10/1.00 15,000 400 drill to 5142, POOH , wiper trip18-Oct5142 9.50 47 22 20 6/14/19 5.0 64/42/33/19/5/4 1.0 6.8 0.0/92.0-0.60 9.0 1.0 0.15/1.00 14,000 500 drill to 501319-Oct5142 9.50 52 16 16 3/18/12 5.0 48/32/24/16/4/3 1.0 6.0 0.0/93.0-0.60 9.0 1.0 0.15/0.80 12,000 500TOOH,Test BOP,RIH wire line,stuck20-Oct5159 9.50 45 15 15 3/19/13 5.0 45/30/23/15/3/2 1.0 6.0 0.0/93.0-0.20 8.5 1.0 0.00/0.80 12,000 500Drill to 5159, TOOH,RU wireline21-Oct5159 9.50 52 24 17 3/10/14 4.5 65/41/31/20/3/2 1 5.7 0.00/93.0 0.25 0.10 8.5 1.0 0.00/0.90 15,000 500Wire Line logs22-Oct5159 9.50 65 23 16 4/15/20 4.5 65/42/32/21/5/4 1 5.7 0.00/93.0 0.25 0.10 8.5 1.0 0.00/93.0 15,000 500Tripping23-Oct5159 9.50 68 27 22 4/10/16 4.0 76/49/32/24/5/3 1 5.9 0.00/93.0 0.25 0.10 8.5 1.0 0.00/1.10 13,000 500Run Casing and cement24-Oct5159 9.60 27 - - - - - - - - - - - - - - - Wait on Cement25-Oct5159 9.60 27 - - - - - - - - - - - - - - - Rig FdownCasing Record16" Conductor @ 9312.75" @ 884' Marker MD INC AZ TVD TVDSS Beluga Tsuga 2-4 2025.0 23.45 289.64 1980.18 1677 Beluga Tsuga 2-5 3210.0 22.20 291.92 3034.96 2731 Beluga Tsuga 2-6 4050.0 22.99 294.25 3780.60 3477 Beluga Tsuga 2-7 4770.0 26.23 293.97 4420.95 4117 Three Mile Creek #3 Interpolated Tops 16 November, 2011 Cook Inlet Three Mile Creek Unit TMCU#3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Three Mile Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: TMCU#3 TMCU#3 Survey Calculation Method:Minimum Curvature TMCU # 3 081611 @ 303.50ft (287.5 + 16) Design:TMCU #3 Database:.Sperry EDM .16 PRD MD Reference:TMCU # 3 081611 @ 303.50ft (287.5 + 16) North Reference: Well TMCU#3 Grid Map System: Geo Datum: Project Map Zone: System Datum:US State Plane 1927 (Exact solution) NAD 1927 (NADCON CONUS) Cook Inlet, COOK INLET BASIN Alaska Zone 04 Mean Sea Level Using Well Reference Point Using geodetic scale factor Well Well Position Longitude: Latitude: Easting: Northing: ft +E/-W +N/-S Position Uncertainty ft ft ftGround Level: TMCU#3 ft ft 0.00 0.00 2,621,669.89 285,834.57 287.50Wellhead Elevation:303.50 ft0.00 61° 10' 12.894 N 151° 12' 47.03 W Wellbore Declination (°) Field Strength (nT) Sample Date Dip Angle (°) TMCU#3 Model NameMagnetics BGGM2011 10/1/2011 17.96 73.99 55,679 Phase:Version: Audit Notes: Design TMCU #3 1.0 ACTUAL Vertical Section: Depth From (TVD) (ft) +N/-S (ft) Direction (°) +E/-W (ft) Tie On Depth:16.00 296.910.000.0016.00 From (ft) Survey Program DescriptionTool NameSurvey (Wellbore) To (ft) Date 11/16/2011 Survey Start Date BLIND Blind drilling93.00 993.05 TMCU #3 (Blind) (TMCU#3)09/27/2011 MWD MWD - Standard1,025.30 5,046.46 TMCU #3 (MWD) (TMCU#3)10/11/2011 MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 16.00 0.00 0.00 16.00 0.00 0.00-287.50 2,621,669.89 285,834.57 0.00 0.00 UNDEFINED 93.00 0.00 0.00 93.00 0.00 0.00-210.50 2,621,669.89 285,834.57 0.00 0.00 BLIND (1) 136.91 2.12 328.34 136.90 0.69 -0.43-166.60 2,621,670.58 285,834.14 4.83 0.69 BLIND (1) 167.23 2.49 326.42 167.20 1.72 -1.08-136.30 2,621,671.61 285,833.49 1.25 1.74 BLIND (1) 197.51 2.50 328.53 197.45 2.83 -1.79-106.05 2,621,672.72 285,832.78 0.31 2.88 BLIND (1) 227.71 2.66 325.62 227.62 3.97 -2.53-75.88 2,621,673.86 285,832.04 0.68 4.05 BLIND (1) 258.04 2.85 325.50 257.91 5.17 -3.36-45.59 2,621,675.06 285,831.21 0.63 5.33 BLIND (1) 288.07 3.22 323.45 287.90 6.46 -4.28-15.60 2,621,676.35 285,830.29 1.28 6.74 BLIND (1) 318.36 3.21 323.09 318.14 7.83 -5.3014.64 2,621,677.71 285,829.27 0.07 8.27 BLIND (1) 348.85 3.36 322.58 348.58 9.22 -6.3545.08 2,621,679.11 285,828.22 0.50 9.84 BLIND (1) 379.31 3.45 320.27 378.99 10.63 -7.4875.49 2,621,680.52 285,827.09 0.54 11.48 BLIND (1) 409.48 3.75 321.27 409.10 12.10 -8.68105.60 2,621,681.99 285,825.89 1.02 13.22 BLIND (1) 439.68 4.02 323.32 439.23 13.72 -9.93135.73 2,621,683.61 285,824.64 1.01 15.06 BLIND (1) 11/16/2011 9:48:44AM COMPASS 2003.16 Build 71 Page 2 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Three Mile Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: TMCU#3 TMCU#3 Survey Calculation Method:Minimum Curvature TMCU # 3 081611 @ 303.50ft (287.5 + 16) Design:TMCU #3 Database:.Sperry EDM .16 PRD MD Reference:TMCU # 3 081611 @ 303.50ft (287.5 + 16) North Reference: Well TMCU#3 Grid MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 469.19 4.31 322.01 468.66 15.42 -11.23165.16 2,621,685.31 285,823.34 1.03 16.99 BLIND (1) 503.93 4.75 322.16 503.29 17.59 -12.92199.79 2,621,687.48 285,821.65 1.27 19.48 BLIND (1) 534.33 5.08 323.72 533.58 19.67 -14.49230.08 2,621,689.55 285,820.09 1.17 21.82 BLIND (1) 595.69 5.64 323.54 594.67 24.28 -17.88291.17 2,621,694.17 285,816.69 0.91 26.94 BLIND (1) 627.13 5.62 322.05 625.96 26.74 -19.75322.46 2,621,696.63 285,814.82 0.47 29.71 BLIND (1) 658.57 5.70 321.99 657.25 29.18 -21.66353.75 2,621,699.07 285,812.91 0.26 32.52 BLIND (1) 689.97 6.09 322.77 688.48 31.74 -23.63384.98 2,621,701.62 285,810.95 1.27 35.43 BLIND (1) 721.35 6.33 322.61 719.68 34.44 -25.68416.18 2,621,704.32 285,808.89 0.77 38.49 BLIND (1) 752.75 6.41 322.97 750.88 37.21 -27.79447.38 2,621,707.10 285,806.78 0.28 41.62 BLIND (1) 784.11 7.05 323.83 782.03 40.16 -29.98478.53 2,621,710.05 285,804.59 2.07 44.91 BLIND (1) 815.55 7.06 323.22 813.23 43.27 -32.28509.73 2,621,713.15 285,802.30 0.24 48.36 BLIND (1) 930.19 8.13 323.00 926.86 55.38 -41.37623.36 2,621,725.27 285,793.20 0.93 61.96 BLIND (1) 961.59 8.17 323.14 957.94 58.94 -44.05654.44 2,621,728.83 285,790.53 0.14 65.95 BLIND (1) 993.05 8.19 322.57 989.08 62.51 -46.75685.58 2,621,732.40 285,787.82 0.27 69.98 BLIND (1) 1,025.30 8.14 323.43 1,021.01 66.17 -49.51717.51 2,621,736.05 285,785.07 0.41 74.09 MWD (2) 1,055.88 8.34 321.57 1,051.27 69.64 -52.17747.77 2,621,739.53 285,782.40 1.09 78.04 MWD (2) 1,087.38 8.32 319.33 1,082.44 73.16 -55.08778.94 2,621,743.05 285,779.49 1.03 82.23 MWD (2) 1,118.86 8.51 317.10 1,113.58 76.60 -58.15810.08 2,621,746.48 285,776.42 1.20 86.52 MWD (2) 1,150.30 8.82 314.30 1,144.66 79.98 -61.46841.16 2,621,749.87 285,773.11 1.66 91.00 MWD (2) 1,181.74 8.96 311.76 1,175.72 83.30 -65.01872.22 2,621,753.18 285,769.56 1.33 95.67 MWD (2) 1,244.57 9.48 307.42 1,237.74 89.70 -72.77934.24 2,621,759.59 285,761.80 1.38 105.49 MWD (2) 1,275.89 10.07 306.48 1,268.61 92.90 -77.02965.11 2,621,762.78 285,757.55 1.95 110.72 MWD (2) 1,307.31 10.36 305.00 1,299.53 96.15 -81.54996.03 2,621,766.03 285,753.03 1.24 116.23 MWD (2) 1,338.74 10.77 301.98 1,330.43 99.33 -86.351,026.93 2,621,769.21 285,748.23 2.19 121.95 MWD (2) 1,370.14 11.01 297.80 1,361.26 102.28 -91.491,057.76 2,621,772.16 285,743.09 2.63 127.87 MWD (2) 1,401.45 11.60 294.95 1,391.96 105.00 -96.991,088.46 2,621,774.89 285,737.59 2.59 134.01 MWD (2) 1,433.00 12.29 290.86 1,422.83 107.53 -103.001,119.33 2,621,777.42 285,731.57 3.46 140.52 MWD (2) 1,464.47 12.90 289.90 1,453.54 109.92 -109.431,150.04 2,621,779.81 285,725.14 2.05 147.33 MWD (2) 1,496.00 13.58 290.01 1,484.24 112.39 -116.221,180.74 2,621,782.27 285,718.35 2.16 154.50 MWD (2) 1,527.46 14.61 288.47 1,514.75 114.91 -123.461,211.25 2,621,784.79 285,711.12 3.48 162.09 MWD (2) 1,558.87 15.55 287.35 1,545.08 117.42 -131.231,241.58 2,621,787.30 285,703.34 3.13 170.16 MWD (2) 1,589.81 16.37 286.33 1,574.82 119.88 -139.381,271.32 2,621,789.77 285,695.20 2.80 178.54 MWD (2) 1,621.27 17.31 286.87 1,604.93 122.49 -148.111,301.43 2,621,792.37 285,686.47 3.03 187.51 MWD (2) 1,652.67 18.13 287.36 1,634.84 125.30 -157.241,331.34 2,621,795.18 285,677.34 2.65 196.92 MWD (2) 1,684.11 18.73 287.32 1,664.67 128.26 -166.731,361.17 2,621,798.15 285,667.85 1.91 206.72 MWD (2) 1,715.49 19.41 286.63 1,694.33 131.25 -176.541,390.83 2,621,801.14 285,658.04 2.28 216.82 MWD (2) 1,746.91 20.22 286.28 1,723.89 134.27 -186.751,420.39 2,621,804.15 285,647.83 2.61 227.30 MWD (2) 1,778.48 21.25 286.61 1,753.41 137.44 -197.471,449.91 2,621,807.32 285,637.11 3.28 238.29 MWD (2) 1,809.81 22.19 286.43 1,782.52 140.73 -208.591,479.02 2,621,810.61 285,625.99 3.01 249.69 MWD (2) 1,841.28 23.07 286.53 1,811.57 