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214-094
'2 / LI, 6)�Z Davies, Stephen F (DOA) From: Luke Keller <Ikeller@hilcorp.com> Sent: Friday, November 07, 2014 11:18 AM To: Schwartz, Guy L (DOA); Davies, Stephen F (DOA) Cc: Luke Saugier; David Duffy; Chad Helgeson; David Buthman; Jeff Allen; Kate Kaufman; Larry Greenstein Subject: Paxton #6 and Frances #2 PTD & Spacing Exception Cancellation G uy/Steve, Hilcorp Alaska, LLC would like to cancel the Drilling and Spacing Exception permit applications for Paxton #6 and Frances #2. My records indicate Frances #2 was approved July 21st, 2014. We do not intend to drill either of these wells in the next 12 months and want to avoid the AOGCC wasting any additional resources on these requests. Please contact me if you have any questions about this. Thank you, Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 THE STATE O GOVERNOR SEAN PARNKI. Luke Keller Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 AJF. 11'r C �� I� !{� -s- Ali 'ate .-a.2;!' .,a- �.d ta1L gar J. Id[x .T1 a- 333 west Sevenih Avenue Anchoraae, Alaska 99501-3572 Main: 907.279.1 A33 90727! 7542 Re: Ninilchik Field, Undefined Tyonek and Undefined Beluga Gas Pools, Frances #2 Hilcorp Alaska, LLC Permit No: 214-094 Surface Location: 2689' FEL, 244' FNL, SEC. 7, TIN, R12W, SM, AK Bottomhole Location: 1828' FNL, 2403' FEL, SEC. 6, TIN, R12W, SM, AK Dear Mr. Keller: Enclosed is the approved application for permit to drill the above referenced development well. The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce is contingent upon issuance of a conservation order approving a spacing exception. Hilcorp Alaska, LLC assumes the liability of any protest to the spacing exception that may occur. 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 AOGCC 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 AOGCC 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 AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, 4CathyFoerster Chair S DATED this 2 day of July, 2014. STATE OF ALASKA Mr-%;t1Vr.0 )N JUN 2 7 2014 :A OIL AND GAS CONSERVATION COMM PERMIT TO DRILL 20 AAC 25.005 .1 .-• y 0, 1 a. Type of Work: 1 b. Proposed Well Class: Development -Oil ❑ Service - Winj ❑ Single Zone ❑ 1 c. Specify if well is proposed for: Drill Q . Lateral ❑ Stratigraphic Test ❑ Development - Gas 0 Service - Supply ❑ Multiple Zone Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory ❑ Service - WAG ❑ Service - Disp ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket ❑ Single Well ❑ 11. Well Name and Number: Hilcorp Alaska, LLC Bond No. _0223524T t�27 T�" 2 �/ , ' L7 Frances #2 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3800 Centerpoint Drive Ste 1400 Anchorage, AK 99503 MD: 9,242' TVD: 8 260' Ninilchik Undefined Tyonek Gas Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 2689' FEL, 244' FNL, Sec 7, T1 N, R12W, SM, AK Well path crosses approx. 8 private leases with(n Undefined Beluga Gas Pool Ninilchik Unit. Xt> .3' l 7 7 8. Land Use Permit: 101 13. Approximate Spud Date: Top of Productive Horizon: 672' FSL, 2604' FEL, Sec 6, T1 N, R12W, SM, AK N/A -7 ' i /�/ 10/15/2014 9. Acres in Propertv: (varies by lease) 14. Distance to Nearest Property: Total Depth: 1828' FNL, 2403' FEL, Sec 6, TIN, R12W, SM, AK The eight (8) private leases range in size from 0.91 -50' at TPI acres to 103 acres. Average size equals 30. 6 acres. Average = 30 acres 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL: 268.4 feet 15. Distance to Nearest Well Open Surface: x- 240097 y- 2267313 Zone- 4 GL Elevation above MSL: 249 feet to Same Pool: 2,228' 16. Deviated wells: Kickoff depth: 1,450 feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035)7 7 Maximum Hole Angle: 30.46 degrees Downhole: 3585 psi Surface: Jfa7_5� i (Drilling) Y'( 7 S r 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling I Length MD TVD MD TVD (including stage data) Cond 16" 109 X-56 Weld 80' Surface Surface 80' 80, Driven 12-1/4" 9-5/8" 40 L-80 BTC 3,600' Surface Surface 3,600' 3396.29' 313.4bbl / 1761ft3 8-1/2" 5-1/2" 17 P-110 DWC HT 9,242' Surface Surface 9,242' 8,260' 324bbl / 1820ft3 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 Q BOP Sketch Q Drilling Program Q Time v. Depth Plot Q Shallow Hazard Analysis❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program Q 20 AAC 25.050 requirements0 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and correct. Contact Luke Keller Email Ikeller(aDhilcorp.com Printed Name Luke Ke ler Title Drilling Engineer Signature Phone 907-777-8395 Date 6/27/2014 Commission Use Only Permit to Drill /��Number: `�° `y .� j i _f;{Le lZ ` Permit Approval See cover letter for other Number: t7 i 50 c 1� E Date: �I ' requirements. Conditions of approval : If box is checked well may now used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: n /�5 Other: 3jD0 �Sr � Samples req'd: Yes ❑ No [k", Mud log req'd: Yes ❑ Noy L�, 3• t.cl'itUeY H2S measures: Yes ❑ No Directional svy req'd: Yes© No❑ r �' S r .� r � � ( eg (t)z-v-4. D� 0 )jng exception req'd: Yes No❑ Inclination -only svy req'd: Yes ❑ Nov APPROVED BY Approved byX � Q9�,L� C M ISSIONER THE COMMISSION Date: - L4 .4, r) Form16-401 (Rkvised 10/ 12) This er fl t "1)o� 2 lIf o�jsprom the date of approval (20 AAC 25.005(g)) Attachments in Duplicate ' ll �� 7 r7-i�� V 1 1 jwj7�7�1�1 - - s 7. 17. /cl Hilcorp Energy company June 25, 2014 Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 Re: Frances #2 Dear Commissioner, Luke Keller Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8395 Email Ikeller@hilcorp.com Enclosed for review and approval is the application for the Permit to Drill the Frances #2 well. Frances #2 is a is a northern appraisal well of the Falls Creek Pool structural closure, targeting the Tyonek T- 50 through T-65, and collecting data for a frac job in the T-10 and T-8 reservoirs found in the Falls Creek #5 well. The base plan is a build and hold wellbore, with a kick-off point at 1450' MD, and reaching a maximum angle of 30.46 deg. Drilling operations are expected to commence approximately Oct 15th, 2014. The Saxon Rig # 147 will be used to drill the well and run the 5-1/2" long string. Pursuant to 20 AAC 25.055 (a) 2 & 4: A spacing exception is required to test and produce this well and will be filed under separate cover. If you have any questions, please don't hesitate to contact myself at 777-8389 or Paul Mazzolini at 777-8369. Sincerely, 14-1.1 Luke Keller Drilling Engineer /ZCL Hilcorp Alaska, LLC Page i of i Hilcorp Alaska, LLC Frances #2 Drilling & Completion Program Version 1 June 18th, 2014 Hilcorp Energy Company Contents Frances #2 Drilling Procedure 1.0 Well Summary.................................................................................................................................2 2.0 Management of Change Information............................................................................................3 3.0 Tubular Program: ........................................................................................................................... 4 4.0 Drill Pipe Information: ................................................................................................................... 4 5.0 Internal Reporting Requirements..................................................................................................5 6.0 Planned Wellbore Schematic..........................................................................................................6 7.0 Drilling / Completion Summary.....................................................................................................7 8.0 Mandatory Regulatory Compliance / Notifications.....................................................................8 9.0 R/U and Preparatory Work.........................................................................................................10 10.0 N/U 21-1/4" 2M Diverter..............................................................................................................11 11.0 Drill 12-1/4" Hole Section.............................................................................................................12 12.0 Run 9-5/8" Surface Casing...........................................................................................................16 13.0 Cement 9-5/8" Surface Casing.....................................................................................................19 14.0 BOP N/U and Test.........................................................................................................................22 15.0 Drill 8-1/2" Hole Section...............................................................................................................23 16.0 Run 5-1/2" Production Casing.....................................................................................................28 17.0 Cement 5-1/2" Production Casing...............................................................................................31 18.0 RDMO............................................................................................................................................34 19.0 Perf and Frac.................................................................................................................................34 20.0 BOP Schematic..............................................................................................................................35 21.0 Wellhead Schematic......................................................................................................................36 22.0 Days Vs Depth...............................................................................................................................37 23.0 Formation Tops.............................................................................................................................38 24.0 Anticipated Drilling Hazards.......................................................................................................39 25.0 Saxon Rig 147 Layout...................................................................................................................41 26.0 FIT Procedure...............................................................................................................................42 27.0 Choke Manifold Schematic..........................................................................................................43 28.0 Casing Design Information...........................................................................................................44 29.0 8-1/2" Hole Section MASP............................................................................................................45 30.0 Spider Plot (NAD 27) (Governmental Sections).........................................................................46 31.0 Surface Plat (As Staked) (NAD 27)..............................................................................................47 32.0 Offset MW vs TVD Chart............................................................................................................48 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 1.0 Well Summary Well Frances #2 Pad Bartolowits Pad Planned Completion Tye 2-7/8" prod tubing inside 5-1/2" production casing Target Reservoir(s) Beluga 50, Beluga 135, Tyonek, T-8, T-10, T-50, T-60, T-65 Planned Well TD, MD / TVD 9,242' MD / 8,260' TVD PBTD, MD / TVD 9,100' MD / 8,137' TVD Surface Location (Governmental) 244' FNL, 2689' FEL, Sec 7, TIN, R12W, SM, AK Surface Location (NAD 27) X=240097, Y=2267313 Surface Location (NAD 83) Top of Productive Horizon (Governmental) 672' FSL, 2604' FEL, Sec 6, TIN, R12W, SM, AK TPH Location (NAD 27) X=240180, Y=2268221 TPH Location (NAD 83 ) BHL (Governmental) 1828' FNL, 2403' FEL, Sec 6, TIN, R12W, SM, AK BHL (NAD 27) X=240434, Y=2270996 BHL (NAD 83) AFE Number 1412170 AFE Drilling Days 32 AFE Completion Days AFE Drilling Amount $5,550.488 AFE Completion Amount Maximum Anticipated Pressure (Surface) 1675 psi (Drilling) Maximum Anticipated Pressure (Downhole/Reservoir) 3585 psi Work String 4-1/2" 16.6# S-135 CDS-40 KB Elevation above MSL: 249.8' + 18.6' = 268.4' GL Elevation above MSL: 249.8' NAVD88 BOP Equipment 11" 5M T3-Energy Annular BOP 11" 5M T3-Energy Double Ram 11" 5M T3-Energy Single Ram Page 2 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hileorp Energy Company 2.0 Management of Change Information Hileorp Alaska, LLC Hilcarp F;nc�p Coaxpw,T Changes to ApprovedFennit to Drill Date: Subject: Changes to Approved Permit to Drill for Frances #2 File #: Frances #2 Drilling and Completion Program Any modifications to Drilling & Completion Program will be documented and approved below_ Changes to an approved APD will be ¢��Jthe ADGCC_ / L��•-::. €ham.. cL...u- !�� z.a2r,1_ �-( Date Procedure Change Approved DY Approved BY Approval: Drilling Manager Prepared: Drilling Engineer Page 3 Version 2 Date Date June, 2014 N Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 3.0 Tubular Program: Hole Section OD (in) ID (in) Drift (in) Conn OD in Wt #/ft(psi), Grade Conn Burst Collapse (psi) Tensio Cond 16" 15" - - 109 X-56 Weld 12-1/4" 9-5/8" 8.835" 8.75" 10.625" 40 L-80 BTC 57507 3090 916 8-1/2" 5-1/2" 4.892" 4.767" 6.05" 17 P-110 DwC HT 7740 6290 397 4.0 Drill Pipe Information: Hole Section 01) (in) ID (in) TJ ID in TJ OD in Wt #/f Grade Conn Burst si. Co All 4.5" 3.826 2.6875" 5.25" 16.6 S-135 CDS40 17,693 16,769 468k All casing will be new, PSL 1 (100% mill inspected, 10% inspection upon delivery to TSA in Fairbanks). Page 4 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 5.0 Internal Reporting Requirements 5.1 Fill out daily drilling report and cost report on Wellez. • Report covers operations from 6am to Gam • Click on one of the tabs at the top to save data entered. If you click on one of the tabs to the left of the data entry area — this will not save the data entered, and will navigate to another data entry tab. • Ensure time entry adds up to 24 hours total. • Try to capture any out of scope work as NPT. This helps later on when we pull end of well reports. 