Alaska Logo
Department of Commerce, Community, and Economic Development
Alaska Oil and Gas Conservation
Commission
Loading...
HomeMy WebLinkAbout226-005Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Sean McLaughlin Drilling Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK, 99503 Re: Ninilchik Field, Beluga/Tyonek Gas Pool, Kalotsa 13 Hilcorp Alaska, LLC Permit to Drill Number: 226-005 Surface Location: 2045' FSL, 350' FWL, Sec. 7, T1S, R13W, SM, AK Bottomhole Location: 1809' FSL, 117' FEL, Sec. 1, T1S R14W, SM, AK Dear Mr. McLaughlin: Enclosed is the approved application for the permit to drill the above referenced well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. 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 an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, . Commissioner DATED this 10 th day of February 2026. 1a. Type of Work: 1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates Redrill Reentry Exploratory - Oil Development - Gas Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket Single Well 11. Well Name and Number: Bond No. 3. Address: 6. Proposed Depth: 12. Field/Pool(s): MD: 8,000' TVD: 5,469' 4a. Location of Well (Governmental Section): 7. Property Designation: Surface: Top of Productive Horizon: 8. DNR Approval Number: 13. Approximate Spud Date: Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 144.8 15. Distance to Nearest Well Open Surface: x-209744 y- 2233322 Zone-4 126.3 to Same Pool: 980' to Susan Dionne 6 16. Deviated wells: Kickoff depth: 300 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 80 degrees Downhole: Surface: Hole Casing Weight Grade Coupling Length MD TVD MD TVD Conductor 16" 84# X-56 Weld 100' Surface Surface 100' 100' 9-7/8" 7-5/8" 29.7# P-110 GBCD 1,250' Surface Surface 1,250' 1,112' 6-3/4" 3-1/2" 9.2# L-80 ACME 6,900' 1,100' 1,047' 8,000' 5,469' Tieback 3-1/2" 9.2# L-80 EUE 1,100' Surface Surface 1,100' 1,047' 19.PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Junk (measured): TVD Hydraulic Fracture planned? Yes No 20. Attachments: Property Plat BOP Sketch Drilling Program Time v. Depth Plot Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirements Contact Name: Contact Email: Contact Phone: Date: Permit to Drill API Number: Permit Approval Number: Date: Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Samples req'd: Yes No Mud log req'd: Yes No H2S measures: Yes No Directional svy req'd: Yes No Spacing exception req'd: Yes No Inclination-only svy req'd: Yes No Post initial injection MIT req'd: Yes No APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Kalotsa 13 Ninilchik Unit Beluga/Tyonek Gas Pool Cement Quantity, c.f. or sacks Commission Use Only See cover letter for other requirements. Total Depth MD (ft): Total Depth TVD (ft): 022224484 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION PERMIT TO DRILL 20 AAC 25.005 L - 1619 ft3 / T - 131 ft3 2078 1342' FNL, 159' FWL, Sec 7, T1S, R13W, SM, AK 1809' FSL, 117' FEL, Sec 1, T1S, R14W, SM, AK N/A 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Hilcorp Alaska, LLC 2045' FSL, 350' FWL, Sec 7, T1S, R13W, SM, AK C061505, ADL359242, ADL 384372 18. Casing Program: Top - Setting Depth - BottomSpecifications 2625 GL / BF Elevation above MSL (ft): Plugs (measured): (including stage data) Driven L - 346 ft3 / T - 208 ft3 Effect. Depth MD (ft): Effect. Depth TVD (ft): LengthCasing Size Conductor/Structural Authorized Title: Authorized Signature: Authorized Name: Production Liner Intermediate Drilling Manager Sean Mclaughlin 21. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Surface Perforation Depth TVD (ft):Perforation Depth MD (ft): 3/18/2026 5018' to nearest unit boundary Zachary Browning zachary.browning@hilcorp.com 208-301-0767 Tieback Assy. 5614 Cement Volume MD YYes ype of W L l R L 1b S Class: os N YYes NNNo s N NNNo Dr s s sDr 84 o ess: well is p G S S 20 S S S YYes NNNos No S G E S YYYes NNNo s Form 10-401 Revised 3/2021 This permit is valid for 24 months from the date of approval per 20 AAC 25.005(g) Digitally signed by Sean McLaughlin (4311) DN: cn=Sean McLaughlin (4311) Date: 2026.01.21 11:50:23 - 09'00' Sean McLaughlin (4311) 226-005 By Grace Christianson at 2:34 pm, Jan 21, 2026 BOP test to 2500 psi. DSR-1/22/26 50-133-20746-00-00 TS 1/23/2026 Submit FIT/LOT within 24 hrs of obtaining results. If LOT is < 13.7 ppg, notify AOGCC and obtain approval before drilling 6.75" hole. BJM 2/9/26JLC 2/10/2026 02/10/26 02/10/26 KALOTSA 13 Drilling Program REV 0 Ninilchik Field January 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX Contents 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 R/U