144.17 -220.201,508.07 2,621,814.05 285,614.38 2.80 261.60 MWD (2) 11/16/2011 9:48:44AM COMPASS 2003.16 Build 71 Page 3 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Three Mile Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: TMCU#3 TMCU#3 Survey Calculation Method:Minimum Curvature TMCU # 3 081611 @ 303.50ft (287.5 + 16) Design:TMCU #3 Database:.Sperry EDM .16 PRD MD Reference:TMCU # 3 081611 @ 303.50ft (287.5 + 16) North Reference: Well TMCU#3 Grid MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 1,872.67 23.45 285.81 1,840.40 147.62 -232.101,536.90 2,621,817.50 285,602.48 1.51 273.78 MWD (2) 1,903.94 23.61 286.09 1,869.07 151.05 -244.111,565.57 2,621,820.93 285,590.48 0.62 286.04 MWD (2) 1,935.28 23.39 286.15 1,897.82 154.52 -256.111,594.32 2,621,824.40 285,578.47 0.71 298.31 MWD (2) 1,966.66 23.33 286.37 1,926.62 158.00 -268.061,623.12 2,621,827.88 285,566.53 0.34 310.54 MWD (2) 1,998.13 23.34 285.56 1,955.52 161.43 -280.041,652.02 2,621,831.31 285,554.54 1.02 322.78 MWD (2) 2,029.52 23.45 285.81 1,984.33 164.80 -292.041,680.83 2,621,834.68 285,542.54 0.47 335.00 MWD (2) 2,060.95 23.35 286.17 2,013.17 168.24 -304.041,709.67 2,621,838.12 285,530.54 0.56 347.26 MWD (2) 2,092.43 23.30 286.09 2,042.08 171.70 -316.011,738.58 2,621,841.58 285,518.57 0.19 359.51 MWD (2) 2,123.89 23.28 286.21 2,070.98 175.16 -327.961,767.48 2,621,845.04 285,506.62 0.16 371.73 MWD (2) 2,155.26 23.20 285.44 2,099.80 178.54 -339.871,796.30 2,621,848.42 285,494.72 1.00 383.87 MWD (2) 2,186.64 23.12 285.71 2,128.65 181.85 -351.761,825.15 2,621,851.73 285,482.83 0.42 395.97 MWD (2) 2,217.98 23.20 285.05 2,157.47 185.12 -363.641,853.97 2,621,855.00 285,470.94 0.87 408.05 MWD (2) 2,249.22 23.91 284.94 2,186.10 188.35 -375.701,882.60 2,621,858.23 285,458.89 2.28 420.27 MWD (2) 2,280.63 24.80 285.09 2,214.72 191.71 -388.211,911.22 2,621,861.59 285,446.38 2.84 432.94 MWD (2) 2,312.17 25.71 284.84 2,243.24 195.18 -401.211,939.74 2,621,865.06 285,433.38 2.90 446.11 MWD (2) 2,343.56 26.62 284.94 2,271.42 198.74 -414.591,967.92 2,621,868.62 285,420.00 2.90 459.64 MWD (2) 2,375.00 27.40 284.82 2,299.43 202.40 -428.391,995.93 2,621,872.28 285,406.20 2.49 473.61 MWD (2) 2,406.42 28.05 284.36 2,327.24 206.09 -442.542,023.74 2,621,875.97 285,392.06 2.18 487.89 MWD (2) 2,437.85 28.27 284.35 2,354.95 209.76 -456.912,051.45 2,621,879.64 285,377.69 0.70 502.37 MWD (2) 2,469.24 28.34 284.55 2,382.59 213.48 -471.322,079.09 2,621,883.36 285,363.27 0.38 516.90 MWD (2) 2,500.41 28.75 283.78 2,409.97 217.12 -485.762,106.47 2,621,887.00 285,348.83 1.77 531.43 MWD (2) 2,531.84 29.31 283.78 2,437.45 220.75 -500.572,133.95 2,621,890.63 285,334.02 