5.2 Afternoon Updates • Submit a short operations update each work day to pmazzolini@hilcorp.com , lkeller@hilcorp.com and jbarrett@hilcorp.com 5.3 Intranet Home Page Morning Update • Submit a short operations update each morning by lam on the company intranet homepage. On weekend and holidays, ensure to have this update in before 5am. Each rig will be assigned a usemame to login with. 5.4 EHS Incident Reporting • Notify EHS field coordinator. 1. This could be one of (3) individuals as they rotate around. Know who your EHS field coordinator is at all times, don't wait until an emergency to have to call around and figure it out!!!! a. John Coston: 0: (907) 777-6726 C: (907) 227-3189 b. Mark Tornai: 0: (907) 283-1372 C: (907) 748-3299 c. Thad Eby: 0: (907) 777-8317 C: (907) 602-5178 2. Spills: Kate Kaufman: 0:907-777-8329 C:907-244-8292 • Notify Drlg Manager 1. Paul Mazzolini: 0: 907-777-8369 C: 907-317-1275 • Submit Hilcorp Incident report to contacts above within 24 hrs 5.5 Casing Tally • Send final "As -Run" Casing tally to lkeller@hilcorp.com and jbarrettghilcorp.com 5.6 Casing and Cmt report • Send casing and cement report for each string of casing to Ikeller@hilcorp.com and jbarrett@hi1corp.com Page 5 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 6.0 Planned Wellbore Schematic i HcIe 2 4 , t ' f (s I t , s t � cc• �. FBTD = 9,140' ;SID 18,13T T17D TD = 9,242' AID i V60' TTD MA", of z flf-m Mud Type Grade Conn. ID Top Ptrn Weight Conductnf — Ir DriuentoSet 1o9 X-55 "Weld Ir Surf Bo' Depth 9-5/8` 5urf. C59 40 L-W I 8iC 8.Wr Surf °.fro' 8.8 ppg 5-1/2` Prod casing 17 L-SD C 4.882" Surf 9,242' 9•5 ppg TUBING 2-7a B" 1 Production 6.4 1 L-W I I BT 1 2.441" 1 Surf — TOC 8t 3100' t Drilling Info Wf Hale Section Casing h.'t4%rrrk;t[iog 12-11C 9-SJE" 8 8 ppg .41,f2F JEWELRY DETAIL No_ Depth ID OD Itern 1 150, SCSSV _ 25M cim 3500 Prod Pkr 3520 Wirelinere-entryguide Planned Reservoir Objectives Zcne Top (PAD) Btm '— '= Est Pressure EMW Gradient Beluga-50 3776 3,503 L506 B.3 0.43 Beluga 135 5427 5,033 2164 8.3 0.43 Typno 5571 5,2w 2262 8.3 0.43 T-8 6502 6,031 2593 8.3 0.43 T-10 67M 8,277 2599 8.3 0.43 T-50 8271 7,573 3256 B_3 0.43 T-0 8491 7,T52 3338 6.3 0.43 T-65 B953 8,161 3509 B.3 0.43 Page 6 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 7.0 Drilling / Completion Summary Frances #2 is a is a northern appraisal well of the Falls Creek Pool structural closure, targetingthe he Tyonek T- 50 through T-65, and collecting data for a frac job in the T-10 and T-8 reservoirs found in the Falls Creek #5 well. The base plan is a build and hold wellbore, with a kick-off point at 1450' MD, and reaching a maximum angle of 30.46 deg. Drilling operations are expected to commence approximately Oct 15�' m, 2014. The Saxon Rig # 147 will be used to drill the well and run the 5-1/2" long string. All known potential fresh water zones exist above 200'. This information is based off salinity calculations of neighboring water wells. Chlorides are 1100 ppm at the 171 — 194' sand, 1800 ppm at the 505 — 535' sand, and 6000 ppm at the 1040' sand. Furthermore, the TGAS (total gas) curve from offset mud logs begins registering shallow gas at depths just below the sandstone bed at 200'. Surface casing will be run to 3,600' MD / 3,396' TVD and cemented to surface to ensure protection of these resources. Cement returns to surface will confirm TOC at surface. If cmt returns to surface are not observed, a Temp log will be run between 6 — 18 hrs after CIP to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. j All waste & mud generated during drilling and completion operations will be hauled to the Kenai Gas Field G&I facility for disposal / beneficial reuse depending on test results. General sequence of operations: 1. MOB Saxon Rig # 147 to well site 2. N/U 21-1/4" x 2M conductor riser. 3. Drill 12-1/4" hole to 3600' MD. Run and cmt 9-5/8" surface casing. 4. N/D diverter, N/U & test 11" x 5M T3-Energy BOP. 5. Drill 8-1/2" hole section to 9,242' MD. Run wireline logs. Run and cmt 5-1/2" production casing. 6. N/D BOP, N/U temp abandonment cap, RDMO. Reservoir Evaluation Plan: 1. Surface hole: None planned. 2. Production Hole: GR + Res + Den/Neu (Triple Combo). Open hole wireline logging — Dipole sonic and (25) rotary sidewall cores. 3. Mud loggers from surface casing point to TD. Page 7 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 8.0 Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. • BOPs shall be tested at (2) week intervals during the drilling and completion of Frances #2 Ensure to provide AOGCC 24 hrs notice prior to testing BOPS. q)t; • The initial test of BOP equipment will be to 250/3000 psi & subsequent tests of the BOP equipment will be to 250/ i for 5/5 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent t III. Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements" • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: A diverter waiver is requested due to the recent drilling of Frances #1 on the same pad, and Falls creek #5 nearby (2185'). No issues were experienced on either well drilling the surface or intermediate hole sections. ��r11`o 1) If,I )� % 1Y Page 8 Version 2 June, 2014 Hilcorp Energy Company Frances #2 Drilling & Completion Procedure Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 12-1/4" • None planned N/A • I I" x 5M T3-Energy (Model 7082) Annular BOP 3 �� • 11" x 5M T3-Energy Double Ram Initial Test: 250/3808' o Blind ram in btm cavity (Annular 2500 psi) • Mud cross 8-1/2" • 11" x 5M T-3 Energy Single Ram • 3-1/8" 5M Choke Line Subsequent Tests: • 2-1/16" x 5M Kill line 250/3W 3y�" 3-1/8" x 2-1/16" 5M Choke manifold (Annular 2500 psi) • Standpipe, floor valves, etc • Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: • Well control event (BOPs utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPS. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (0): 907-793-1236 / Email: jim.regg@alaska.gov Guy Schwartz / Petroleum Engineer / (0): 907-793-1226 / (C): 907-301-4533 / Email: guy.schwartz@alaska.gov Victoria Ferguson / Petroleum Engineer / (0): 907-793-1247 / Email: Victoria.fer uson@alaska.g_ov Primary Contact for Opportunity to witness: AOGCC.InspectorsAalaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification / Emergency Phone: 907-793-1236 (During normal Business Hours) Notification / Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 9.0 R/U and Preparatory Work 9.1 Set 16" conductor at 60' below ground level. 9.2 Dig out and set impermeable cellar. 9.3 Install Seaboard slip-on 16-3/4" 3M "A" section. Ensure to orient wellhead so that tree will line up with flowline later. 9.4 Level pad and ensure enough room for layout of rig footprint and R/U. 9.5 Layout Herculite on pad to extend beyond footprint of rig. 9.6 R/U Saxon Rig # 147, spot service company shacks, spot & R/U company man & toolpusher offices. 9.7 Mud loggers are NOT required on the surface hole section. 9.8 After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 9.9 Mix mud for 12-1/4" hole section. 9.10 Set test plug in wellhead prior to N/U conductor riser to ensure nothing can fall into the wellbore if it is accidentally dropped. 9.11 Install 5-1/2" liners in mud pumps. • TSM 1000 mud pumps are rated at 3633 psi (85%) / 333 gpm (100%) with 5-1/2" liners. Page 10 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure 10.0 NX 21-1/4" 2M Diverter 10.1 N/U 16-3/4" Conductor Riser -I— D r'vt-r4/c:,, • Ensure line does not direct flow from trip tank straight down the flowline. Fill up line and flowline should be oriented 90 degrees to each other at approx. the same height. • Ensure flowline outlet installed so that enough slope exists to carry cuttings to the shakers. • Consider adding additional drainage points at the bottom of the conductor riser if deemed necessary. • RX fill up line to conductor riser. 10.2 Set 15.375" ID wearbushing in wellhead. 10.3 Rig Orientation on Frances pad: — _ -- .54 _ _ —�� —WATER WELL ` — —�--- 39.7— ti`t� 1 i_ it FR8!•10ES #2— 4 11t WELL } I ti I t I � II r y m I —TOP OF 18" `FR KES #1 ll�l I CONTAINMENT E, VrELL I � 1 ELSE OF I I S"� LE3AELE PAD ff:19 n 1! y� I 1V3 X 3" FLOWLINES UNDEP. GROUND (FUTURE) I Page 11 Version 2 June, 2014 Frances #2 Drilling &Completion Procedure Hilcorp Energy Cornpeny 11.0 Drill 12-1/4" Hole Section 11.1 P/U 12-1/4" directional drilling assy: • Ensure BHA components have been inspected previously. • Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. • Ensure TF offset is measured accurately and entered correctly into the MWD software. • Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. • Workstring will be 4.5" 16.6# S-135 CDS40. 11.2 12-1 /4" BHA: COMPONENT 1 DATA Description HDBS FX56rA POC ♦f 12200 to 2.750 Gauge 12.250 Weight 378.15 Top B 6-518' REG Length 1.00 Cumulative 1.00 2 8" SperryDrdl Lobe 415 - 5.3 stg 8.00D 5.000 121.08 B 6-5l8' REG 28.99 29.99 Stabilizer 11.5DD 3 Non Mag Stabilizer 8.000 2.813 12.125 150.12 8 6-W REG 6.00 35.99 4 8' DM Colter (Directional) 8.000 3.5DD 147.40 B &SIB' REG 9.20 45.19 5 8" TM - HOC (putser) 8.150 4.00D 145.20 B 6-5f8- REG 15.77 60.96 6 Non Mag Flex Drill Collar 8.000 3.000 147.22 B 6-518- REG 30.00 90.96 7 Non Mag Flex Drill Collar 8.000 3.00D 14722 B 6-5t8' REG 30.00 120.98 8 X-O 6-518 Reg Pin X 4-112" IF Box 8.000 2.813 150.12 B 4-I r IF 3.50 124.46 9 6-314" Non Mag Flex Drill Collar 6.750 2.750 101.71 B 4-112" IF 30.00 154.46 10 5-314' Non Mag Flex Drill Collar 6.750 2.750 101.71 B 4-Irr IF 30.00 184A6 11 X-0 4-112" IF Pin X 4-112" COS 40 Box 6.500 2.750 B 4.5" CDs 40 2.75 187.21 12 6 joints 4-112" COS 40 HWDP 4.500 2.50D 180.0D 367.21 13 X-0 4-112' COS 40 Pin X 4-1/2" IF Box 6.500 2.75D J37A7 B 4-1a' IF 2.75 369.95 14 Weatherford 6-114' Hyd Jar 6.250 2.25D B 4-112 IF 30.00 399.96 15 X-0 4-112" IF Pin X 4-112' COS 40 Box 6.500 2.75D B 4.5' COS 40 2.75 402.71 16 19 Joints 4-1/2' COS 40 HWDP 4.500 2.500 570.OD 972.71 972.71 Bit Number Bit Size Manufacturer Model Serial Number (in) : 12250 Nozzles TFA Dull Grade In Dull Grade Out 903 (in2) 1.1666 MOTOR DATA Motor Number 2 Bend (deg) 1,15 OD (in) 8.000 Nozzles (32nd) Manufacturer Sperry Drilling Avg Diff Press Model SperryDrig Cumul Cir Hre Serial Number Page 12 Version 2 June, 2014 HileOTp Energy Company 11.3 Primary Bit: PRODUCT SPECIFICATIONS IADC Code 117W Total Tooth Count 67 Gage Row Tooth Count 39 Journal Angle 33' Offset (1 1fi") 6 Jet Nozzle Types Standard 93244 Extended 302447 Center Jet (if Center Jetted) 501813 TJ. Connection 6-5!8" (API Reg.) Recommended Make -Up Torque' 28000,32000 Ftslbs. Bit Weight (Boxed) 250 Lbs. (113 Kg.) Bit Breaker (Mat.#1Legacy#') 515353 5064fi3 PRODUCT FEATURES New patented DiamondT"t Clawg tooth bit design. • Tungsten carbide 'surf inserts in gage teeth for added gage protection. • Newly formulated, proprietary hardfacing on cutting structure and gage maximizes carbide and diamond volume for ultimate wear resistance. • High-speed bearing designed for high rpm and high-energy applications. . Innovative mechanical pressure compensating system provides reliable pressure equalization and relief for maximum bearing and seal life. • Raised tungsten carbide inserts and proprietary hardfacing provides maximum arm protection in abrasive and directional applications while minimizing drill string torque. • QuadPack1, Plus Series incorporates its successful "longevity" features and patented engineered hydraulics system for optimal cleaning efficiency. • Center jet feature to prevent bit balling problems Frances #2 Drilling & Completion Procedure Material #1622394 'Calculations based on rccommcndations from API and toot joint manufacturers. C 2012 Halliburton. All rights reserved. Sales of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the sale. Page 13 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 11.4 4-1/2" Workstring & HWDP will come from Saxon. Jars will come from Weatherford. 11.5 Begin drilling out from 16" conductor at reduced flow rates to avoid broaching the conductor. v 11.6 Drill 12-1/4" hole section to 3,600' MD. Confirm this setting depth with the geologist and Drilling Engineer while drilling the well. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 500 - 550 gpm. Ensure shaker screens are set up to handle this flowrate. • Utilize Inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. • TD the hole section in a good shale btwn 3500' MD and 3700' MD. • Take MWD surveys every stand drilled (60' intervals). 11.7 12-1/4" hole mud program summary: Weighting material to be used for the hole section will be barite. Additional barite will be on location to weight up the active system (1) ppg above highest anticipated MW. We will start with a simple gel + FW spud mud at 8.8 ppg. �- Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 8.8 — 9.5 ppg Pre -Hydrated Aquagel/freshwater spud mud Properties: De the Density Viscosity Plastic Viscosity Yield Point API FL LGS 80-3600' 8.8 - 9.5 85-150 20 - 40 25 - 45 < 10 < 15% System Formulation: M-1 Gel + FW spud mud Product Concentration Fresh Water 0.905 bbl M-I Gel Export 20 ppb M-I Wate As needed Soda Ash 0.5 ppb Caustic Soda 0.1 ppb Busan 1060 0.04ppb Page 14 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Fnergy Company 11.8 At TD; pump sweeps, CBU, and pull a wiper trip back to the 16" conductor shoe. 11.9 TOH with the drilling assy, handle BHA as appropriate. 