and Preparatory Work........................................................................................................10 9.0 N/U 21-1/4” 2M Diverter.............................................................................................................11 10.0 Drill 9-7/8” Hole Section..............................................................................................................12 11.0 Run 7-5/8” Surface Casing..........................................................................................................14 12.0 Cement 7-5/8” Surface Casing....................................................................................................16 13.0 BOP N/U and Test........................................................................................................................19 14.0 Drill 6-3/4” Hole Section..............................................................................................................20 15.0 Run 3-1/2” Production Liner......................................................................................................23 16.0 Cement 3-1/2” Production Liner................................................................................................26 17.0 3-1/2” Liner Tieback Polish Run................................................................................................29 18.0 3-1/2” Tieback Run, ND/NU, RDMO.........................................................................................30 19.0 CBL and Nitrogen Operation (Post Rig Work)........................................................................31 20.0 Diverter Schematic ......................................................................................................................34 21.0 BOP Schematic.............................................................................................................................35 22.0 Wellhead Schematic.....................................................................................................................36 23.0 Anticipated Drilling Hazards......................................................................................................37 24.0 Hilcorp Rig 147 Layout...............................................................................................................39 25.0 FIT/LOT Procedure ....................................................................................................................40 26.0 Rig 147 Choke Manifold Schematic...........................................................................................41 27.0 6-3/4” Hole Section MASP..........................................................................................................42 28.0 Spider Plot w/ 660’.......................................................................................................................43 29.0 Surface Plat As-Built...................................................................................................................44 Page 2 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 1.0 Well Summary Well Kalotsa 13 Pad & Old Well Designation Kalotsa Pad – Grassroots Well Planned Completion Type 3-1/2” Production Liner w/Tieback (monobore) Target Reservoir(s) Tyonek / Lower Beluga Planned Well TD, MD / TVD 8,000’ MD / 5,469’ TVD PBTD, MD / TVD 7,920’ MD / 5,400’ TVD Planned Drilling Days 17 days Maximum Anticipated Pressure (Surface) 2078 psi Maximum Anticipated Pressure (Downhole/Reservoir) 2625 psi Work String 4-1/2” 16.6# S-135 CDS-40 RKB 144.8’ Ground Elevation 126.3’ BOP Equipment 11” 5M Annular BOP 11” 5M Double Ram 11” 5M Single Ram Page 3 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 2.0 Management of Change Information Page 4 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 3.0 Tubular Program: Hole Section OD (in) ID (in)Drift (in) Conn OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) Conductor 16” 16” 15.01” 14.822”- 84 X-56 Weld 2980 1410 - Surface Casing 9-7/8” 7-5/8” 6.875” 6.750” 8.500”29.7 P-110HC GBCD 9470 6700 940 Production Liner* 6-3/4” 3-1/2” 2.992” 2.867” 4.25”9.2 L-80 ACME 10160 10540 207 Production Tubing NA 3-1/2” 2.992” 2.867” 4.50”9.2 L-80 EUE 10160 10540 207 * Liner must overlap surface casing by at least 100’. 