1.78 546.28 MWD (2) 2,563.24 29.17 283.80 2,464.85 224.41 -515.472,161.35 2,621,894.29 285,319.13 0.45 561.22 MWD (2) 2,594.69 29.15 284.08 2,492.31 228.10 -530.342,188.81 2,621,897.98 285,304.25 0.44 576.15 MWD (2) 2,626.05 29.17 284.85 2,519.70 231.92 -545.142,216.20 2,621,901.80 285,289.46 1.20 591.07 MWD (2) 2,657.52 29.00 283.80 2,547.20 235.70 -559.962,243.70 2,621,905.58 285,274.64 1.71 606.00 MWD (2) 2,689.00 28.68 285.55 2,574.78 239.55 -574.652,271.28 2,621,909.43 285,259.95 2.87 620.84 MWD (2) 2,720.42 28.58 286.17 2,602.35 243.66 -589.132,298.85 2,621,913.54 285,245.47 1.00 635.62 MWD (2) 2,751.77 28.51 286.99 2,629.89 247.94 -603.492,326.39 2,621,917.82 285,231.11 1.27 650.36 MWD (2) 2,783.09 28.40 286.93 2,657.43 252.29 -617.762,353.93 2,621,922.17 285,216.84 0.36 665.05 MWD (2) 2,814.56 28.33 286.26 2,685.12 256.56 -632.092,381.62 2,621,926.44 285,202.51 1.04 679.76 MWD (2) 2,845.86 28.41 286.79 2,712.66 260.79 -646.352,409.16 2,621,930.67 285,188.25 0.84 694.39 MWD (2) 2,877.27 28.08 288.79 2,740.33 265.33 -660.502,436.83 2,621,935.21 285,174.10 3.19 709.07 MWD (2) 2,908.71 28.04 290.33 2,768.08 270.28 -674.432,464.58 2,621,940.16 285,160.17 2.31 723.73 MWD (2) 2,940.17 27.79 291.53 2,795.88 275.54 -688.192,492.38 2,621,945.42 285,146.41 1.95 738.38 MWD (2) 2,971.60 27.53 291.78 2,823.71 280.93 -701.752,520.21 2,621,950.80 285,132.85 0.91 752.91 MWD (2) 3,002.98 27.77 291.72 2,851.51 286.32 -715.282,548.01 2,621,956.20 285,119.33 0.77 767.41 MWD (2) 3,034.44 27.83 292.12 2,879.34 291.80 -728.892,575.84 2,621,961.68 285,105.72 0.62 782.03 MWD (2) 3,065.88 27.82 291.72 2,907.15 297.28 -742.502,603.65 2,621,967.15 285,092.10 0.59 796.65 MWD (2) 3,097.27 27.74 291.86 2,934.92 302.71 -756.092,631.42 2,621,972.58 285,078.52 0.33 811.22 MWD (2) 11/16/2011 9:48:44AM COMPASS 2003.16 Build 71 Page 4 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Three Mile Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: TMCU#3 TMCU#3 Survey Calculation Method:Minimum Curvature TMCU # 3 081611 @ 303.50ft (287.5 + 16) Design:TMCU #3 Database:.Sperry EDM .16 PRD MD Reference:TMCU # 3 081611 @ 303.50ft (287.5 + 16) North Reference: Well TMCU#3 Grid MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 3,128.73 27.48 291.45 2,962.79 308.09 -769.642,659.29 2,621,977.96 285,064.97 1.02 825.74 MWD (2) 3,160.16 27.41 291.92 2,990.69 313.44 -783.102,687.19 2,621,983.32 285,051.51 0.72 840.17 MWD (2) 3,191.66 27.35 292.14 3,018.66 318.88 -796.532,715.16 2,621,988.75 285,038.08 0.37 854.60 MWD (2) 3,223.09 27.09 291.76 3,046.61 324.25 -809.862,743.11 2,621,994.12 285,024.75 1.00 868.92 MWD (2) 3,254.55 27.15 291.58 3,074.61 