11.10 No open hole logging program planned for Frances #2 surface hole. Page 15 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 12.0 Run 9-5/8" Surface Casing 12.1 R/U and pull 15.375" wearbushing. 12.2 R/U Weatherford 9-5/8" casing running equipment. • Ensure 9-5/8" BTC x CDS 40 XO on rig floor and M/U to FOSV. • R/U fill -up line to fill casing while running. • Ensure all casing has been drifted on the location prior to running. • Be sure to count the total # of joints on the location before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 12.3 P/U shoe joint, visually verify no debris inside joint. 12.4 Continue M/U & thread locking shoe track assy consisting of- (1) Shoe joint w/ float shoe bucked on (thread locked). • (1) Joint with coupling thread locked. • (1) Joint with float collar bucked on pin end & thread locked. • Install (2) centralizers on shoe joint over a stop collar. 10' from each end. • Install (1) centralizer, mid tube on thread locked joint and on FC joint. • Ensure proper operation of float equipment. 12.5 Continue running 9-5/8" surface casing • Fill casing while running using fill up line on rig floor. • Use "API Modified" thread compound. Dope pin end only w/ paint brush. • M/U connections to the base of the triangle stamped on the pin end. Note M/U torque values required to achieve this position. Estimated torque to reach base of triangle: 10,750 ft-lbs. • After making up several connections, use the torque required to M/U to base of triangle as the M/U torque and continue running string. • Install (1) centralizer every other joint to 300'. Do not run any centralizers above 300' in the event a top out job is needed. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 9-5/8" BTC Estimated M/U Torque Casing OD Est Torque to Reach Triangle Base 9-5/8" 9,630 ft-lbs Page 16 Version 2 June, 2014 0 Hilcolp Energy Company Frances #2 Drilling & Completion Procedure Tenaris Casing and Tubing Performance Data Choose pipe size, wait thickness and steel grade to view API connection options and performance data. Size ��o Wall Grade ��n Connection �0 Unit Pipe Body Data 941hiall• Nominal OD 9.625 in Wall Thickness 0.395 in API Drift Diameter 8.679 in Nominal Weight 40.00 Ibstft Nominal ID 8.835 in Alternate Drift Diameter 8.75 in Plain End Weight 38.97lbstft Nominal Cross Section 11A54 sq in PERFORMANCE Steel Grade L80 Minimum Yield 80,000 psi Minimum Ultimate 95,000 psi Body Yield Strength 916,000lbs Internal Yield Pressure 5,750 psi Collapse Pressure 3,080 psi Connection Data xelflixf Regular OD 10.625 in Threads Per Inch 5 Make -Up Thread Turns 1 PERFORMANCE Steel Grade 1-80 MinimumYield 80„000 psi Minimum Ultimate 95,000 psi Joint Strength 947,000 lbs internal Pressure 5,750 psi Resistance TenarisHvdnl Preniiui�� Connections Print Contact Us Ver 8.6 12.6 Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 12.7 Slow in and out of slips. 12.8 P/U casing hanger joint and M/U to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe as close to TD as possible. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 12.9 Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. Page 17 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 12.10 R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 12.11 After circulating, lower string and land hanger in wellhead again. Page 18 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hllcorp Energy Company 13.0 Cement 9-5/8" Surface Casing 13.1 Hold a pre job safety meeting over the upcoming cmt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. • How to handle cmt returns at surface. • Which pump will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Positions and expectations of personnel involved with the cmt operation. 13.2 Document efficiency of all possible displacement pumps prior to cement job 13.3 R/U cmt head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 13.4 Pump 5 bbls 10 ppg spacer. Test surface cmt lines. 13.5 Pump remaining 35 bbls 10 ppg spacer. 13.6 Drop bottom plug. Mix and pump cmt per below recipe. 13.7 Cement volume based on annular volume + 50% open hole excess. Job will consist of lead & tail, TOC brought to surface. Estimated Total Cement Volume: Section: Calculation: Vol (BBLS) Vol (ft3 LEAD: 80' x .129 bpf = 10.3 57.8 16" Conductor x 9-5/8" casing annulus: LEAD: (3000' — 80') x .0558 bpf x 1.5 = 244.4 1372 12-1/4" OH x 9-5/8" Casing annulus: Total LEAD: 254.7 bbl 1430 ft3 TAIL: (3600'-3000') x .0558 bpf x 1.5 = 50 282 12-1/4" OH x 9-5/8" Casing annulus: TAIL: 90 x .096 bpf = 8.7 48.8 9-5/8" Shoe track: Total TAIL: 58.7 bbl 331 ft3 Page 19 Version 2 June, 2014 6 -71 ).'C'ti Frances #2 Drilling & Completion Procedure Cement Slurry Design: Lead Slurry (3000' MD to surface) Tail Slurry (3600' to 3000' MD) System Extended Conventional Density 12.5 lb/gal 15.2 lb/gal Yield 2.13 ft3/sk 1.25 ft3/sk Mixed Water 12.02 gal/sk 5.7 gal/sk Mixed Fluid 12.03 gal/sk 5.71 gal/sk Code Description Concentration Code Description Concentration Type1 Cement 94 lb/sk WBWOB Type1 Cement 94 lb/sk WBWOB Static Free De-Foamer 0.005 Ibs/sk Static Free De-Foamer 0.005 Ibs/sk CaCI Accelerator 2% bwoc CaCI Accelerator .25% bwoc Additives CD-32 Dispersant 0.4% bwoc CD-32 Dispersant 0.5% bwoc FL-52 Fluid Loss Add 0.3% bwoc FL-52 Fluid Loss Add 0.2% bwoc FP-6L De-Foamer 1 gal/100 sk FP-6L De-Foamer 1 gal/100 sk Na Metasillicate Extender 2% bwoc 13.8 Attempt to reciprocate casing during cement pumping if hole conditions allow. Keep the hanger elevated above the wellhead while working. If the hole gets "sticky", land the hanger on seat and continue with the cement job. 13.9 After pumping cement, drop top plug and displace cement with 9.5 ppg Kla-shield. 13.10 Ensure cement unit is used to displace cmt so that volume tracking is more accurate. 13.11 Displacement calculation: 3500' x .0758 bpf = 265.3 bbls 13.12 Monitor returns closely while displacing cement. Adjust pump rate if necessary. If hanger flutes become plugged, open wellhead side outlet in cellar and take returns to cellar. Be prepared to pump out fluid from cellar. Have some sx of sugar available to retard setting of cement. 13.13 Do not overdisplace by more than '/2 shoe track volume. Total volume in shoe track is 8.7 bbls. 13.14 Be prepared for cement returns to surface. If cmt returns are not observed to surface, be prepared to run a temp log btwn 6 — 18 hours after CIP. 13.15 Be prepared with small OD top out tubing in the event a top out job is required. The AOGCC will require us to run steel pipe through the hanger flutes. The ID of the flutes is 1.5". Page 20 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 13.16 Bump the plug with 500 psi over displacement pressure. Bleed off pressure and confirm floats are holding. If floats do not hold, pressure up string to final circulating pressure and hold until cement is set. Monitor pressure build up and do not let it exceed 500 psi above final circulating pressure if pressure must be held. L3.17 R/D cement equipment. Flush out wellhead with FW. 13.18 Back out and L/D landing joint. Flush out wellhead with FW. 13.19 M/U pack -off running tool and pack -off to bottom of Landing joint. Set casing hanger packoff. Run in lock downs and inject plastic packing element. 13.20 Lay down landing joint and pack -off running tool. Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration a. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid b. Note if casing is reciprocated or rotated during the job c. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold d. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure e. Note if pre flush or cement returns at surface & volume f. Note time cement in place g. Note calculated top of cement h. Add any comments which would describe the success or problems during the cement job Send final "As -Run " casing tally & casing and cement report to lkellerkhilcorp. com. This will be included with the EOW documentation that goes to the AOGCC. Page 21 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure HilcoTp Energy Company 14.0 BOP N/U and Test 14.1 N/D the conductor flow riser. 14.2 N/U Seaboard multi -bowl wellhead assy. Install packoff 9-5/8" P-seals. Test to 3000 psi. 14.3 N/U 11" x 5M T3-Energy BOP as follows: • BOP configuration from Top down: I I" x 5M T3-Energy annular BOP/11" x 5M T3-Energy Model 6011i double ram /I I" x 5M mud cross/II" x 5M T3-Energy Model 6011i single ram • Double ram should be dressed with 2-7/8 x 5-1/2" VBRs in top cavity, blind ram in btm cavity. • Single ram should be dressed with 2-7/8 x 5-1/2" VBRs • N/U bell nipple, install flowline. • Install (2) manual valves & a check valve on kill side of mud cross. • Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 14.4 Run 4-1/2" BOP test assy, land out test plug (if not installed previously). • Test BOP to 250/3000 psi for 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave `B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 R/D BOP test assy. 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 9.5 ppg Kla-Shield mud system. 14.8 RAJ mud loggers for production hole section. 14.9 Set 10" ID wearbushing in wellhead. 14.10 Rack back as much 4-1/2" DP in derrick as possible to be used while drilling the hole section. 14.11 Keep 5-1/2" liners in mud pumps. Page 22 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 15.0 Drill 8-1/2" Hole Section 15.1 P/U 8-1/2" directional BHA. 15.2 Ensure BHA components have been inspected previously. 15.3 Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 15.4 TF offset is measured accurately and entered correctly into the MWD software. 15.5 Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. Hydraulics calculations and recommended TFA is attached below. 15.6 Workstring will be 4.5" 16.6# S-135 CDS40. Page 23 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Energy p / Energy Company 15.7 8-1/2" BHA (Includes GR+Res+Den/Neu LWD components): COMPONENTDATA 1 D. HUBS - FX650 On 8.40D i 2.500 8.500 172.13 connectlan P 4-112` REG 1.00 1.OD 2 7" SperryOrill Lobe 718 - 6.0 stg 7.00D 4.952 93.13 B 4-112" IF 27.30 28.38 Stabilizer 7.750 3 Non Mag Float Sub 6.750 2.750 101.71 B 4-112- IF 3.00 31.39 4 Integral Blade St8bi6izer (NM) 6.75D 2.813 B.375 100-77 B 4-112" IF 5.00 36.38 5 6 3A" DM (Directional y 6.75D 3.125 103-40 B 4-112" IF 9.20 45-58 6 6 T4" DGR (Gamma) 6150 1.92D 97.80 B 4-112- IF 4.55 50.14 7 6 314' EWR-P4 (Resistivity) 6 750 2.00D 104.30 B 4-112'IF 12.10 62.24 8 6 314" HCIP.f {Processor) 6.75D 1920 101.70 B 4-112" IF 4.97 6721 9 1 6 314" ALD Collar 175C 3OKS1 6.75D 1.92D B.250 104.30 P NC 50 14.54 81.75 Stabilizer 8.250 10 6 314- CTN Collar 175C 30KS1 6,750 1.905 102.3D B NC 50 11.84 93.59 11 6 314" Tad - HOC (Pulser) 6.900 3.25D 103.60 B 4-112" IF 15.59 109.18 12 6-314' Non Mag Flex Drill Corlar 6.75D 2.813 100.77 B 4-112- IF 30.0D 139.18 13 6-314' Non Mag Flex Drill Collar 6.75D 2.813 100.77 B 4-112" IF 30.0D 169.18 14 X-O 4-112- CDS 40 Box X 4-1A2" IF Pin 6.50D 2.750 92.85 B 4.5" CDS 40 2.75 171.93 15 6 Joints 4-1,12' CDS 40 HWDP 4.500 2.500 37.47 1130.00 351.93 16 X-O 4-1/2" IF Box X 4-1?2" CDS 40 Pin 6.501) 2.750 92.85 B 4-112" IF 2.75 354.68 17 Weatherford & 4" Jars 6.25D 2.25D 91.01 B 4-112" IF 30.00 384.68 18 X-O 4-112"IF Pin X 4-112"CDS 40 Box 6.50D 2.750 CDS 40 2.75 387.43 19 19 Joints 4-1 t2` CDS 40 HWOP 4.500 2.50D E37.47 LB4.5" 570.00 957.43 - 95T43 Bit Number Bit Size Manufacturer Model Serial Number (in) : 8.50D Nozzles TFA Dull Grade In Dull Grade Out 5xl3 (in2) : 0.6481 Page 24 Version 2 June, 2014 Hilcorp Energy Company 15.8 Primary Bit: PRODUCT SPECIFICATIONS Cutter Type SelectCutter I.ADC Code M324 Body Type MATRIX Total Cutter Count 41 Cutter Distribution 13mm 16mm Face I 29 Gauge 5 0 Up Drill 6 0 Number of Large Nozzles 0 Number of Medium Nozzles 0 Number of Small Nozzles 6 Number of Micro Nozzles 0 Number of Ports ( Size) 0 Number of Replaceable Ports ( Size) 0 Junk Slot Area (sq in) 14.81 Normalized Face Volume 4113% API Connection 4-V2 REG. PIN Recommended Make -Up Torque* 12,461 — 17,766 Ft'lbs_ Nominal Dimensions`* Make -Up Face to Nose 10.73 in -273 mm Gauge Length 2-5 in - 64 mm Sleeve Length 0 in - 0 min Shank Diameter 6 in - I52 mm Break Out Plate (Mat.4!'Legacy;) 18195444040 Approximate Shipping Weight 160Lbs. -73Kg- SPECIAL FEATURES 1132" Relieved Gage, Combination Backream!Up-Drill Cutters. Secondary Cutting Element - "R" Feature. TSP Gage Frances #2 Drilling & Completion Procedure Material #803275 *Bit specific recommended make-up torque is a function of the bit I.D. and actual bit sub O.D. utilized asspcciftcd in API RP7G Section A.8.2. •'Design dimensions an nominal and may vary slightly on manufactured product lialliburton Drill Bits and Services models arc continuously reviewed and refined. Product specifications may change without notice_ C! 2013 Halliburton. All rights reserved. Sales of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the sale. Page 25 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 15.9 8-1/2" hole section mud program summary: Weighting material to be used for the hole section will be salt and calcium carbonate. Additional calcium carbonate will be on location to weight up the active system (1) ppg above highest anticipated MW. Pason PVT will be used throughout the drilling and completion phase. Remote monitoring stations will be available at the driller's console, Co Man office, Toolpusher office, and mud loggers office. System Type: 9.5 ppg Kla-Shield fresh water based drilling fluid with 6% KCI. Properties: De the DensityPlastic ViscosityYield Point Chlorides API FL pH 3600'-9,242' 9.5 10-20 15-25 60,000 — 70,000 <8 9.0 - 10 System Formulation: M-1 Swaco Kla-Shield with 6% KCI Product ConcentrationNunction Water Base Fluid Busan 1060 0.4 ppb Biocide Soda Ash 0.25 ppb PH/Hardness Control Flowzan 1.0 ppb Viscosifier/Rheology KCL 21.8 ppb weight/inhibition NaCI Salt 20.Oppb weight/inhibition Poly Pac Sup UL 0.75 ppb API Fluid Loss EMI-2009 2-3% v/v Clay/Shale inhibitor Safe-Carb 40 If needed for weight increase over Conqor 404 9.Oppg Asphasol Supreme Corrosion Mitigation Sack Black 4ppb Shale/Coal Stabilizer 3 b-Gilsonite Shale/Coal Stabilizer 15.10 TIH w/ 8-1/2" directional assy to TOC. Shallow test MWD and LWD on trip in. Note depth TOC tagged on AM report. 