4.0 Drill Pipe Information: Hole Section OD (in)ID (in)TJ ID (in) TJ OD (in) Wt (#/ft) Grade Conn Burst (psi) Collapse (psi) Tension (k-lbs) All 4-1/2”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 5 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 5.0 Internal Reporting Requirements 1. Fill out daily drilling report and cost report on WellView. Report covers operations from 6am to 6am Ensure time entry adds up to 24 hours total. Capture any out-of-scope work as NPT. 2. Afternoon Updates Submit a short operations update each day to kenaiciodrilling@hilcorp.com 3. Morning Update Submit a short operations update each morning by 7am in NDE – Drilling Comments 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. Jacob Nordwall: O: (907) 777-8418 C: (907) 748-0753 b. Leonard Dickerson: O: (907) 777-8317 C: (907) 252-7855 2. Spills: Notify Drlg Manager 1. Sean McLaughlin: C: 907-223-6784 Submit Hilcorp Incident report to contacts above within 24 hrs 5. Casing Tally Send final “As-Run” Casing tally to Zachary.Browning@hilcorp.com, and cdinger@hilcorp.com 6. Casing and Cmt report Send casing and cement report for each string of casing to Zachary.Browning@hilcorp.com, and cdinger@hilcorp.com Page 6 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 6.0 Planned Wellbore Schematic Page 7 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 7.0 Drilling / Completion Summary Kalotsa 13 is an S-shaped directional grassroots development well to be drilled from Kalotsa Pad. Reservoir analysis and subsurface mapping has identified an optimal location for infill development of the Tyonek and Lower Beluga sands. The base plan is an S-shaped directional wellbore with a kickoff point at ~350’ MD. Maximum hole angle will be ~80 deg. and TD of the well will be 8,000’ TMD/ 5,469’ TVD, ending with 30 deg inclination. Drilling operations are expected to commence approximately February 2025. The Hilcorp Rig #147 will be used to drill the wellbore then run casing and cement. Surface casing will be run to approx. 1250’ MD / 1112’ TVD and cemented to surface to ensure protection of any shallow freshwater resources. Cement returns to surface will confirm TOC at surface. If cement returns to surface are not observed, a cement evaluation log (CBL/VDL or temperature log for example) may be run to determine TOC. Necessary remedial action will then be discussed with AOGCC authorities. 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 Hilcorp Rig # 147 to wellsite 2. N/U diverter and test. 3. Drill 9-7/8” hole to 1250’ MD. Run and cement 7-5/8” surface casing. 4. Test casing to 3000 psi. Perform FIT to min 13.7ppg. 5. ND diverter, N/U & test 11” x 5M BOP to 2500 psi 6. Drill 6-3/4” hole section to 8,000’ MD. 7. Run and cement 3-1/2” production liner. 8. POOH and LDDP. Perform Polish mill run. Swap well to CI fluid. 9. RIH and land 3-1/2” tieback string in liner top. 10. Test IA to 3000psi; Test tubing to 3000 psi 11. N/D BOP, N/U temp abandonment cap, RDMO. 12. MIRU Eline and log well. RDMO. 13. MIRU Coil Tubing and blowdown well. RDMO. 14. Suspend Well. Reservoir Evaluation Plan: 1. Surface hole: GR/RES/PWD 2. Production Hole: Triple Combo Page 8 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 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 of Kalotsa 13. Ensure to provide AOGCC 48 hrs notice prior to testing BOPs. The initial test of BOP equipment will be 250/2500 psi & subsequent tests of the BOP equipment will be to 250/2500 psi for 5/10 min (annular to 50% rated WP, 2500 psi on the high test for initial and subsequent tests).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 permits are posted on the rig floor and in Co Man office. Review all conditions of approval of the AOGCC PTD on the 10-401 form. Ensure that the conditions of approval are captured in shift handover notes until they are executed and complied with. VARIENCE REQUEST: Test 7-5/8” surface casing to 3500psi. o Justification: Request to test to 50% IYP of L-80 rather than P-110 grade pipe. L-80 grade (6890psi burst / 4790psi collapse) is sufficient for this well design. The worst-case burst load is 2078psi (MASP) and the worst-case collapse load is 556psi (fully evacuated casing with max MW external gradient). L-80 pipe has been the standard for similar wells in the past. P-110 grade pipe (9470 burst / 6700psi high collapse) has been sourced due to availability. There is no well design load requirement necessitating a higher test to 4735psi (50% of P- 110 IYP).Variance to 20 AAC 25.030(e) is approved. -bjm Page 9 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure (psi) 9-7/8”21-1/4” x 2M Hydril MSP diverter Function Test Only 6-3/4” 11” x 5M Annular BOP 11” x 5M Double Ram o Blind ram in btm cavity Mud cross 11” x 5M Single Ram 3-1/8” 5M Choke Line 2-1/16” x 5M Kill line 3-1/8” x 2-1/16” 5M Choke manifold Standpipe, floor valves, etc Initial Test: 250/2500 (Annular 2500 psi) Subsequent Tests: 250/2500 (Annular 2500 psi) 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-hour notice prior to testing BOPs. Any other notifications required in APD. Additional requirements may be stipulated on APD and Sundry. Regulatory Contact Information: AOGCC Jim Regg / AOGCC Inspector / (O): 907-793-1236 / Email:jim.regg@alaska.gov Bryan McLellan / Petroleum Engineer / (O): 907-793-1226 / Email:bryan.mclellan@alaska.gov Victoria Loepp / Petroleum Engineer / (O): 907-793-1247 / Email:victoria.loepp@alaska.gov Primary Contact for Opportunity to witness:AOGCC.Inspectors@alaska.