329.55 -823.192,771.11 2,621,999.42 285,011.42 0.32 883.20 MWD (2) 3,285.83 26.87 292.22 3,102.48 334.84 -836.372,798.98 2,622,004.72 284,998.24 1.29 897.36 MWD (2) 3,317.34 26.75 292.01 3,130.60 340.19 -849.542,827.10 2,622,010.07 284,985.07 0.49 911.52 MWD (2) 3,348.73 26.79 291.63 3,158.63 345.45 -862.662,855.13 2,622,015.32 284,971.95 0.56 925.60 MWD (2) 3,380.14 26.82 291.97 3,186.66 350.71 -875.812,883.16 2,622,020.58 284,958.80 0.50 939.71 MWD (2) 3,411.58 26.83 292.43 3,214.72 356.07 -888.952,911.22 2,622,025.94 284,945.66 0.66 953.85 MWD (2) 3,443.05 27.28 292.49 3,242.74 361.54 -902.182,939.24 2,622,031.41 284,932.44 1.43 968.12 MWD (2) 3,474.57 27.21 292.89 3,270.77 367.10 -915.492,967.27 2,622,036.98 284,919.12 0.62 982.51 MWD (2) 3,506.00 27.27 293.14 3,298.71 372.73 -928.732,995.21 2,622,042.60 284,905.88 0.41 996.86 MWD (2) 3,537.47 27.49 292.88 3,326.66 378.39 -942.053,023.16 2,622,048.26 284,892.56 0.80 1,011.30 MWD (2) 3,568.84 27.21 292.73 3,354.52 383.97 -955.343,051.02 2,622,053.84 284,879.28 0.92 1,025.68 MWD (2) 3,600.34 27.26 292.93 3,382.53 389.57 -968.623,079.03 2,622,059.44 284,865.99 0.33 1,040.06 MWD (2) 3,631.74 27.31 293.75 3,410.43 395.27 -981.843,106.93 2,622,065.14 284,852.78 1.21 1,054.42 MWD (2) 3,663.12 27.17 293.80 3,438.33 401.06 -994.983,134.83 2,622,070.93 284,839.63 0.45 1,068.76 MWD (2) 3,694.52 26.98 293.37 3,466.29 406.78 -1,008.083,162.79 2,622,076.65 284,826.54 0.87 1,083.03 MWD (2) 3,725.95 27.08 293.71 3,494.29 412.48 -1,021.183,190.79 2,622,082.35 284,813.44 0.59 1,097.29 MWD (2) 3,757.37 27.25 293.78 3,522.24 418.26 -1,034.313,218.74 2,622,088.13 284,800.31 0.55 1,111.61 MWD (2) 3,788.90 27.99 293.89 3,550.18 424.17 -1,047.683,246.68 2,622,094.04 284,786.94 2.35 1,126.21 MWD (2) 3,820.31 28.31 294.13 3,577.87 430.20 -1,061.213,274.37 2,622,100.06 284,773.41 1.08 1,141.01 MWD (2) 3,851.76 28.14 293.82 3,605.59 436.24 -1,074.813,302.09 2,622,106.11 284,759.82 0.71 1,155.86 MWD (2) 3,883.19 27.96 294.01 3,633.32 442.23 -1,088.323,329.82 2,622,112.10 284,746.31 0.64 1,170.62 MWD (2) 3,914.64 27.98 293.65 3,661.10 448.19 -1,101.813,357.60 2,622,118.06 284,732.81 0.54 1,185.35 MWD (2) 3,946.08 28.07 294.28 3,688.85 454.19 -1,115.313,385.35 2,622,124.06 284,719.32 0.98 1,200.11 MWD (2) 3,977.52 27.99 293.56 3,716.61 460.18 -1,128.813,413.11 2,622,130.05 284,705.81 1.11 1,214.86 MWD (2) 4,008.93 28.03 293.89 3,744.34 466.12 -1,142.323,440.84 2,622,135.98 284,692.31 0.51 1,229.59 MWD (2) 4,040.43 28.02 294.24 3,772.14 472.15 -1,155.833,468.64 2,622,142.02 284,678.79 0.52 1,244.37 MWD (2) 4,071.84 27.93 294.27 3,799.88 478.20 -1,169.263,496.38 2,622,148.07 284,665.36 