15.11 R/U and test casing to 2900 psi / 30 min. Ensure to record volume / pressure and plot on FIT graph. AOGCC reg is 50% of burst = 5750 / 2 = 2875-2900 psi 15.12 Drill out shoe track and 20' of new formation. 15.13 CBU and condition mud for FIT. 15.14 Conduct FIT to 12 ppg EMW. Page 26 Version 2 June, 2014 Hilcorp Energy Company Frances #2 Drilling & Completion Procedure Note: Offset field test data predicts frac gradient at the 9-518 " shoe to be btwn 17 -18 ppg EMW. A 12 ppg FIT results in a 2.5 ppg kick margin while drilling with the planned MW of 9.5 PPg- 15.15 Drill 8-1/2" hole section to 9,242' MD / 8,260' TVD. • Pump sweeps and maintain mud rheology to ensure effective hole cleaning. • Pump at 400 - 450 gpm. Ensure shaker screens are set up to handle this flowrate. • Utilize inlet experience to drill through coal seams efficiently. Coal seam log will be provided by Hilcorp Geo team, try to avoid sliding through coal seams. Work through coal seams once drilled. • Keep swab and surge pressures low when tripping. • Make wiper trips every 500' or every couple days unless hole conditions dictate otherwise. • Ensure shale shakers are functioning properly. Check for holes in screens on connections. • Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. • Take MWD surveys every other stand drld. Surveys can be taken more frequently if deemed necessary. • Take (3) sets of formation samples every 20'. Mud loggers should compile Pixler plots and QFT 2 analysis for Lower Tyonek to total depth. 15.16 At TD; pump sweeps, CBU, and pull a wiper trip back to the 9-5/8" shoe. 15.17 TOH with the drilling assy, stand back BHA if possible. Drop a drift on the last trip out of the hole in preparation for running the liner. 15.18 R/U and run OH wireline logs consisting of: • Dipole Sonic • Rotary sidewall cores (25). 15.19 Monitor the well at all times on the trip tank while logging. 15.20 After logging objectives accomplished, pick up a wiper trip BHA and make another run to TD. Circ B/U at TD and TOH. Rack back DP, handle BHA as appropriate. Page 27 Version 2 June, 2014 0 Hilcorp Energy Company 16.0 Run 5-1/2" Production Casing Frances #2 Drilling & Completion Procedure 16.1. R/U 5-1/2" casing running equipment. • Ensure 5-1/2" DWC/C x CDS 40 crossover on rig floor and M/U to FOSV. • R/U fill up line to fill casing while running. • Ensure to R/U Tesco or Weatherford CRT so that string can be rotated if necessary while running. • Ensure all casing has been drifted on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/ vendor & model info. 16.2. P/U shoe joint, visually verify no debris inside joint. 16.3. Continue M/U & thread locking shoe track assy consisting of- (1) Shoe joint w/ shoe bucked on & threadlocked (coupling also thread locked). Install (2) solid body centralizers on shoe joint prior to bucking on float shoe. The centralizers should be held in place 10' from each end via stop rings on either side. • (1) Thread locked joint (coupling thread locked). • (1) Joint with float collar bucked on pin end & threadlocked (coupling also thread locked). Install (1) solid body centralizer on float collar joint prior to bucking on float collar. • Install a solid body centralizer on landing collar joint. Leave centralizers free floating so that they can slide up and down the joint. • Ensure proper operation of float shoe and float collar prior to running in the hole. 16.4. Continue running 5-1/2" prod casing. • Fill casing while running using fill up line on rig floor. • Use "Best O Life 2000" thread compound. Dope pin end only w/ paint brush. • Install solid body centralizers on every joint to 5,400 MD. Every other joint to 3800'. None above 3800'. Leave the centralizers free floating. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 5-1/2" DWC/C M/U torques Casing OD Minimum Maximum Yield Torque 5.5" 12,000 ft-lbs 13,800 ft-lbs 15,500 ft-lbs Page 28 Version 2 June, 2014 Hilcorp Energy Company Connection Type: DWC/C Casing standard Frances #2 Drilling & Completion Procedure Technical Specifications Size(O.D.): Weight (wall): 5-1f2 in 17.00Ibtft (0.304 in) Material P-110 Grade 110,000 Minimum Yield Strength (psi) 125,000 Minimum Ultimate Strength (psi) Pipe Dimensions 5.500 Nominal Pipe Body O.D. (in) 4.892 Nominal Pipe Body I.D.(in) 0.304 Nominal Wall Thickness (in) 17.00 Nominal Weight (lbslft) 16.89 Plain End Weight (lbslft) 4.962 Nominal Pipe Body Area (sq in) Pipe Body Performance Properties 546,000 Minimum Pipe Body Yield Strength (lbs) 7,480 Minimum Collapse Pressure (psi) 10,640 Minimum Internal Yield Pressure (psi) 9,700 Hydrostatic Test Pressure (psi) Connection Dimensions 6.050 Connection O-D. (in) 4.892 Connection I.D. (in) 4.767 Connection Drift Diameter (in) 4.13 Make-up Loss (in) 4.962 Critical Area (sq in) 100.0 Joint Efficiency (%) Connection Performance Properties 546,000 Joint Strength (Ibs) 22,940 Reference String Length (ft) 1.4 Design Factor 568,000 API Joint Strength (Ibs) 546,000 Compression Rating (Ibs) 7,460 API Collapse Pressure Rating (psi) 10,640 API Internal Pressure Resistance (psi) 91.7 Maximum Uni axial Bend Rating [degrees1100 ft] Appoxlmated Field End Torque Values 12,000 Minimum Final Torque (ft-Ibs) 13,800 Maximum Final Torque (ft-Ibs) 15,500 Connection Yield Torque (ft-Ibs) Grade: P-110 U �R VAM USA 4424 W. Sam Houston Pkvey. Sure 150 Houston. TX 77041 Phone- 713-479-32(YD Fax: 713479-3234 E-mai1: VAh1 U SAsalesgDvam-us a scam Page 29 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 16.5. M/U casing hanger joint to string. Casing hanger joint will come out to the rig with the landing joint already M/U. Position the shoe approx 10 — 20' above TD. Strap the landing joint while it is on the deck and mark the joint at (1) ft intervals to use as a reference when landing the hanger. 16.6. Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 16.7. R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger offseat (slightly) to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 16.8. After circulating, lower string and land hanger in wellhead again. Page 30 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure 17.0 Cement 5-1/2" Production Casing 17.1. Hold a pre job safety meeting over the upcoming curt operations. Make room in pits for volume gained during cement job. Ensure adequate cement displacement volume available as well. Ensure mud & water can be delivered to the cmt unit at acceptable rates. • How to handle cmt returns at surface, regardless of how unlikely it is that this should occur. • Which pump will be utilized for displacement, and how fluid will be fed to displacement PUMP. • Positions and expectations of personnel involved with the curt operation. • Document efficiency of all possible displacement pumps prior to cement job. 17.2. Attempt to reciprocate the casing during cmt operations. 17.3. Pump 5 bbls 10 ppg SealBond spacer. 17.4. Test surface curt lines to 4500 psi. 17.5. Pump remaining 15 bbls 12 ppg SealBond spacer. 17.6. Mix and pump lead and tail cmt per below recipe. Ensure curt is pumped at designed weight. Job is designed to pump 30% OH excess. b 3ic° nti Section: Calculation: ( Vol Vol (ft3) 9-5/8" x 5-1/2" Overlap(Lead): 500' x 0.046 = 23 129 8-1/2" OH x 5-1/2" Liner(Lead): (6,350 — 3,600') x 0.0408 x 1.3 = 146 820 8-1/2" OH x 5-1/2" Liner(Tail): (9,242' — 6,350') x 0.0408 xl.3 = 153 876 Shoe Track(Tail): 90' x 0.023 = 2.1 12 Total Volume (Lead): 169 949 Total Volume (Tail): 155.1 871 Page 31 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company Lead Slurry (6350' to 3600') Tail Slurry (9100' to 6350' MD) System Extended Conventional Density 13.5 lb/gal 15.2 lb/gal Yield 1.82 ft3/sk ✓ 1.25 ft3/sk -- Mixed Water 9.21 gal/sk 5.7 gal/sk Mixed Fluid 9.22 gal/sk 5.71 gal/sk Code Description Concentration Code Description Concentration Class G Cement 94 lb/sk WBWOB Type1 Cement 94 lb/sk WBWOB BA-90 Low den. additive 10% bwoc Static Free De-Foamer 0.005 Ibs/sk BA-56 Gas Migration 2.5% bwoc R-3 Retarder 0.9% bwoc CD-32 Dispersant 0.4% bwoc CD-32 Dispersant 0.6% bwoc Additives ASA-301 Free water control 0.1% bwoc FP-6L De-Foamer 1 gal/100 sk FP-6L De-Foamer 1 gal/100 sk BA-10A Bonding agent 1% bwoc Na Metasillicate Extender 0.5% bwoc MetaNillicate Extender 0.5% bwoc Static Free De-Foamer 0.005 Ibs/sk 17.7. Drop DP dart and displace with 6% KCL 9000' x .023 = 209 bbls 17.8. Do not overdisplace by more than shoe track. Shoe track volume is 1.7 bbls. 17.9. Bleed pressure to zero to check float equipment. 17.10. Pressure up again to 3500 psi and hold for 30 min to test production bore. Page 32 Version 2 June, 2014 Hilcorp Energy Company Frances #2 Drilling & Completion Procedure Ensure to report the following on wellez: • Pre flush type, volume (bbls) & weight (ppg) • Cement slurry type, lead or tail, volume & weight • Pump rate while mixing, bpm, note any shutdown during mixing operations with a duration i. Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid j. Note if casing is reciprocated or rotated during the job k. Calculated volume of displacement, actual displacement volume, whether plug bumped & bump pressure, do floats hold 1. Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure m. Note if pre flush or cement returns at surface & volume n. Note time cement in place o. Note calculated top of cement p. Add any comments which would describe the success or problems during the cement job Send final "As -Run " casing tally & casing and cement report to lkeller(acr�hilcorp. com. This will be included with the EOW documentation that goes to the AOGCC. Page 33 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 18.0 RDMO 18.1 Install back pressure valve in hanger neck. N/D BOP. 18.2 Install & test production tree. 18.3 RDMO Saxon rig #147 ' 18.4 After rig has departed, pull BPV and run CBL to determine TOC behind 5-1/2" production casing. Send the CBL to the AOGCC for review. J 19.0 Perf and Frac 19.1 A separate sundry will be submitted to the AOGCC that will cover the below operations: • R/U workover rig • Run production tubing / pkr / CIM & SCSSV. • Perforating and flowback • And hydraulic fracturing or other stimulation that may be necessary to produce the well commercially. Page 34 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 20.0 BOP Schematic Page 35 Version 2 June, 2014 Hilcorp Enegy Company 21.0 Wellhead Schematic Tubing head, Seaboard-S8, 11 5M X 7 1/16 5M, w/ 2- 2 1/16 5M SSO, 7" P seal bottom Casing spool, Seaboard-S8, 16 3/4 3M X 11 5M, w/ 2- 2 1/16 5M SSO, 9 5/8 P sea I bottom Starting head, Seaboard, 16 % 3M X 16" SOW BTM, w/ 2- 2 1/16 5M SSO Ninilchik Unit New drill system -Seaboard Saxon Rig 147 16x95/8x51/2 5 %" z Frances #2 Drilling & Completion Procedure Page 36 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 22.0 Days Vs Depth Days Vs Depth 0 — — —Frances#2 —Falls Creek #5 200 4WD - x s 60DO N Qj O1 BODO loo00 12DOD 0 5 10 15 20 25 30 35 40 Days Page 37 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 23.0 Formation Tops ANTICIPATED FORMATION TOPS & GEOHAZARDS EXPECTED Intersection Points TOP TOP NAME FLUID MD fF77 TVD TVDSS tF77 Est Pressure X Y +/- BELUGA 2686 2.591 -2.231 1114 Beluga-50 Pos Gas 3776 3,503 -3,243 r 1506 Beluga 135 Pos Gas 5427 5,033 -4,773 r 2164 Tyonek GAS 5671 5,260 -5,000 r 2262 T-8 Tight Gas 6502 6,031 -5,771 2593 T-10 Tight Gas 6769 6,277 -6,017 r 2699 240355 2269825 40 T-50 GAS 8271 7,573 -7,313 r 3256 T-60 GAS 8491 7,762 -7,502 r 3338 T-65 GAS 8953 8.161 -7,901 3509 240434 2270996 40 Total Depth 9100 ObjectivePrimary Secondary Obiective Page 38 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure 24.0 Anticipated Drilling Hazards 12-1/4" Hole Section: Lost Circulation: Ensure adequate amounts of LCM are available. Safe-carb 10, 20, 40, 250, & 750. Ensure G-seal, Pecan nut plug, and Mix II are also available for more severe lost returns incidents. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of Safe-carb 10 & 20 to the active system at 1 — 2 ppb. Hole Cleaning: Maintain rheology w/ gel and gel extender. Sweep hole with gel or flowzan sweeps as necessary. Optimize solids control equipment to maintain density, sand content, and reduce the waste stream. Maintain YP btwn 25 — 45 to optimize hole cleaning and control ECD. Wellbore stability: Lithology through this zone is a composite of pebble conglomerate and sand in the upper intervals with intermittent clay matrix. Carbonaceous material and coal may be noted. Gravel sizes that are larger than normal can cause hole -cleaning problems. If encountered, be prepared to increase the viscosity. Excessive quantities of gravel and sand may indicate wellbore instability. Increase properties up to a YP of —50 - —60 lbs/100ft2 to combat this issue. Maintain low flow rates for the intial 200' of drilling to reduce the likelihood of washing out the conductor shoe. To help insure good cement to surface after running the casing, condition the mud to a YP of 25 — 30 prior to cement operations. Do not lower the YP beyond 25 to avoid trouble with sands that may be found on this well. Have Desco DF, SAPP, and water on hand to ensure the desired rheologies can be achieved. H2S: H2S is not present in this hole section. No abnormal pressures or temperatures are present in this hole section. Page 39 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilco p sorry company 8-1/2" Hole Section: Lost Circulation: Ensure adequate amounts of LCM are available. Safe-carb 10, 20, 40, 250, & 750. Ensure G-seal, Pecan nut plug, and Mix II are also available for more severe lost returns incidents. Monitor fluid volumes to detect any early signs of lost circulation. For minor seepage losses, consider adding small amounts of Safe-carb 10 & 20 to the active system at 1 — 2 ppb. Hole Cleaning: Maintain theology w/ flowzan. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP btwn 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain 1ppb total of PolyPac Supreme UL to maintain a thin/strong wall cake and keep HTHP filtrate below 9 ml/30 min. Maintain MW as necessary using additions of Barite. Maintain 6 ppb EMI-2009 for shale/clay inhibition. Maintain 4 ppb Asphasol Supreme & 3 ppb Sack Black for Shale/Coal stabilizer. Maintain 6% KCl in system for shale inhibition. Coal Drilling: The following lessons were learned from extensive experience drilling coal seams in Cook Inlet. The need for good planning and drilling practices is also emphasized as a key component for success. • Keep the drill pipe in tension to prevent a whipping effect which can disturb coal sections. • Use asphalt -type additives to further stabilize coal seams (Asphasol Supreme, Sack Black). • Increase fluid density as required to control a "running coal". • Emphasize good hole cleaning through hydraulics, ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb Asphasol Supreme pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss. H2S: 112S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 40 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 25.0 Saxon Rig 147 Layout i ,•— Page 41 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp Energy Company 26.0 FIT Procedure Formation Integrity Test (FIT) and Leak -Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20' of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer (ram or annular). 4. Pump down the drill stem at 1 /4 to 1 /2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs. pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre -determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre -determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 42 Version 2 June, 2014 Hilcorp Energy Company 27.0 Choke Manifold Schematic Page 43 Version 2 Frances #2 Drilling & Completion Procedure June, 2014 Hilcorp Energy Company Frances #2 Drilling & Completion Procedure 28.0 Casing Design Information Hole Size 12-1/4" Hole Size 8-1/2" Hole Size DATE: 6123/2014 WELL: Frances #2 DESIGN BY:Luke Keller Design Criteria: Mud Density 8.8 PM Mud Density: 9.5 ppii Mud Density: Drilling Mode MASP: 1675 psi (see attached MASP determination & calculation) MASP: Production Mode MASP: 2759 psi (see attached MASP determination & calculation) Collapse Calculation: Section Calculation 1 Normal gradient external stress (0.494 psUft) and the casing evacuated for the internal stress Casing Section Calculation/Specification 1 2 3 4 Casing OD To MD 9-518" 0 5-1/2" 0 To 0 0 Bottom Mil 3,600 9,242 Bottom Length 3,396 3,600 8,260 9„242 Weight p 40 17 Grade L-80 P-110 Connection Weight w/o Bouyancy Factor Ibs BTC 144,000 DWC/C 157,114 Tension at TOP of Section Ibs) Min strength Tension 10001bs 144,000 916 157,114 546 Worst Case Safety Factor (Tension) Collapse Pressure at bottom Psi 6.36 1,678 3.48 4.080 Collapse Resistance w/o tension Psi) Worst Case Safety Factor (Collapse) 3,090 1.84 7„460 1.83 MASP (psi) Minimum Yield(psi) 1,777 5,750 2„759 10,640 Worst case safe factor (Burst) 3.24 3.86 Page 44 Version 2 June, 2014 0 Hilcorp Energy Company 29.0 8-1/211 i I licar� Frances #2 Drilling & Completion Procedure Hole Section MASP Maximum Anticipated Surface Pressure Calculation B-1/2" Hole Section Frances #2 Ninilchik Unit IVID TVD Planned Top: 3500 3396 Planned TD: 9242 8260 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas[Wet PPG Grad Beluga-50 3,503 1506 Pos Gas 8.3 0.430 Beluga 135 5,033 2164 Pas Gas 8.3 0.430 T onek T-8 5 2b0 6,031 2262 GAS 2593 Tight Gas 8.3 8.3 0.430m 0.430 T-10 6,277 2699 Tight Gas 8.3 0.430 T-50 7,573 3256 GAS 8.3 0.430 ? 50 7,762 3338 GAS 8.3 0.430 T-65 81161 3509 GAS 8.3 0,430 TD Offset Well Mud Densities Well N%V range Top (TVD) Bottom (TVD) Date Falls Creek 01 11-6 -13.1 3,500 10,000 1960 Falls Creek #2 10.5 - 11 3,500 6,300 1966 Falls Creek #3 9.4 - 9-5 3,500 8,400 2003 Falls Creek #4 Falls Creek #5 9-9-5 9-5-9-7 3,500 6,D00 3,520 9,715 2004 2014 Corea [reek #1 9.5 -10.13 1 3,500 9,000 1996 Frances #1 9.5 - 9-8 1 3,500 10,000 2013 Assumptions: 1. Fracture gradient at shoe is estimated at 0.936 psi / ft based on field test data. 2. Maximum planned mud density for the 8-1/2"' hale section is 9.5 ppg- 3. Calculations assume "Unknown" reservoir contains 10DIX gas (worst case). 4. Calculations assume worst case event is 2/3 evacuation of wellbore to gas. Remaining 1/3 volume in welibore remains drilling fluid density. Fracture Pressure at 9-5/8" shoe considering a full column of gas from shoe to surface: 3396 (ft) x 0.936(psi/ft)= 317E psi 3178(psi) - [0A(psi/ft)'3396(ft)]= 2839 psi MASP from pore pressure (unknown gas sand at TD, at 8.4 ppg, encountered while drilling) 8,260 (ft) x 0.434(psi/ft)= 3585 psi 3585(psi) -11213)•0.1(psi/ft)"8,260[ft)]+[(1/3)'0-494(psi/ft)•8.260(ft))= 1675 psi MASP from pore pressure during production made (Complete evacuation to gas) 8,260 (ft) x 0.434(psi/ft)= 3585 psi 3585[psi) - 10-1(psi/ft)"8,260 (ft)]= 2759 psi Summary: 1. MASP while drilling 8-1/2" production hole is governed by pore pressure and evacuation of 2/3 of wellbore to gas at 0.1 psi/ft. Page 45 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcoip Energy Company 30.0 Spider Plot (NAD 27) (Governmental Sections) NiCCt�ilc/hfik � Unit 111"n. ILL es Page 46 Version 2 © t,aaa z.DW Feet V AWsU sae Ptam Zv a 4, NA027 Map 6ffia: W24=4 June, 2014 Frances #2 Drilling & Completion Procedure Hilc EneW,2,T 31.0 Surface Plat (As Staked) (NAD 27) 114 /1 Fed Brass Cap I I I I L IT —ER CLAM A'F/L—,, —$06�— S7 3 L 7 rRqS7 z LL lr-f 8 NO i E iu. FRANCES NO. 2 WELL Aq-STAKED NAD27 A611 ZONE 4 N:2267312.9 E:240097 LAT: 15IT" 1 1'54.846N LUNG: 151"25'42.304'W `ELEV. 249.8'NAVD88 6B9'FEL 244'FNL GET CLWIRrx Ih*1 V. BARTOLOWITS PAD SEC. 7 TIN, RI 2W S. M -AX 100, 200- HASIS OF GEODETIC C(MlROL Nail)&iPOSITION tF-PCICH2010)ANCI ORT140METRIC HEIGHT IS AN OPUS SOLUTION FROM NGS COORDINATES STATIONSAC23 SOLDOTNA AK20:17 CORS ARP', 5F-tD 5EL0-AKDA-AK2D00 CORS ARP", ANEFAC17 DRIETRIVERAK2008 MRS ARP' TO ESTABLISH TKE POSITION OF 'CP87 EAST OF THE BARTOWITS PAD- THE GEODETIC POSITION or CP8 WAS DETERMYNED TO HAVE A LATITUDE OF 69'1 1'49-91836'N AW) A LONGITUDE OF 151'2542,0001'W. THE ALASKA STATE PLANE COORDINATES JXSPI ZONE 4 ARE N-22667711.327 E-1380480.8B7 ELEV. 259.955'(NAVD88 GE0012AI 2> SECTION LINIE OFFSE tS (*rERW*D FROM MONUMEN rtl) SECTION CORNER VALUES. 3; NAD63 COORDINATES CONVERTED 70 NAD27 WITH GORPSCON CONVERSION SOFT WARE VERSION 6,0 1 Frid rasa C; S7 OF At ... go dV 10 do M, SCOT-T McLANE�.: 4928—S SC I ALE HILCORP ALASKA LTC 3800 CENTERPOINT DR- FRANCES NO. 2 WELL AS -STAKED ANCHORAGE, AK 99-503-582b SURFACE LOCATION DIAGRAM NAD27 ON BARTOLOWITS PAD SEC 7 TIN R12W SEWARD MERIDIAN, ALASKA Page 47 Version 2 June, 2014 Frances #2 Drilling & Completion Procedure Hilcorp EnergyCompany 32.0 Offset MW vs TVD Chart Frances #2 Offset Wells 0 1 G'M 20flD 3DOO 4000 50w 60M ❑ 7000 sow 9000 100DO 11ODO 120DO 13MO 14WO 8 9 10 11 12 13 14 15 Mud Weight (PPG) Page 48 Version 2 June, 2014 Hilcorp Energy Company Ninilchik Unit Falls Creek Frances 2 Frances 2 Plan: Frances 2 wp1.0 Proposal Report 24 June, 2014 Well Coordinates: 2,267,312.90 N, 240,097.00 E (60' 11' 54.85" N, 151 ° 25' 42.30" W) Ground Level: 260.00 usft Local Coordinate Origin: Viewing Datum: North Reference: Geodetic Scale Factor Applied Version: 5000.1 Build: 70 Centered on Well Frances 2 Prelim: Frances 2 @ 278.00usft True HALLIBURTON Sperry Grilling HALLIBURTBN I Spew' C7r filling Plan Proposal Report for Frances 2 - Frances 2 wp1.0 Hilcorp Energy Company Ninilchik Unit Survey Stations Measured Vertical Vertical Dogleg Build Turn Toolface Depth INC AZM Depth +N/-S +E/-W Section Northing Easting Rate Rate Rate Azimuth (usft) (°) (°) (usft) (usft) (usft) (usft) (usft) (usft) (°I100usft) (°/100usft) (°/100usft) (°) 18.00 0.00 0.00 18.00 0.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 0.00 0.00 100.00 0.00 0.00 100.00 0.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 0.00 0.00 200.00 0.00 0.00 200.00 0.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 0.00 0.00 300.00 0.00 0.00 300.00 0.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 0.00 0.00 400.00 0.00 0.00 400.00 0.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 0.00 0.00 500.00 0.00 0.00 500.00 0.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 0.00 0.00 600.00 0.00 0.00 600.00 0.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 0.00 0.00 700.00 0.00 0.00 700.00 0.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 0.00 0.00 800.00 0.00 0.00 800.00 0.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 0.00 0.00 900.00 0.00 0.00 900.00 0.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 0.00 0.00 1,000.00 0.00 0.00 1,000.00 0.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 0.00 0.00 1,100.00 0.00 0.00 1,100.00 0.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 0.00 0.00 1,200.00 0.00 0.00 1,200+00 0.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 0.00 0.00 1,300.00 0.00 0.00 1,300.00 0.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 0.00 0.00 1,400.00 0.00 0.00 1,400.00 0.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 0.00 0.00 1,450.00 0.00 0.00 1,450.00 0.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 0.00 0.00 Start Dir 2°/100' : 1450' MD, 1450'TVD 1,500.00 1.50 3.99 1,499.99 0.65 0.05 0.65 2,267,313.55 240,097.06 3.00 3.00 0.00 3.99 1,600.00 4.50 3.99 1,599.85 5.87 0.41 5.89 2,267,318.76 240,097.54 3.00 3.00 0.00 0.00 1,700.00 7.50 3.99 1,699.29 16.30 1.14 16.34 2,267,329.17 240.098.49 3.00 3.00 0.00 0.00 1,800.00 10.50 3.99 1,798.04 31.90 2.22 31.98 2,267,344.75 240,099.91 3.00 3.00 0.00 0.00 1,900.00 13.50 3.99 1,895.85 52.64 3.67 52.77 2,267,365.45 240,101.81 3.00 3.00 0.00 0.00 2,000.00 16.50 3.99 1,992.43 78.46 5.47 78.65 2,267,391.22 240,104.17 3.00 3.00 0.00 0.00 2,100.00 19.50 3.99 2,087.52 109.28 7.62 109.55 2,267,421.99 240,106.98 3.00 3.00 0.00 0.00 2,200.00 22.50 3.99 2,180.87 145.03 10.11 145.38 2,267,457.67 240,110.25 3.00 3.00 0.00 0.00 2,300.00 25.50 3.99 2,272.22 185.60 12.94 186.05 2,267,498.17 240,113.95 3.00 3.00 0.00 0.00 2,400.00 28.50 3.99 2,361.31 230.88 16.10 231.44 2,267,543.37 240,118.09 3.00 3.00 0.00 0.00 2,465.18 30.46 3.99 2,418.05 262.88 18.33 263.51 2,267,575.31 240,121.01 3.00 3.00 0.00 0.00 End Dir : 2465.18' MD, 2418.06' TVD 2,500.00 30.46 3.99 2,448.06 280.48 19.56 281.16 2,267,592.89 240,122.62 0.00 0.00 0.00 0.00 2,570.69 30.46 3.99 2,509.00 316.23 22.05 317.00 2,267,628.57 240,125.88 0.00 0.00 0.00 0.00 BELUGA 2,600.00 30.46 3.99 2,534.26 331.05 23.08 331.85 2,267,643.36 240,127.24 0.00 0.00 0.00 0.00 2,700.00 30.46 3.99 2,620.47 381.61 26.61 382.54 2,267,693+84 240,131.86 0.00 0.00 0.00 0.00 2,800.00 30.46 3.99 2,706.67 432.18 30.13 433.22 2,267,744.31 240,136.47 0.00 0.00 0.00 0.00 2,900.00 30.46 3.99 2,792.87 482.74 33.66 483.91 2,267,794.79 240,141.09 0.00 0.00 0.00 0.00 3,000.00 30.46 3.99 2,879.07 533.30 37.18 534.60 2,267,845.26 240,145.71 0.00 0.00 0.00 0.00 3,100.00 30.46 3.99 2,965.28 583.87 40.71 585.28 2,267,895.74 240,150.33 0.00 0.00 0.00 0.00 3,200.00 30.46 3.99 3,051.48 634.43 44.23 635.97 2,267,946.21 240,154.95 0.00 0.00 0.00 0.00 3,300.00 30.46 3.99 3,137.68 685.00 47.76 686.66 2,267,996.69 240,159.57 0.00 0.00 0.00 0.00 3,400+00 30.46 3.99 3,223.88 735.56 51.28 737.35 2,268,047+16 240,164.18 0.00 0.00 000 0.00 3,500.00 30.46 3.99 3,310.08 786.12 54.81 788.03 2,268,097.64 240,168.80 0.00 0.00 0.00 0.00 3,600.00 30.46 3.99 3,396.29 836.69 58.34 838.72 2,268,148.11 240,173.42 0.00 0.00 0.00 0.00 9 5/8" 3,700.00 30.46 3.99 3,482.49 887.25 61.86 889.41 2,268,198.59 240,178.04 0.00 0.00 0.00 0.00 3,744.67 30.46 3.99 3,521.00 909.84 63.44 912.05 2,268,221.13 240,180.10 0.00 0.00 0.00 0.00 Beluga50 24 June, 2014 - 10:10 Page 2 of 6 COMPASS i ^w, Hilcorp Energy Company HALLIBURTOAI ! SP'rr'-•V 0"11"'g I Ninilchik Unit Plan Proposal Report for Frances 2 - Frances 2 wp1.0 Survey Stations Measured Vertical Vertical Dogleg Build Turn Toolface Depth INC AZM Depth +N/-S +E/-W Section Northing Easting Rate Rate Rate Azimuth (usft) (°) (°) (usft) (usft) (usft) (usft) (usft) (usft) (°/100usft) (°1100usft) (°/100usft) (°) 3,800.00 30.46 3.99 3,568.69 937.82 65.39 940.09 2,268,249.06 240,182.66 0.00 0.00 0.00 0.00 3,900.00 30.46 3.99 3,654.89 988.38 68.91 990.78 2,268,299.53 240,187.28 0.00 0.00 0.00 0.00 4,000.00 30.46 3.99 3,741.10 1,038.94 72.44 1,041.47 2,268,350.01 240,191.89 0.00 0.00 0.00 0.00 4,100.00 30.46 3.99 3,827.30 1,089.51 75.96 1,092.15 2,268,400.48 240,196.51 0.00 0.00 0.00 0.00 4,200.00 30.46 3.99 3,913.50 1,140.07 79.49 1,142.84 2,268,450.96 240,201.13 0.00 0.00 0.00 0.00 4,300.00 30.46 3.99 3,999.70 1,190.64 83.01 1,193.53 2,268,501.43 240,205.75 0.00 0.00 0.00 0.00 4,400.00 30.46 3.99 4,085.91 1,241.20 86.54 1,244.21 2,268,551.91 240,210.37 0.00 0.00 0.00 0.00 4,500.00 30.46 3.99 