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 10 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 8.0 R/U and Preparatory Work 1. Level pad and ensure enough room for layout of rig footprint and R/U. 2. Layout Herculite on pad to extend beyond footprint of rig. 3. R/U Hilcorp Rig # 147, spot service company shacks, spot & R/U company man & toolpusher offices. 4. After rig equipment has been spotted, R/U handi-berm containment system around footprint of rig. 5. Mix spud mud for 9-7/8” hole section. 6. Install 5-1/2” liners in mud pumps. TSM -1000 mud pumps are rated at 3632 psi (85%) / 361gpm (100%) at 130 strokes with 5-1/2” liners. 7. PU and rack back enough 4.5in DP to TD the surface hole. 4-1/2” Workstring & HWDP will come from Hilcorp. Workstring will be 4.5” 16.6# S-135 CDS40 Page 11 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 9.0 N/U 21-1/4” 2M Diverter 1. N/U 21-1/4” Hydril MSP 2M diverter System. N/U 16-3/4” 3M x 21-1/4” 2M DSA (Hilcorp) on 16-3/4” 3M wellhead. N/U 21-1/4” diverter “T”. Knife gate, 16” diverter line. Ensure diverter R/U complies with AOGCC reg 20.AAC.25.035(C). 2. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. 3. Function test diverter. Ensure that the knife gate and annular are operated on the same circuit so that knife gate opens prior to annular closure. NOTE:Ensure closing time on diverter annular is in line with API RP 64: 1..1.1.Annular element ID 20” or smaller: Less than 30 seconds 1..1.2.Annular element ID greater than 20”: Less than 45 seconds 4. Ensure to set up a clearly marked “warning zone” is established on each side and ahead of the vent line tip. “Warning Zone” must include: A prohibition on vehicle parking. A prohibition on ignition sources or running equipment. A prohibition on staged equipment or materials. Restriction of traffic to essential foot or vehicle traffic only. 5. Set wear bushing in wellhead. 6. Estimated Diverter line orientation on Kalotsa Pad: Page 12 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 10.0 Drill 9-7/8” Hole Section 1. P/U 9-7/8” directional drilling assembly: 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. GR/RES/PWD tools required 2. Begin drilling out from 16” conductor at reduced flow rates to avoid broaching the conductor. 3. Drill 9-7/8” hole section to 1250’ MD/ 1112’ TVD. 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. Keep swab and surge pressures low when tripping. Make wiper trips as hole conditions dictate. 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 competent shale Take MWD surveys every stand drilled (60’ intervals). 4. 9-7/8” 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. 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 logger’s office. System Type:8.8 – 9.5 ppg Pre-Hydrated Aquagel/freshwater spud mud Properties: Depths Density Viscosity Plastic Viscosity Yield Point API FL pH 120-1250’ 8.8 – 9.5 150-250 15-30 30-60 <8 8.5-10.0 Page 13 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX System Formulation: Aquagel + FW spud mud Product Concentration FRESH WATER SODA ASH AQUAGEL CAUSTIC SODA BARAZAN D+ BAROID 41 DEXTRID ALDACIDE G 0.905 bbl 0.5 ppb 20-28 ppb 0.1 ppb (9 pH) as needed as required for weight 2-3 ppb 0.1 ppb 5. At TD, pump sweeps, CBU 2X, and pull a wiper trip back to the 16” conductor shoe. 6. TOH with the drilling assembly, LD BHA. Page 14 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 11.0 Run 7-5/8” Surface Casing 1. R/U and pull wearbushing. 2. R/U Nabors 7-5/8” casing running equipment. Ensure 7-5/8” GBCD 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. 3. P/U shoe joint, visually verify no debris inside joint. 4. Continue M/U & thread locking shoe track assy consisting of: 7-5/8” Float Shoe 1 joint – 7-5/8”threadlocked coupling.2 Centralizers, 10’ from each end w/ stop rings 1 full joint – 7-5/8”threadlocked coupling, 1 centralizer mid joint w/ stop rings 7” Float Collar 1 joint – 7-5/8 threadlocked coupling, 1 Free floating centralizer Ensure proper operation of float equipment. 