0.29 1,259.09 MWD (2) 4,103.29 27.75 294.62 3,827.69 484.28 -1,182.643,524.19 2,622,154.15 284,651.99 0.77 1,273.76 MWD (2) 4,134.76 27.66 294.64 3,855.55 490.38 -1,195.943,552.05 2,622,160.25 284,638.69 0.29 1,288.38 MWD (2) 4,166.21 27.67 293.98 3,883.41 496.39 -1,209.243,579.91 2,622,166.26 284,625.39 0.97 1,302.97 MWD (2) 4,197.65 27.73 294.17 3,911.25 502.35 -1,222.593,607.75 2,622,172.22 284,612.04 0.34 1,317.57 MWD (2) 4,228.99 27.80 294.56 3,938.98 508.38 -1,235.883,635.48 2,622,178.24 284,598.74 0.62 1,332.15 MWD (2) 4,260.50 27.74 294.96 3,966.86 514.52 -1,249.223,663.36 2,622,184.39 284,585.41 0.62 1,346.82 MWD (2) 4,291.92 27.72 294.36 3,994.67 520.62 -1,262.503,691.17 2,622,190.49 284,572.13 0.89 1,361.43 MWD (2) 4,323.44 27.36 293.98 4,022.62 526.59 -1,275.803,719.12 2,622,196.46 284,558.83 1.27 1,375.99 MWD (2) 4,354.83 27.25 293.61 4,050.51 532.40 -1,288.973,747.01 2,622,202.27 284,545.66 0.64 1,390.37 MWD (2) 11/16/2011 9:48:44AM COMPASS 2003.16 Build 71 Page 5 Project: Company: Local Co-ordinate Reference: TVD Reference: Site: Aurora Gas, LLC Cook Inlet Three Mile Creek Unit Halliburton Company Definitive Survey Report Well: Wellbore: TMCU#3 TMCU#3 Survey Calculation Method:Minimum Curvature TMCU # 3 081611 @ 303.50ft (287.5 + 16) Design:TMCU #3 Database:.Sperry EDM .16 PRD MD Reference:TMCU # 3 081611 @ 303.50ft (287.5 + 16) North Reference: Well TMCU#3 Grid MD (ft) Inc (°) Azi (°) +E/-W (ft) +N/-S (ft) Survey TVD (ft) TVDSS (ft) Map Northing (ft) Map Easting (ft) Vertical Section (ft) DLS (°/100')Survey Tool Name 4,386.27 27.21 294.27 4,078.47 538.24 -1,302.123,774.97 2,622,208.10 284,532.51 0.97 1,404.73 MWD (2) 4,417.82 27.27 294.51 4,106.52 544.20 -1,315.273,803.02 2,622,214.07 284,519.36 0.40 1,419.16 MWD (2) 4,449.31 27.10 294.47 4,134.53 550.17 -1,328.373,831.03 2,622,220.03 284,506.27 0.54 1,433.53 MWD (2) 4,480.73 26.90 294.50 4,162.52 556.08 -1,341.353,859.02 2,622,225.94 284,493.29 0.64 1,447.78 MWD (2) 4,512.19 26.83 294.64 4,190.59 561.99 -1,354.283,887.09 2,622,231.85 284,480.36 0.30 1,461.99 MWD (2) 4,543.62 26.87 294.25 4,218.63 567.86 -1,367.203,915.13 2,622,237.73 284,467.43 0.57 1,476.17 MWD (2) 4,574.89 26.89 295.29 4,246.52 573.79 -1,380.043,943.02 2,622,243.65 284,454.60 1.51 1,490.30 MWD (2) 4,606.37 26.86 295.04 4,274.60 579.84 -1,392.923,971.10 2,622,249.70 284,441.72 0.37 1,504.52 MWD (2) 4,637.83 26.87 293.66 4,302.67 585.70 -1,405.873,999.17 2,622,255.56 284,428.77 1.98 1,518.72 MWD (2) 4,669.79 26.79 293.06 4,331.19 591.42 -1,419.114,027.69 2,622,261.28 284,415.53 0.88 1,533.12 MWD (2) 4,700.71 26.63 293.60 4,358.81 596.92 -1,431.874,055.31 2,622,266.78 284,402.77 