4,172.11 1,291.76 90.06 1,294+90 2,268,602.38 240,214.99 0.00 0.00 0.00 0.00 4,600.00 30.46 3.99 4,258.31 1,342.33 93.59 1,345.59 2,268,652.86 240,219.60 0.00 0.00 0.00 0.00 4,700.00 30.46 3.99 4,344.51 1,392.89 97.12 1,396.27 2,268.703.33 240,224.22 0.00 0.00 0.00 0.00 4,800.00 30.46 3.99 4,430.72 1,443.46 100.64 1,446.96 2,268,753.81 240,228.84 0.00 0.00 0.00 0.00 4,900.00 30.46 3.99 4,516.92 1,494.02 104.17 1,497.65 2,268,804.28 240,233.46 0.00 0.00 0.00 0.00 5,000.00 30.46 3.99 4,603.12 1,544.58 107.69 1,548.33 2,268,854.76 240,238+08 0.00 0.00 0.00 0.00 5,100.00 30.46 3.99 4,689.32 1,595.15 111.22 1,599.02 2,268,905.23 240,242.70 0.00 0.00 0.00 0.00 5,200.00 30.46 3.99 4,775.53 1,645.71 114.74 1,649.71 2,268,955.71 240,247.32 0.00 0.00 0.00 0.00 5,300.00 30.46 3.99 4,861+73 1,696.28 118.27 1,700.39 2,269,006.18 240,251.93 0.00 0.00 0.00 0.00 5,400.00 30.46 3.99 4,947.93 1,746.84 121.79 1,751.08 2,269,056.66 240,256.55 0.00 0.00 0.00 0.00 5,500.00 30.46 3.99 5,034.13 1,797.40 125.32 1,801.77 2,269,107.13 240,261.17 0.00 0.00 0.00 0.00 5,519.57 30.46 3.99 5,051.00 1,807.30 126.01 1,811.69 2,269,117.01 240,262.07 0.00 0.00 0.00 0.00 Beluga 135 5,600.00 30.46 3.99 5,120.33 1,847.97 128.84 1,852.45 2,269,157.61 240,265.79 0.00 0.00 0.00 0.00 5,700+00 30.46 3.99 5,206.54 1,898+53 132.37 1,903.14 2,269,208.08 240,270.41 0.00 0.00 0.00 0.00 5,782.90 30.46 3.99 5,278.00 1,940.45 135.29 1,945.16 2,269,249.93 240,274.24 0.00 0.00 0.00 0.00 Tyonek 5,800.00 30.46 3.99 5,292.74 1.949.10 135.90 1,953.83 2,269,258.56 240,275.03 0.00 0.00 0.00 0.00 5,900.00 30.46 3.99 5,378.94 1,999.66 139.42 2.004.52 2,269,309.03 240,279.64 0.00 0.00 0.00 0.00 6,000.00 30.46 3.99 5,465.14 2,050.22 142.95 2,055.20 2,269,359.51 240,284.26 0.00 0.00 0.00 0.00 6,100.00 30.46 3.99 5,551.35 2,100.79 146.47 2,105.89 2,269,409.98 240,288.88 0.00 0.00 0.00 0.00 6,200.00 30.46 3.99 5,637.55 2,151.35 150.00 2,156+58 2,269,460+45 240,293+50 0.00 0.00 0.00 0.00 6,300.00 30.46 3.99 5,723.75 2,201.92 153.52 2,207+26 2,269,510.93 240,298.12 0.00 0.00 0.00 0.00 6,400.00 30.46 3.99 5,809.95 2,252.48 157.05 2,257+95 2,269,561.40 240,302.74 0.00 0.00 0.00 0.00 6,500.00 30.46 3.99 5,896.16 2,303.04 160.57 2,308.64 2,269,611.88 240,307.35 0.00 0.00 0.00 0.00 6,600.00 30.46 3.99 5,982.36 2,353.61 164.10 2,359+32 2,269,662.35 240,311.97 0.00 0.00 0.00 0.00 6,677.31 30.46 3.99 6,049.00 2,392.70 166.82 2,398+51 2,269,701.38 240,315.54 0.00 0.00 0.00 0.00 T-8 6,700.00 30.46 3.99 6,068.56 2,404.17 167.62 2,410.01 2,269,712.83 240,316.59 0.00 0.00 0.00 0.00 6,800.00 30.46 3.99 6,154.76 2,454.74 171.15 2,460.70 2,269,763.30 240,321.21 0.00 0.00 0.00 0.00 6,900.00 30.46 3.99 6,240.97 2,505.30 174.68 2,511.38 2,269,813.78 240,325.83 0.00 0.00 0.00 0.00 6,962.68 30.46 3.99 6,295.00 2,537.00 176.89 2,543.16 2,269,845.42 240,328.72 0.00 0.00 0.00 0.00 T-10 7,000.00 30.46 3.99 6,327+17 2,555+87 178.20 2,562+07 2,269,864.25 240,330.45 0.00 0.00 0.00 0.00 7,100.00 30.46 3.99 6,413.37 2,606.43 181.73 2,612.76 2,269,914.73 240,335.06 0.00 0.00 0.00 0.00 7,200.00 30.46 3.99 6,499.57 2,656.99 185.25 2,663.44 2,269,965.20 240,339.68 0.00 0.00 0.00 0.00 7,300.00 30.46 3.99 6,585.77 2,707.56 188.78 2,714.13 2,270,015.68 240,344.30 0.00 0.00 0.00 0.00 7,400.00 30.46 3.99 6,671.98 2,758+12 192.30 2,764+82 2,270,066.15 240,348.92 0.00 0.00 0.00 0.00 7,500.00 30.46 3.99 6,758.18 2,808.69 195.83 2,815+50 2,270,116.63 240,353.54 0.00 0.00 0.00 0.00 7,600.00 30.46 3.99 6,844.38 2,859.25 199.35 2,866+19 2,270,167.10 240,358.16 0.00 0.00 0.00 0.00 7,700.00 30.46 3.99 6,930.58 2,909.81 202.88 2,916.88 2,270,217.58 240,362.78 0.00 0.00 0.00 0.00 7,800.00 30.46 3.99 7,016.79 2,960+38 206.40 2,967+56 2,270,268.05 240,367.39 0.00 0.00 0.00 0.00 24 June, 2014 - 10:10 Page 3 of 6 COMPASS f Hilcorp Energy Company HALL.IBURTON I Sp,-,r°ry Orillin Ninilchik Unit Plan Proposal Report for Frances 2 - Frances 2 wp1.0 Survey Stations Measured Vertical Vertical Dogleg Build Turn Toolface Depth INC AZM Depth +N/-S +E/-W Section Northing Easting Rate Rate Rate Azimuth (usft) (°) (°) (usft) (usft) (usft) (usft) (usft) (usft) (°/100usft) (°/100usft) (°/100usft) (°) 7,900.00 30.46 3.99 7,102.99 3,010.94 209.93 3,018.25 2,270,318.53 240,372.01 0.00 0.00 0.00 0.00 8,000.00 30.46 3.99 7,189.19 3,061.51 213.46 3,068.94 2,270,369.00 240,376.63 0.00 0.00 0.00 0.00 8,100.00 30.46 3.99 7,275.39 3,112.07 216.98 3,119.62 2,270,419.48 240,381.25 0.00 0.00 0.00 0.00 8,200.00 30.46 3.99 7,361.60 3,162.63 220.51 3,170.31 2,270,469.95 240,385.87 0.00 0.00 0.00 0.00 8,300.00 30.46 3.99 7,447.80 3,213.20 224.03 3,221.00 2,270,520.43 240,390.49 0.00 0.00 0.00 0.00 8,400.00 30.46 3.99 7,534.00 3,263.76 227.56 3,271.69 2,270,570.90 240,395.10 0.00 0.00 0.00 0.00 8,466.12 30.46 3.99 7,591.00 3,297.20 229.89 3,305.20 2,270,604.27 240,398.16 0.00 0.00 0.00 0.00 T-50 8,500.00 30.46 3.99 7,620.20 3,314.33 231.08 3,322.37 2,270,621.37 240,399.72 0.00 0.00 0.00 0.00 8,600.00 30.46 3.99 7,706.41 3,364.89 234.61 3,373.06 2,270,671.85 240,404.34 0.00 0.00 0.00 0.00 8,685.37 30.46 3.99 7,780.00 3,408.06 237.62 3.416.33 2,270,714.94 240,408.28 0.00 0.00 0.00 0.00 T-60 8,700.00 30.46 3.99 7,792.61 3,415.45 238.13 3,423.75 2,270,722.32 240,408.96 0.00 0.00 0.00 0.00 8,800.00 30.46 3.99 7,878.81 3,466.02 241.66 3,474.43 2,270,772.80 240,413.58 0.00 0.00 0.00 0.00 8,900.00 30.46 3.99 7,965.01 3,516.58 245.18 3,525.12 2,270,823.27 240,418.20 0.00 0.00 0.00 0.00 9,000.00 30.46 3.99 8,051.22 3,567.15 248.71 3,575.81 2,270,873.75 240,422.81 0.00 0.00 0.00 0.00 9,100.00 30.46 3.99 8,137.42 3,617.71 252.23 3,626.49 2,270,924.22 240,427.43 0.00 0.00 0.00 0.00 9,148.24 30.46 3.99 8,179.00 3,642.10 253.94 3,650.94 2,270,948.57 240,429.66 0.00 0.00 0.00 0.00 T-65 9,200.00 30.46 3.99 8,223.62 3,668.27 255.76 3,677.18 2,270,974.70 240,432.05 0.00 0.00 0.00 0.00 . 9,242.20 30.46 3.99 8,260.00 - 3,689.61 257.25 3,698.57 2,270,996.00 240,434.00 0.00 0.00 0.00 0.00 Total Depth : 9242.20' MD, 8260' TV , - 5 1/2" 24 June, 2014 - 10.10 Page 4 of 6 COMPASS HALT„ IBURTON I Sperry Orilling Plan Proposal Report for Frances 2 - Frances 2 wp1.0 Plan Annotations Measured Vertical Depth Depth (usft) (usft) 1,450.00 1,450.00 2,465.18 2,418.05 9,242.20 8,260.00 Vertical Section Information Angle Type Local Coordinates +N/-S +E/-W Comment (usft) (usft) 0.00 0.00 Start Dir 21/100' : 1450' MD, 1450'TVD 262.88 18.33 End Dir : 2465.18' MD, 2418.05' TVD 3,689.61 257.25 Total Depth : 9242.20' MD, 8260' TVD Target TD No Target (Freehand) SUrVeV tool program From To (usft) (usft) 18.00 3,600.00 Frances 2 wp1.0 3,600.00 9,242.20 Frances 2 wpl.0 Casing Details Measured Vertical Depth Depth (usft) (usft) 3,600.00 3,396.29 9 5/8" 9,242.20 8,260.00 51/2" Formation Details Measured Vertical Depth Depth (usft) (usft) 2,570.69 2,509.00 BELUGA 3,744.67 3,521.00 Beluga-50 5,519.57 5,051.00 Beluga 135 5,782.90 5,278.00 Tyonek 6,677.31 6,049.00 T-8 6,962.68 6,295.00 T-10 8,466.12 7,591.00 T-50 8,685.37 7,780.00 T-60 9,148.24 8,179.00 T-65 Targets associated with this wellbore Target Name Frances 2 BHL Tgt Frances 2 Mid Tgt Azimuth Origin (°) Type 3.99 Slot Survey/Plan Hilcorp Energy Company Ninilchik Unit Origin Start +N/_S +E/-W TVD (usft) (usft) (usft) 0.00 0.00 18.00 Survey Tool M W D+S C+sag M W D+S C+sag Casing Hole Name Diameter Diameter 9-5/8 12-1/4 5-1/2 8-1/2 Dip Name Lithology Dip Direction (°) (°) TVD +N/-S +E/-W (usft) (usft) (usft) Shape 8,260.00 3,689.61 257.25 Circle 6,260.00 2,516.31 175.51 Point 24 June, 2014 - 10:10 Page 5 of 6 COMPASS HQLLIBURTON I Seer"Y Eir•fl""g Hilcorp Energy Company Ninilchik Unit North Reference Sheet for Falls Creek - Frances 2 - Frances 2 All data is in US Feet unless otherwise stated. Directions and Coordinates are relative to True North Reference. Vertical Depths are relative to Prelim: Frances 2 @ 278.00usft. Northing and Easting are relative to Frances 2 Coordinate System is US State Plane 1927 (Exact solution), Alaska Zone 04 using datum NAD 1927 (NADCON CONUS), ellipsoid Clarke 1866 Projection method is Transverse Mercator (Gauss -Kruger) Central Meridian is-150.00°, Longitude Origin:0.000000°, Latitude Origin:0.000000° False Easting: 500,000.00usft, False Northing: 0.00usft, Scale Reduction: 0.99997688 Grid Coordinates of Well: 2,267,312.90 usft N, 240,097.00 usft E Geographical Coordinates of Well: 600 11' 54.85" N, 1510 25' 42.30" W Grid Convergence at Surface is: -1.24' Based upon Minimum Curvature type calculations, at a Measured Depth of 9,242.20usft the Bottom Hole Displacement is 3,698.57usft in the Direction of 3.99' (True). Magnetic Convergence at surface is: -18.01 ° (19 June 2014, , BGGM2014) T Magnetic Model: BGGM U14 M Date: 19-Arl-14 Declination: 16.77— Inclination/Dip: 7321' Field Strength: 55247 Grid North is 1.24' West of True North (Grid Convergence) Magnetic North is 16.77' East of True North (Magnetic Declination) Magnetic North is 18.01° East of Grid North (Magnetic Convergence) To convert a True Diiedion to a Grid Direction, Add 1.24' To convert a Magnetic Direction to a True Direction, Add 16.77' East To convert a Magnetic Direction to a Grid Direction, Add 18.01 ° 24 June, 2014 - 10:10 Page 6 of 6 COMPASS CD O_ W N - O 1D Gc JC, V. A W N — O IC oo J Cl �A A W I 1 W W WIW W W W W W N N N N IV N N N N' N N N J 01 Vi A W N --� O C C Oo J i l A A W I N � O i CD 00 A I A w N -• C 00 J CT `A w N O O O! O O CD w C:,C, C> CD I C) O O O 'O O,O to O O O O. pip p O_.O O O O.O O'O O O,,O O Cl O O C O O CO O O Q O 00 C . O. O O;000 .O O C:, C:, O Q�p a, CO O_.O.O o'.0 Cl O. O O!O. 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N O O m m Qoornm oomm U00010 C O O T V 0000 M M ❑ 000�0 O UOJ CO7 � N m O o oo LO N 0 t7 O QO N V Lfj U O N O N � a W r Q D —1 W m O W N ~ \0 Ln Ln 1 O T iT O N n m fT N m QI C L L L w CL 0 0 0 0 0 0 0 0 0 0 0 Ln to 0 Ln o Ln o Ln 0 Ln r L` 1 N O n Ln N 0 n N M M V LO t0 co (u!/ljsn 00S6) uldaa leoivan anal w �> j� too d N N Y i v1 LA zmm Q H NN„3„ N Z C C Q 1O L 3 Z�I �L=LN a"icc� LL LL E LL�EE a>d C d_c V U U O C C C L `m d dg o C7 W❑L N 1r Q U N H / J S LO m � N 0 �— m CD (DLn U ~ C F" [6 LL 0 0 O Ln o n lA W HALLIBURTON Sperry Drilling Project: Ninilchik Uni Site: Falls Creek Well: Frances 2 ellbore: Frances 2 Frances 2 wpl.0 COMPANY DETAILS: Hilcorp Energy Company Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Closest Approach 3D Error Surface: Elliptical Conic Warning Method: Error Ratio L CASING DETAILS D MD Name Size 3396.29 3600.00 9 5/8" 9-5 8 8260.00 9242.20 5 1/2" 5-1 2 WELL DifFrances 2 Ground Level: 260.00 +N--S +E/-W Northing Easting Latittude Longitude Slot 0.00 0,00 2267312.90 240097.00 60-19856843-151.42841765 SECTION DETAILS Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target 1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00 21450.00 0.00 0.00 1450.00 0.00 0.00 0.00 0.00 0.00 3 2465.18 30.46 3.99 2418.05 262.88 18.33 3.00 3.99 263.52 49242.20 30,46 3.99 8260.00 3689,61 257.25 0.00 0.00 3698.57 Frances 2 BHL Tgt SURVEY PROGRAM Date: 2014-06-20T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 18.00 3600.00 Frances 2 wp1.0 (Frances 2) MWD+SC+sag 3600.00 9242.20 Frances 2 wp1.0 (Frances 2) MWD+SC+sag REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well Frances 2, True North Vertical (TVD) Reference: Prelim: Frances 2 @ 278.00usft Measured Depth Reference: Prelim: Frances 2 @ 278.00usft Calculation Method: Minimum Curvature -1960 -1680 -1400 -1120 -840 -560 -280 0 280 560 840 1120 1400 1680 1960 2240 2520 2800 3080 West( -)/East(+) (700 usft/in) HALLIBURTON Halliburton Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Ninilchik Unit Site: Bartolowits Pad Well: Frances #2 Wellbore: Frances #2 Design: Frances #2 wpl.0 Local Co-ordinate Reference: Well Frances #2 TVD Reference: Prelim: Frances 2 @ 278.00usft MD Reference: Prelim: Frances 2 @ 278.00usft North Reference: True Survey Calculation Method: Minimum Curvature Project Ninilchik Unit 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 Bartolowits Pad Site Position: Northing: From: Map Easting: Position Uncertainty: 0.00 usft Slot Radius: Well Frances #2 Well Position +N/-S 0.00 usft Northing: +E/-W 0.00 usft Easting: Position Uncertainty 0.00 usft Wellhead Elevation Wellbore Frances #2 Magnetics Model Name Sample Date BGGM2014 6/19/2014 Design Frances #2 wpl.0 Audit Notes: 2.267,300.00usft Latitude: 240,000.00usft Longitude: 13-3/16" Grid Convergence: 2,267,312.90 usfl Latitude: 240.097.00 usfl Longitude: 0.00 usfl Ground Level: Declination 16.77 Version: Phase: PLAN Vertical Section: Depth From (TVD) +N/-S (usft) (usft) 18.00 0.00 Plan Sections Measured Vertical TVD Depth Inclination Azimuth Depth System +N/-S (usft) (°) (°) (usft) usft (usft) 18.00 0.00 0.00 18.00 -260.00 0.00 1,450.00 0.00 0.00 1,450.00 1,172.00 0.00 2,465.18 30.46 3.99 2,418.05 2,140.05 262.88 9,242.20 30.46 3.99 8,260.00 7,982.00 3,689.61 Dip Angle 73.21 Tie On Depth: 18.00 +E/-W Direction (usft) (°) 0.00 3.99 60.19852741 151.42894903 -1.24 ° 60.19856843 151.42841765 260.00 usft Field Strength (nT) 55,247 Dogleg Build Turn +E/-W Rate Rate Rate Tool Face (usft) (°/100usft) (°/100usft) (°/100usft) (°) 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 18.33 3.00 3.00 0.39 3.99 257.25 0.00 0.00 0.00 0.00 711812014 4:19:28PM Page 2 COMPASS 5000.1 Build 70 HALLIBURTON Halliburton Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Frances #2 Company: Hilcorp Energy Company TVD Reference: Prelim: Frances 2 @ 278.00usft Project: Ninilchik Unit MD Reference: Prelim: Frances 2 @ 278.00usft Site: Bartolowits Pad North Reference: True Well: Frances #2 Survey Calculation Method: Minimum Curvature Wellbore: Frances #2 Design: Frances #2 wpl .0 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -278.00 0.00 0.00 0.00 0.00 -278.00 0.00 0.00 2.267.312.90 240.097.00 0.00 0.00 18.00 0.00 0.00 18.00 -260.00 0.00 0.00 2,267.312.90 240,097.00 0.00 0.00 100.00 0.00 0.00 100.00 -178.00 0.00 0.00 2,267.312.90 240,097.00 0.00 0.00 200.00 0.00 0.00 200.00 -78.00 0.00 0.00 2,267.312.90 240.097.00 0.00 0.00 300.00 0.00 0.00 300.00 22.00 0.00 0.00 2.267.312.90 240,097.00 0.00 0.00 400,00 0.00 0.00 400.00 122.00 0.00 0.00 2,267.312.90 240,097.00 0.00 0.00 500.00 0.00 0.00 500.00 222.00 0.00 0.00 2,267.312.90 240,097.00 0.00 0.00 600.00 0.00 0.00 600.00 322.00 0.00 0.00 2.267.312.90 240.097.00 0.00 0.00 700.00 0.00 0.00 700.00 422.00 0.00 0.00 2,267.312.90 240.097.00 0.00 0.00 800.00 0.00 0.00 800.00 522.00 0.00 0.00 2.267.312,90 240.097.00 0.00 0.00 900.00 0.00 0.00 900.00 622.00 0.00 0.00 2,267.312.90 240,097.00 0.00 0.00 1,000.00 0.00 0.00 1.000.00 722.00 0.00 0.00 2,267.312.90 240,097.00 0.00 0.00 1,100.00 0.00 0.00 1.100.00 822.