5. Continue running 7-5/8” 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. Install 1 centralizer/joint free floating until 300’ from surface. Do not run any centralizers above 300’ in the event a top-job is needed. Utilize dog collar until weight is sufficient to keep slips set properly. Page 15 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 6. Watch displacement carefully and avoid surging the hole. Slow down running speed if necessary. 7. Slow in and out of slips. 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. 9. Lower string and land out in wellhead. Confirm measurements indicate the hanger has correctly landed out in the wellhead profile. 10. R/U circulating equipment and circulate the greater of 1 x casing capacity or 1 x OH volume. Elevate the hanger off seat to avoid plugging the flutes. Stage up pump slowly and monitor losses closely while circulating. 11. After circulating, lower string and land hanger in wellhead again. Page 16 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 12.0 Cement 7-5/8” Surface Casing 1. Hold a pre-job safety meeting over the upcoming cement 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 cement unit at acceptable rates. Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole How to handle cement 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. 2. Document efficiency of all possible displacement pumps prior to cement job 3. R/U cement head (if not already done so). Ensure top and bottom plugs have been loaded correctly. 4. Pump 5bbls 10.5ppb spacer. Test surface lines. 5. Pump remaining spacer. ~50bbls total spacer volume planned 6. Drop bottom plug. 7. Mix and pump cement per below recipe: Cement volume based on annular volume + 75% lead and tail open hole excess. Job will consist of lead & tail, TOC brought to surface. Page 17 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX Estimated Total Cement Volume: 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. 9. After pumping cement, drop top plug and displace cement with spud mud at max rate of 5bpm. NOTE: Use cement unit to displace cement for accurate displacement volumes. Slow to 2-3bpm for plug bump. 10. 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. 11. Do not over displace by more than 1 shoe track volume. Total volume in shoe track is 3.7 bbls. Surface Casing Cement Volumes Total 10.5ppg Spacer 50.0 bbls Conductor OD 16 in Conductor ID 15.01 in Hole Size 9.875 in Casing OD 7.625 in Casing ID 6.875 in Casing x Conductor Capacity 0.16239 bbl/ft Casing x OH Annular Capacity 0.03825 bbl/ft Casing Capacity 0.04592 bbl/ft OH Excess (Lead) 75% OH Excess (Tail) 75% Lead Cement - 12# Casing x OH 42.17 bbls Casing x Conductor 19.49 bbls Total Lead 61.7 bbls Tail Cement - 15.3# - Length: 500 ft ST Length 80 ft Casing x OH 33.5 bbls Shoetrack 3.7 bbls Total Tail 37.1 bbls Total Job 98.8 bbls Displacement Volume 53.7 bbls *Note volume change if LS is modified Verified cement calcs. -bjm Page 18 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX Be prepared for cement returns to surface. If cement returns are not observed to surface, be prepared to run a temp log between 12 – 18 hours after CIP. 12. 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. 13. R/D cement equipment. Flush out wellhead with FW. 14. Back out and L/D landing joint. Flush out wellhead with FW. 15. 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. 16. Lay down landing joint and pack-off running tool. Ensure to report the following on WellView: 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 Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid Note if casing is reciprocated or rotated during the job Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure Note if pre flush or cement returns at surface & volume Note time cement in place Note calculated top of cement 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 cdinger@hilcorp.com and zachary.browning@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 19 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 13.0 BOP N/U and Test 1. ND Diverter line and diverter 2. N/U wellhead assy. Ensure to orient wellhead so that tree will line up with flowline later. Test Packoff to minimum 2500 psi. 3. N/U 11” x 5M BOP as follows: BOP configuration from Top down: 11” x 5M annular BOP/11” x 5M double ram /11” x 5M mud cross/11” x 5M single ram Double ram should be dressed with 2-7/8” x 5” variable bore rams in top cavity, blind ram in btm cavity. Single ram should be dressed with 2-7/8” x 5” variable bore rams 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. 