0.94 1,546.99 MWD (2) 4,732.16 26.49 293.95 4,386.94 602.59 -1,444.744,083.44 2,622,272.45 284,389.90 0.67 1,561.03 MWD (2) 4,763.59 26.25 293.92 4,415.10 608.25 -1,457.504,111.60 2,622,278.12 284,377.14 0.76 1,574.97 MWD (2) 4,795.01 26.15 294.15 4,443.29 613.90 -1,470.174,139.79 2,622,283.77 284,364.47 0.45 1,588.83 MWD (2) 4,826.46 26.09 294.82 4,471.53 619.64 -1,482.774,168.03 2,622,289.50 284,351.87 0.96 1,602.66 MWD (2) 4,857.87 26.14 294.60 4,499.73 625.42 -1,495.334,196.23 2,622,295.28 284,339.31 0.35 1,616.48 MWD (2) 4,889.29 26.15 294.92 4,527.94 631.22 -1,507.904,224.44 2,622,301.08 284,326.74 0.45 1,630.31 MWD (2) 4,920.77 26.02 294.50 4,556.21 637.01 -1,520.484,252.71 2,622,306.87 284,314.17 0.72 1,644.15 MWD (2) 4,952.23 25.93 295.04 4,584.49 642.78 -1,532.994,280.99 2,622,312.64 284,301.66 0.80 1,657.91 MWD (2) 4,983.50 25.79 295.04 4,612.63 648.55 -1,545.354,309.13 2,622,318.41 284,289.30 0.45 1,671.55 MWD (2) 5,014.97 25.75 294.89 4,640.97 654.33 -1,557.754,337.47 2,622,324.19 284,276.90 0.24 1,685.22 MWD (2) 5,046.46 25.78 295.44 4,669.33 660.15 -1,570.144,365.83 2,622,330.01 284,264.51 0.77 1,698.90 MWD (2) 5,142.00 25.78 295.44 4,755.36 678.00 -1,607.664,451.86 2,622,347.85 284,226.99 0.00 1,740.44 PROJECTED to TD 11/16/2011 9:48:44AM COMPASS 2003.16 Build 71 Page 6 0 1000 2000 DepthThree Mile Creek #3 SDL Crew Arrived Set 9 5/8" Casing 8850', 660' TVD LOT to 16.2 ppg EMW End of Run 300 Drill to 3009, POOH for Bit Trip 10/11/2011 @ 17:30 TD 12 1/4" Surface Hole 900' MD, 897' TVD Begin Drilling 12 1/4" Section Start Run 300 Begin 8 1/2" Section Failed Casing Test , POOH Begin Drilling 8 1/2" Section 7 Oct 2011 @ 13:46 Start Run 400 10/13/2011 @ 06:40 3000 4000 5000 6000 0 102030405060Measured DRig Days Run E-Logs TD Well 5142' MD, 4755.44' TVD On 10:01 , 18-Oct-2011 CBU, Short Trip to shoe Run 5 1/2" production liner.and cement Off Location11/2/2011 On 10/20/2011 @ 11:42 Drill extra 15' for Casing. From 5142' MD to 5157' MD POOH, R/U and Run E-LogsLogs. No go, Pull Out and RIH to clean hole. Surface Data Logging After Action Review Employee Name: Mark Lindloff Date: 11/3/2011 Well: TMC #3 Hole Section: Production What went as, or better than, planned: Three Mile Creek Unit 3 went very well for the mudloggers. Phone communications was 100% better making it easier to contact resources and resolve issues as they arose. Difficulties experienced: None. Recommendations: Maybe put some thought on how we can track depth better. Innovations and/or cost savings: Saved Aurora thousands of dollars by providing rig monitor service therefore Aurora did not have to purchase a stand alone monitoring system.