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 1,200.00 0.00 0.00 1,200.00 922.00 0.00 0.00 2,267,312.90 240.097.00 0.00 0.00 1,300.00 0.00 0.00 1,300.00 1.022.00 0.00 0.00 2,267,312.90 240.097.00 0.00 0.00 1,400.00 0.00 0.00 1,400.00 1.122.00 0.00 0.00 2,267.312.90 240,097.00 0.00 0.00 1,450.00 0.00 0.00 1,450.00 1,172.00 0.00 0.00 2,267,312.90 240,097.00 0.00 0.00 Start Dir 2°/100' : 1450' MD, 1450'TVD 1,500.00 1.50 3.99 1A99.99 1,221.99 0.65 0.05 2,267,313.55 240,097.06 3.00 0.65 1,600.00 4.50 3.99 1.599.85 1,321.85 5.87 0.41 2,267,318.76 240,097.54 3.00 5.89 1,700.00 7.50 3.99 1.699.29 1,421.29 16.30 1.14 2,267,329.17 240,098.49 3.00 16.34 1.800.00 10.50 3.99 1,798.04 1,520.04 31.90 2.22 2,267,344.75 240,099.91 3.00 31.98 1,900.00 13.50 3.99 1,895.85 1,617.85 52.64 3.67 2,267,365.45 240,101.81 3.00 52.77 2,000.00 16.50 3.99 1,992.43 1,714.43 78.46 5.47 2,267,391.22 240,104.17 3.00 78.65 2,100.00 19.50 3.99 2,087.52 1,809.52 109.28 7.62 2,267,421.99 240,106.98 3.00 109.55 2,200.00 22.50 3.99 2,180.87 1,902.87 145.03 10.11 2,267,457.67 240,110.25 3.00 145.38 2,300.00 25.50 3.99 2,272.22 1,994.22 185.60 12.94 2,267,498.17 240.113.95 3.00 186.05 2,400.00 28.50 3.99 2361.31 2,083.31 230.88 16.10 2,267,543.37 240,118.09 3.00 231.44 2,465.18 30.46 3.99 2,418.05 2,140.05 262.88 18.33 2,267,575.31 240,121.01 3.00 263.51 End Dir : 2465.18' MD, 2418.05' TVD 2,500.00 30.46 3.99 2,448.06 2,170.06 280.48 19.56 2,267,592.89 240,122.62 0.00 281.16 2,570.69 30.46 3.99 2,509.00 2,231.00 316.23 22.05 2,267,628.57 240,125.88 0.00 317.00 BELUGA 2,600.00 30.46 3.99 2,534.26 2,256.26 331.05 23.08 2,267,643.36 240,127.24 0.00 331.85 2,700.00 30.46 3.99 2,620.47 2,342.47 381.61 26.61 2,267,693.84 240,131.86 0.00 382.54 2,800.00 30.46 3.99 2,706.67 2,428.67 432.18 30.13 2,267,744.31 240,136.47 0.00 433.22 2,900.00 30.46 3.99 2,792.87 2,514.87 482.74 33.66 2,267,794.79 240,141.09 0.00 483.91 3,000.00 30.46 3.99 2,879.07 2,601.07 533.30 37.18 2,267,845.26 240,145.71 0.00 534.60 3,100.00 30.46 3.99 2,965.28 2,687.28 583.87 40.71 2,267,895.74 240,150.33 0.00 585.28 3,200.00 30.46 3.99 3,051.48 2,773.48 634.43 44.23 2,267,946.21 240,154.95 0.00 635.97 3,300.00 30.46 3.99 3,137.68 2,859.68 685.00 47.76 2,267,996.69 240,159.57 0.00 686.66 3,400.00 30.46 3.99 3,223.88 2,945.88 735.56 51.28 2,268,047.16 240,164.18 0.00 737.35 3,500.00 30.46 3.99 3,310.08 3,032.08 786.12 54.81 2,268,097.64 240,168.80 0.00 788.03 3,600.00 30.46 3.99 3,396.29 3,118.29 836.69 58.34 2,268,148.11 240,173.42 0.00 838.72 9 5/8" 711812014 4:19:28PM Page 3 COMPASS 5000.1 Build 70 HALLIBURTON Halliburton Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Ninilchik Unit Site: Bartolowits Pad Well: Frances #2 Wellbore: Frances #2 Design: Frances #2 wpl.0 Planned Survey Measured Depth Inclination Azimuth (usft) (°) (°) 3,700.00 30.46 3.99 3.744.67 30.46 3.99 Beluga-50 3.800.00 3.900.00 4,000.00 4,100.00 4.200.00 4,300.00 4A00.00 4,500.00 4,600.00 4,700.00 4,800.00 4,900.00 5,000.00 5,100.00 5,200.00 5,300.00 5.400.00 5,500.00 5,519.57 Beluga 135 5,600.00 5,700.00 5,782.90 Tyonek 5,800.00 5,900.00 6,000.00 6,100.00 6,200.00 6,300.00 6,400.00 6,500.00 6,600.00 6,677.31 T-8 6,700.00 6,800.00 6,900.00 6,962.68 T-10 7,000.00 7.100.00 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Well Frances #2 Prelim: Frances 2 @ 278.00usft Prelim: Frances 2 @ 278.00usft True Minimum Curvature Vertical Map Map Depth TVDss +N/-S +El-W Northing Easting DLS Vert Section (usft) usft (usft) (usft) (usft) (usft) 3,204.49 3.482.49 3.204.49 887.25 61.86 2,268.198.59 240,178.04 0.00 889.41 3.521.00 3.243.00 909.84 63.44 2,268,221.13 240,180.10 0.00 912.05 30.46 3.99 3.568.69 3.290.69 937.82 65.39 2,268.249.06 240.182.66 0.00 940.09 30.46 3.99 3.654.89 3.376.89 988.38 68.91 2,268.299.53 240.187.28 0.00 990.78 30.46 3.99 3,741.10 3,463.10 1.038.94 72.44 2,268.350.01 240.191.89 0.00 1,041.47 30.46 3.99 3.827.30 3.549.30 1.089.51 75.96 2,268.400.48 240.196.51 0.00 1,092.15 30.46 3.99 3.913.50 3,635.50 1.140.07 79.49 2,268,450.96 240,201.13 0.00 1,142.84 30.46 3.99 3.999.70 3,721.70 1,190.64 83.01 2.268.501.43 240.205.75 0.00 1.193.53 30.46 3.99 4,085.91 3,807.91 1.241.20 86.54 2,268,551.91 240.210.37 0.00 1,244.21 30.46 3.99 4.172.11 3.894.11 1.291.76 90.06 2,268.602.38 240.214.99 0.00 1,294.90 30.46 3.99 4258.31 3.980.31 1.342.33 93.59 2.268.652.86 240.219.60 0.00 1,345.59 30.46 3.99 4.344.51 4,066.51 1.392.89 97.12 2,268,703.33 240.224.22 0.00 1.396.27 30.46 3.99 4,430.72 4,152.72 1.443.46 100.64 2,268,753.81 240.228.84 0.00 1.446.96 30.46 3.99 4,516.92 4.238.92 1.494.02 104.17 2.268,804.28 240,233.46 0.00 1.497.65 30.46 3.99 4,603.12 4,325.12 1,544.58 107.69 2,268,854.76 240,238.08 0.00 1.548.33 30.46 3.99 4.689.32 4,411.32 1,595.15 111.22 2,268,905.23 240,242.70 0.00 1,599.02 30.46 3.99 4,775.53 4,497.53 1,645.71 114.74 2,268,955.71 240,247.32 0.00 1,649.71 30.46 3.99 4,861.73 4,583.73 1,696.28 118.27 2,269,006.18 240,251.93 0.00 1,700.39 30.46 3.99 4,947.93 4,669.93 1,746.84 121.79 2,269,056.66 240,256.55 0.00 1,751.08 30.46 3.99 5,034.13 4,756.13 1,797.40 125.32 2,269.107.13 240,261.17 0.00 1,801.77 30.46 3.99 5,051.00 4.773.00 1,807.30 126.01 27269,117.01 240,262.07 0.00 1,811.69 30.46 3.99 5,120.33 4,842.33 1,847.97 128.84 2,269,157.61 240,265.79 0.00 1,852.45 30.46 3.99 5,206.54 4,928.54 1,898.53 132.37 2,269,208.08 240,270.41 0.00 1,903.14 30.46 3.99 5,278.00 5,000.00 1,940.45 135.29 2.269,249.93 240,274.24 0.00 1,945.16 30.46 3.99 5,292.74 5,014.74 1,949.10 135.90 2.269,258.56 240,275.03 0.00 1,953.83 30.46 3.99 5,378.94 5,100.94 1,999.66 139.42 2,269,309.03 240,279.64 0.00 2,004.52 30.46 3.99 5,465.14 5,187.14 2,050.22 142.95 2,269,359.51 240,284.26 0.00 2,055.20 30.46 3.99 5,551.35 5,273.35 2,100.79 146.47 2,269,409.98 240,288.88 0.00 2,105.89 30.46 3.99 5,637.55 5,359.55 2,151.35 150.00 2,269,460.45 240,293.50 0.00 2,156.58 30.46 3.99 5,723.75 5,445.75 2,201.92 153.52 2,269,510.93 240,298.12 0.00 2,207.26 30.46 3.99 5,809.95 5,531.95 2,252.48 157.05 2,269,561.40 240,302.74 0.00 2,257.95 30.46 3.99 5,896.16 5,618.16 2,303.04 160.57 2,269,611.88 240,307.35 0.00 2,308.64 30.46 3.99 5,982.36 5,704.36 2,353.61 164.10 2,269,662.35 240,311.97 0.00 2,359.32 30.46 3.99 6,049.00 5,771.00 2,392.70 166.82 2,269,701.38 240,315.54 0.00 2,398.51 30.46 3.99 6,068.56 5,790.56 2,404.17 167.62 2,269,712.83 240,316.59 0.00 2,410.01 30.46 3.99 6,154.76 5,876.76 2,454.74 171.15 2,269,763.30 240,321.21 0.00 2,460.70 30.46 3.99 6,240.97 5,962.97 2,505.30 174.68 2.269,813.78 240,325.83 0.00 2,511.38 30.46 3.99 6,295.00 6,017.00 2,537.00 176.89 2,269,845.42 240,328.72 0.00 2,543.16 30.46 3.99 6,327.17 6,049.17 2,555.87 178.20 2,269,864.25 240,330.45 0.00 2,562.07 30.46 3.99 6,413.37 6,135.37 2,606.43 181.73 2,269,914.73 240,335.06 0.00 2,612.76 711812014 4:19:28PM Page 4 COMPASS 5000.1 Build 70 HALLIBURTON Halliburton Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Company: Hilcorp Energy Company Project: Ninilchik Unit Site: Bartolowits Pad Well: Frances #2 Wellbore: Frances #2 Design: Frances #2 wpl.0 Planned Survey Measured Vertical Depth Inclination Azimuth Depth TVDss (usft) (°) (°) (usft) usft 7.200.00 30.46 3.99 6.499.57 6.221.57 7.300.00 30.46 3.99 6.585.77 6.307.77 7,400.00 30.46 3.99 6.671.98 6,393.98 7.500.00 30.46 3.99 6.758.18 6,480.18 7,600.00 30.46 3.99 6.844.38 6,566.38 7.700.00 30.46 3.99 6.930.58 6.652.58 7,800.00 30.46 3.99 7,016.79 6.738.79 7,900.00 30.46 3.99 7.102.99 6,824.99 8,000.00 30.46 3.99 7,189.19 6,911,19 8.100.00 30.46 3.99 7,275.39 6.997.39 8.200.00 30.46 3.99 7,361.60 7.083.60 8,300.00 30.46 3.99 7.447.80 7,169.80 8,400.00 30.46 3.99 7.534.00 7,256.00 8,466.12 30.46 3.99 7,591.00 7,313.00 T-50 8,500.00 30.46 3.99 7,620.20 7,342.20 8,600.00 30.46 3.99 7,706.41 7,428.41 8,685.37 30.46 3.99 7,780.00 7,502.00 T-60 8,700.00 30.46 3.99 7,792.61 7,514.61 8,800.00 30.46 3.99 7,878.81 7.600.81 8,900.00 30.46 3.99 7,965.01 7,687.01 9,000.00 30.46 3.99 8,051.22 7,773.22 9.100.00 30.46 3.99 8,137.42 7.859.42 9,148.24 30.46 3.99 8,179.00 7,901.00 T-65 9,200.00 30.46 3.99 8,223.62 7,945.62 9,242.20 30.46 3.99 8.260.00 7,982.00 Total Depth : 9242.20' MD, 8260' TVD - 5 1/2" Targets Target Name hit/miss target Shape Local Co-ordinate Reference: Well Frances #2 TVD Reference: Prelim: Frances 2 @ 278.00usft MD Reference: Prelim: Frances 2 @ 278.00usft North Reference: True Survey Calculation Method: Minimum Curvature Map Map +N/-S +E/-W Northing Easting DLS Vert Section (usft) (usft) (usft) (usft) 6,221.57 2,656.99 185.25 2,269,965.20 240,339.68 0.00 2.663.44 2.707.56 188.78 2,270.015.68 240,344.30 0.00 2,714.13 2.758.12 192.30 2,270.066.15 240.348.92 0.00 2,764.82 2,808.69 195.83 2.270,116.63 240.353.54 0.00 2,815.50 2.859.25 199.35 2.270,167.10 240.358.16 0.00 2.866.19 2.909.81 202.88 2270,217.58 240.362.78 0.00 2.916.88 2.960.38 206.40 2.270.268.05 240,367.39 0.00 2.967.56 3,010.94 209.93 2.270.318.53 240,372.01 0.00 3.018.25 1061.51 213.46 2,270.369.00 240,376.63 0.00 3,068.94 3.112.07 216.98 2,270.419.48 240,381.25 0.00 3.119.62 3.162.63 220.51 2,270.469.95 240.385.87 0.00 3.170.31 3.213.20 224.03 2.270,520.43 240,390.49 0.00 3,221.00 3,263.76 227.56 2,270,570.90 240.395.10 0.00 3,271.69 3,297.20 229.89 2,270,604.27 240.398.16 0.00 3.305.20 3,314.33 231.08 2,270,621.37 240,399.72 0.00 3,322.37 3.364.89 234.61 2,270.671.85 240,404.34 0.00 3,373.06 3,408.06 237.62 2,270,714.94 240,408.28 0.00 3,416.33 3,415.45 238.13 2,270,722.32 240,408.96 0.00 3,423.75 3,466.02 241.66 2,270,772.80 240,413.58 0.00 3,474.43 3,516.58 245.18 2,270,823.27 240,418.20 0.00 3,525.12 3.567.15 248.71 2,270,873.75 240,422.81 0.00 3,575.81 3,617.71 252.23 2.270,924.22 240,427.43 0.00 3,626.49 3,642.10 253.94 2,270,948.57 240,429.66 0.00 3.650.94 3,668.27 255.76 2.270,974.70 240,432.05 0.00 3,677.18 3,689.61 257.25 2,270,996.00 240,434.00 0.00 3,698.57 Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Easting (°) (°) (usft) (usft) (usft) (usft) (usft) Frances 2 BHL Tqt 0.00 0.00 8,260.00 3,689.61 plan hits target center Circle (radius 100.00) Frances 2 Mid Tgt 0.00 0.00 6,260.00 2,516.31 plan misses target center by 0.15usft at 6922.00usft MD (6259.93 TVD, 2516.43 N, 175.45 E) Point 257.25 2,270,996.00 240,434.00 175.51 2,269,824.77 240,326.90 711812014 4:19:28PM Page 5 COMPASS 5000.1 Build 70 HALLIBURTON Halliburton Standard Proposal Report Database: Sperry EDM - NORTH US + CANADA Local Co-ordinate Reference: Well Frances #2 Company: Hilcorp Energy Company TVD Reference: Prelim: Frances 2 @ 278.00usft Project: Ninilchik Unit MD Reference: Prelim: Frances 2 @ 278.00usft Site: Bartolowits Pad North Reference: True Well: Frances #2 Survey Calculation Method: Minimum Curvature Wellbore: Frances #2 Design: Frances #2 wpl .0 Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name (") (") 3.600.00 3,396.29 9 5/8" 9-5/8 12-1/4 9,242.20 8,260.00 51/2" 5-1/2 8-1/2 Formations Measured Vertical Depth Depth (usft) (usft) 2.570.69 2.509.00 6,962.68 6.295.00 8.466.12 7,591.00 8,685.37 7.780.00 5,519.57 5.051.00 6,677.31 6.049.00 3,744.67 3,521.00 5,782.90 5,278.00 9,148.24 8,179.00 Plan Annotations Measured Vertical Depth Depth (usft) (usft) 1,450.00 1,450.00 2,465.18 2,418.05 9,242.20 8,260.00 Vertical Depth SS BELUGA T-10 T-50 T-60 Beluga 135 T-8 Beluga-50 Tyonek T-65 Name Dip Dip Direction Lithology (1) (1) Local Coordinates +N/-S +E/-W (usft) (usft) Comment 0.00 0.00 Start Dir 2'/100' : 1450' MD, 1450'TVD 262.88 18.33 End Dir : 2465.18' MD, 2418.05' TVD 3.689.61 257.25 Total Depth: 9242.20' MD, 8260' TVD 711812014 4:19:28PM Page 6 COMPASS 5000.1 Build 70 v a+ c N 0 O O_ U a) C U N C � O C M G N is 3 v o c o x N N O ® � d N L O S E � N L O ik N N c I � N T V ' O O r w 3 Z 2 En E U �! 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Cl! N Z moia 0 m O N M N � CD 5 O O R a- O U) C 0 O y Q (D3 d IA Q c m m Z a m m O a)Y y d = = to U U rY io N a r 0 0 m M o0 V Cl) o0 V (f') 0 0 r (D 0o r (D o0 a1 oo Lf) o0 o0 D) co 0o 0) N N M V V 'V V V' V V V' V 00 C) 0 00 O O M O O (D O O (D O O V O O N u0 O N Ln O co (f) LO (D (D r (D (D r Nr V' (n LO Cl) to (n M O V LO O Lo (9 ClCDo0 co (D 00 to (D oo o 0 o (n LO to n LO LO (n LO In co O O oo O O (D O O (D O O N (n O N LO O It r LO v r Un ljl� �Q rl-�u?(qtl-: co a a a (n N co �- U U U N N N C C C C C C LL LL LL c6 m (6 LL lL LL m m m 0-Il d N N N N N N U U U U U U C c C C c C m m m m m m LL LL LL LL LL LL ik Xk i'k �k # 7k N N N N N N U U U U U U C C C c c c m m m m m m LL LL LL LL LL LL co O O V O O 00 O N r v_ v_ v_ O O O 3 3 3 U U U C C C m m m LL LL LL N N (N U U U _C: m m m LL LL LL * * U N (N N U U U C C c m m m LL LL LL ME a O rn 0) m co N N U) Cl) :sJ LL LL C 0 m IZ d (n d Q a w c a d N O U CD (D `O a) � C � v N C: c 3 Q (D M U O d UE 3 ✓ �) 0 _ N N C O a 0 C o m T N N d N d 2 d — cm 3 O d C '� C N c _ N d d LL 3 N d d c U 3 'N d d d d m 3 N 3 3 .d N U d d U m (D c w m m U d m N d O o & d m d d U m C N N cc- U U d N m II m Q Y 4) U O d .N 0) LL OU O c a) U O C C d m t0 c m m Q U Q O m M (p W 0 cn 0 U Q Q) Q a 0 U V O N Ia a r Q N N U C cc I— LL 1 N N V L U- L. 0 0 N� I.L 0 .N O u c iJ N U) O > O m O 7 N E N m N c N N (6 1Z 0 io Fu O C > U U > a m CD U) � Z N C C LL m fD L L "- a ri w C7 �* o w J m LL V- LL c c c c cLa co c4 m LL Li LL LPL I I I L I I I I f I I I I O LO I I I I I I I M I I I I I I I I I I I O C) O I I I I M O I I O LO FL LLO CD N C Q ^^ `` W I N I I I I -----I- G Z5 I O O I I I I I I I I I I I I 1 LO r I I I I I I I I I I I I I I LO I I I I I I I I I I I I � I I I I I I I I O O chi O (ui/llsn 09C) uoijaaadaS aaluao of aaluao co co a 0 c> R C M dio T" CL 3 AN W Y L LL 1 N N t� C m L LL L O O ^M NW I.L C 6 a El A o > o m a > M N C N L C � C Z LL d Cl) w It w w cz c c J N w LL LL N N N N cm c c I-_ cm C t6 @ 6 (0 LL LL LL LL p 00 I- O M N O (ui/ 09*z) aoloe-I uoi}eaedaS r 0 U V' I N C a Davies, Stephen F (DOA) From: David Duffy <dduffy@hilcorp.com> Sent: Wednesday, July 02, 2014 1:33 PM To: Davies, Stephen F (DOA); Colombie, Jody J (DOA) Cc: Jeff Allen Subject: FW: Frances No. 2-AOGCC Spacing Application Attachments: Frances 2 Spacing Exception AOGCC Receipt.pdf; 7-2-14 Frances-2 Spacing Exception (signed).pdf; Frances 2 Certified Mail.pdf Steve & Jody, Earlier today we submitted another spacing exception for the Ninilchik Unit (Frances-2). This grassroots gas well will be drilled from the Bartolowitz Pad. I've attached an electronic copy of the application, including the certified mail receipts. Very shortly (possibly tomorrow, but more likely early next week) I'll be submitting two additional spacing exception applications for the Ninilchik Unit (Pax-7 and Frances-3). This drilling campaign will be started in August and likely run through the end of 2014. As always, we'd be glad to provide a technical presentation on the proposed spacing exception application - and if useful — bundle it together with other pending spacing applications/pool rules. Regards, David Duffy, Landman Hilcorp Alaska, LLC Direct: 907-777-8414 Cell: 907-301-2629 dduffy@hilcorp.com This email may contain confidential and / or privileged information and is intended for the recipient(s) only. In the event you receive this message in error, please notify me and delete the message. Ifl 0.1corp Alaska, LLC July 2, 2014 Cathy Foerster, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Post Office Box 244027 Anchorage, AK 99524-4027 3800 Centerpoint Drive Suite 1400 Anchorage, AK 99503 Phone:907/777-8414 Fax:907/777-8301 Email: dduffv@hiicorp.com RE: Application for spacing exception per 20 AAC 25.055(a)(2) and (4) to test and produce the Frances No. 2 well within the Ninilchik Unit Undefined. Tyonek and Beluga Pools Bear Commissioner Foerster: Pursuant to 20 AAC 25.055(a)(2) and (4), Hilcorp Alaska, LLC ("Hilcorp"), as Operator of the Ninilchik Unit, requests permission to test and produce the Frances No. 2 well in the Undefined Tyonek and Beluga Pools within 1,500 feet of a property line where the owner and landowner are not the same on both sides of the line, and within 3,000 feet of other wells capable of producing from the same pool. To date, no special Pool Rules have been established within the Ninilchik Unit. Therefore, statewide spacing regulation 20 AAC 25.055(a) is controlling. In relevant part, subsections (a)(2) and (a)(4) provide: (a)(2) For a well drilling for gas, a wellbore may be open to test or regular production within 1,500 feet of a property line only if the owner is the same and the landowner is the same on both sides of the line. (a)(4) If gas has been discovered, the drilling unit for the pool is a governmental section; not more than one well may be drilled to and completed in that pool on any governmental section; a well may not be drilled or completed closer than 3,000 feet to any well drilling to or capable of producing from the same pool. The location of Frances No. 2 and its relationship to adjoining properties and wells is depicted in Exhibit A. A confidential plat (well data) is provided in Exhibit B. Surface Location: 238' FNL, 2542' FWL, Sec 7, TIN, R12W, SM, AK Top of Productive Interval: 672' FSL, 2604' FEL, Sec 6, TIN, R12W, SM, AK Bottom Hole Location: 1828' FNL, 2403' FEL, Sec 6, TIN, R12W, SM, AK Based on confidential geological and engineering data available to Hilcorp, it is apparent that both the Undefined Tyonek and Beluga Pools are particularly discontinuous and unpredictable, and that they drain small areas. The existing wells in the Falls Creek area indicate that the majority of the fluvial sandstone reservoirs drain less than 155 acres or M1,466-f3 radius. The Frances No. 2 well indicates several gas reservoirs cannot be Ninilchik Unit Frances No. 2 Spacing Exception Application July 2, 2014 Page 2 of 8 produced from within the existing boundary of the Falls Creek Participating Area ("PA and cannot be efficiently produced from existing wells.' In order to prevent waste and maximize gas recovery from the Undefined Tyonek and Beluga Pools, we therefore request spacing exception. Frances No. 2 and all affected properties are located within the existing Ninilchik Unit Boundary. Hilcorp, as sole unit operator and 100% working interest owner, will account for all testing and production of Frances No. 2 as required by the Ninilchik Unit Agreement. As a result, the correlative rights of all affected owners, landowners and operators will be protected by approval of the requested short duration test and spacing exception. At the date of this mailing, a copy of this application was sent by certified mail to the all affected owners and landowners within 3000 feet of Frances No. 2's anticipated productive interval. No other affected operators exist. Also enclosed is an affidavit stating the undersigned is acquainted with the facts and verifying that all facts asserted herein are true. Should you have any technical questions, please contact Mr. David Buthman, Senior Geologist, at (907) 777-8395, or you may contact the undersigned at (907) 777-8414. Sincerely, David W. Duffy, Landman Ililcorp Alaska, LLC Enclosures: Exhibit A, Confidential Exhibit B (AOGCC-only), Affidavit, Copy of Certified Mail Receipts (AOGCC-only), Mailing Labels for AOGCC Notice (AOGCC-only) CC: Owners and Landowners within 3000 feet of subject well 1 Existing wells currently or potentially open to production in the within 3000' of the Frances No. 2 include: Frances #], Falls Creek #5, Fails Creek 94, Falls Creek 0, and Falls Creek #]RD. See Exhibit B (Confidential). Schwartz, Guy L (DOA) From: Luke Keller <Ikeller@hilcorp.com> Sent: Wednesday, July 09, 20141:03 PM To: Schwartz, Guy L (DOA) Subject: RE: Frances #2 (PTD 214-094) Guy, Forgot to include the drawing of a diverter line if required... See below. FROCES WELL Top OF 18, CONTAINME W .^'E'��DCAE�E rrOF PAD 16" Diverter Line .t FR,RNCEB #1 WELL p N u 3 X 3' nDwuNm UNDER Qqum (FUTURE] no 1 From: Luke Keller Sent: Wednesday, July 09, 2014 1:01 PM To: 'Schwartz, Guy L (DOA)' Subject: RE: Frances #2 (PTD 214-094) Guy, 1. Can we discuss the diverter issue further? I do not see how use of a diverter provides any additional protection to nearby roads and housing. Most likely the diverter would only buy personnel a few minutes to get off the rig, and safely away. Discharge of gas / fluids would still continue from the diverter line and affect everything nearby. In the grand scheme of things, the diverter line is not all that far from the wellbore, maybe 120' at best. 2. No problem bumping the BOP test pressure to 3500 psi. 3. 1 have Sperry working up a report right now. 4. Same as #3 5. Does this mean that the AOGCC will no longer accept the 1/3 mud, 2/3 gas MASP calculation? If not — what has changed? This will make an enormous economic impact on some of our drill wells, especially the deeper pool tests and offshore. Can we discuss this in more detail? Is this just because the well is on the bluff? Luke Keller Drilling Engineer Hilcorp Alaska, LLC 907-777-8395 From: Schwartz, Guy L (DOA)[ma iIto: guy. schwa rtzC&alaska.gov] Sent: Wednesday, July 09, 2014 12:05 PM To: Luke Keller Subject: Frances #2 (PTD 214-094) Luke, A couple of comments about PTD . 1) AOGCC is not inclined to Waive the diverter on this well regardless of the drilling history. Due to proximity to roads and housing in the area .. can you supply a diagram of the proposed layout of the diverter line. 2) Bumped BOPE test to 3500 psi based on the casing pressure test of the 5 %Z" . 3) Provide anti collision data 4) The normal vertical section and spider maps were not provided. 5) AOGCC is assuming .1 psi/ft gradient for gas well drilling in calc MASP ... 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). WELL NAME: Y-a I-,e- e_e, '2-- PTD: _�?Wq 014/ /nc\ elopment Scry icc _ l-:xhlorator} _ Stratigrahhic Test Non-C'om cntional 171ELB: <�C �� �� POOL: Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter 01EECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (1f last two digits Production should continue to be reported as a function oil' the original in API number are API number stated above. between 60-69) 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 Pilot Hole name ( PH) and API number (50- - - - ) from records, data and logs acquired for well (name onpermit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator that ti assumes the liability of any protest to the spacing exception may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 5/2013 WELL PERMIT CHECKLIST Field & Pool NINILCHIK, FC BELUGA UNDEF GAS - 562505 NINILCHIK, FC TYONEK UNDE Well Name: FRANCES 2 PTD#:2140940 Company HILCORP ALASKA LLC Initial Class/Type DEV / PEND GeoArea 820 Administration 1 Permit fee attached NA 2 Lease number appropriate Yes 3 Unique well name and number Yes 4 Well located in a defined pool No 5 Well located proper distance from drilling unit boundary No 6 Well located proper distance from other wells No 7 Sufficient acreage available in drilling unit No 8 If deviated, is wellbore plat included Yes 9 Operator only affected party No 10 Operator has appropriate bond in force Yes 11 Permit can be issued without conservation order No Appr Date 12 Permit can be issued without administrative approval Yes 13 Can permit be approved before 15-day wait Yes SFD 7/17/2014 14 Well located within area and strata authorized by Injection Order # (put 10# in comments) (For NA 15 All wells within 1/4 mile area of review identified (For service well only) NA 16 Pre -produced injector: duration of pre -production less than 3 months (For service well only) NA 17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D) NA Program DEV Well bore seg Unit 51432 On/Off Shore On Annular Disposal Surface location and top productive interval will lie within Private Fee Leases: Addition made to Form 10-401: TD appears to be within ADL0389737. SFD NINILCHIK, FC BELUGA UNDEF GAS - 562505 and NINILCHIK, FC TYONEK UNDEF GAS - 562510 SPACING EXCEPTION REQUIRED SPACING EXCEPTION REQUIRED SPACING EXCEPTION REQUIRED 18 Conductor string provided Yes 16" conductor set at 80 ft Engineering 19 Surface casing protects all known USDWs Yes 9 5/8" surface casing will be set at 3400 ft TVD 20 CMT vol adequate to circulate on conductor & surf csg Yes surface casing will be fully cemented. 21 CMT vol adequate to tie-in long string to surf csg Yes 5.5" production casing will be cemented 400 ft above the SC shoe. (Cement packer) 22 CMT will cover all known productive horizons Yes Cement packer completion.. Swell packer is not planned. 23 Casing designs adequate for C, T, B & permafrost Yes BTC calculations provided. 24 Adequate tankage or reserve pit Yes Rig has steel pits. All waste to be transported to KGF G & 1 25 If a re -drill, has a 10-403 for abandonment been approved NA Grassroots development gas well . Target T-50 to T-65 zones. 26 Adequate wellbore separation proposed Yes 27 If diverter required, does it meet regulations Yes Diverter waiver request is DENIED. Wellsite is in residential area. Appr Date 28 Drilling fluid program schematic & equip list adequate Yes Max formation press= 3585 psi (8.3 pgg EMW) Will drill with 9.5 ppg Mud. GLS 7/8/2014 29 BOPEs, do they meet regulation Yes Saxon 147 has 5000 psi 11" BOPE. 30 BOPE -press rating appropriate; test to (put psig in comments) Yes MASP= 2759 psi Will test BOPE to 3500 psi. (annular to 2500-psi) 31 Choke manifold complies w/API RP-53 (May 84) Yes rig has 5000 psi choke manifold. 32 Work will occur without operation shutdown Yes Workover rig will run tubing/packer and perforate well. 33 Is presence of H2S gas probable No H2S not expected. 34 Mechanicalconditionof wells within AOR verified (For service well only) NA 35 Permit can be issued w/o- hydrogen sulfide measures Yes Six wells within 10 miles have been drilled through the same geologic section with no evidence of H2S. Geology 36 Data presented on potential overpressure zones Yes Nearby offset wells did not encounter shallow gas or overpressure, Appr Date 37 Seismic analysis of shallow gas zones NA Planned mud weights appearadequateto control the operator's forecast of most likely pore pressures SFD 7/17/2014 38 Seabed condition survey (if off_ -shore) NA- in the operator's geologic prognosis. No abnormally geo-pressured strata are anticipated. - 39 Contact name/phone for weekly -progress reports [exploratory only] Yes - - Luke Keller 907-777-8395 - - - - - - - Geologic Engineering Public SPACING EXCEPTION REQUIRED SFD Date: Date Date Commissioner: issioner: Commissioner Development gas well on the Bartolowitz Pad. Targeting Tyonek and Beluga gas sand. GIs Co�X-2- zi%