4. Land out test plug (if not installed previously). Test BOP to 250/2500 psi for 5/10 min. Test VBR’s with 3-1/2” and 4-1/2” test joints Test annular to 250/2500 psi for 10/10 min with a 3-1/2” test joint Ensure to leave side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 5. Dump and clean mud pits, send spud mud to G&I pad for injection. 6. Mix 9.0ppg 6% KCL PHPA mud system. 7. Rack back as much 4-1/2” DP in derrick as possible to be used while drilling the hole section. Page 20 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 14.0 Drill 6-3/4” Hole Section 1. Pull test plug, run and set wear bushing 2. Ensure BHA components have been inspected previously. 3. Drift and caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 4. TIH and conduct shallow hole test of MWD to confirm all LWD functioning properly. 5. Ensure TF offset is measured accurately and entered correctly into the MWD software. 6. Have DD run hydraulics calculations on site to ensure optimum nozzle sizing. 7. Workstring will be 4.5” 16.6# S-135 CDS40. Ensure to have enough 4-1/2” DP in derrick to drill the entire open hole section without having to pick up pipe from the pipeshed. 8. 6-3/4” hole section mud program summary: Weighting material to be used for the hole section will be barite, 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. Ensure fluids are topped off and adequate lost circulation material is on location in anticipation of losses in hole section. System Type:9.0 – 9.8 ppg 6% KCL PHPA fresh water based drilling fluid. Properties: MD Mud Weight Yield Point Plastic Viscosity pH HPHT LGS 1250’- 5500’ 9.0 – 9.8 14-20 15-30 9.0-10.5 11.0 <10 %5500’- 8000’ 9.3 – 9.8 12-16 Page 21 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX System Formulation:6% KCL EZ Mud DP Product Concentration Water Soda Ash KCl Caustic BARAZAN D+ EZ MUD DP DEXTRID LT PAC-L BARACARB 25/50/150 Steel Seal 50/100/400 BAROID 41 ALDACIDE G BARACOR 700 OXYGON 0.905 bbl 0.5ppb (as needed) 22 ppb (29 K chlorides) 0.2 ppb (9 pH) 0.65 ppb (as required 14 YP) 0.75 ppb 5 ppb 3.5 ppb 15 ppb (5 ppb of each) 2.5/2.5/1.5ppb as required for a 9.0 – 9.8 ppg 0.1 ppb 1 ppb 0.1 ppb 9. TIH w/ 6-3/4” cleanout assembly to TOC. Record TOC tagged on daily report Utilize a mill-tooth bit and motor for shoetrack drillout. 10. R/U and test casing to 3500 psi / 30 min if not already performed. Ensure to record volume / pressure and plot on FIT graph. NOTE: See Variance request to test to 3500psi. 11. Drill out shoe track and 20’ of new formation. 12. CBU and condition mud for FIT. 13. Conduct FIT to minimum 13.7 ppg EMW. 13.7ppg FIT provides 15bbls KT with a 9.8ppg MW 14. POH and LD cleanout assembly. 15. MU and TIH w/ 6-3/4” directional assy to TOC. Shallow test MWD and LWD on trip in. Record TOC tagged on daily report Triple Combo LWD tools required (DEN, POR, RES) 16. Drill 6-3/4” hole section to 8,000’ MD / 5,469’ TVD Increase MW to target 9.5ppg (9.3ppg minimum) by 5500’ MD / 3300’ TVD for Beluga 134 and Tyonek pressure (MLPP: ~9.2ppg). Pump sweeps and maintain mud rheology to ensure effective hole cleaning. Pump at 200-290 gpm. Ensure shaker screens are set up to handle this flowrate. Keep swab and surge pressures low when tripping. Make wiper trips as hole conditions dictate. Page 22 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX Discuss with DE the need to perform long wiper trip back to the 7-5/8” shoe about ½ way through the hole section. Ensure shale shakers are functioning properly. Check for holes in screens on connections. LL: Maintain good hole cleaning and add black product to the mud. Slow ROP or perform cleanout CBU if ECD indicates dirty hole. Lost BHA on Kalotsa 8. Adjust MW as necessary to maintain hole stability. Keep HTHP fluid loss < 10. Take MWD surveys every 100’ drilled. Surveys can be taken more frequently if deemed necessary. 17. At TD; pump sweeps, CBU min 2X while rotating and reciprocating. Condition mud for the casing run 18. POH to the 7-5/8” shoe. If tight spots are seen on trip out of hole, consider wiper back to TD. 19. TOH with the drilling assy, LDDP not needed for polish run. 20. LD BHA 21. Verify 2-7/8” x 5” VBRs previously installed in BOP stack and tested with 3-1/2” test joint. Page 23 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 15.0 Run 3-1/2” Production Liner 1. R/U Nabors 3-1/2” casing running equipment. Ensure 3-1/2” GB ACME x CDS 40 crossover on rig floor and M/U to FOSV. R/U fill up line to fill casing while running. Ensure all casing has been drifted prior to running. Be sure to count the total # of joints 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. 2. P/U shoe joint, visually verify no debris inside joint. 3. Continue M/U & thread locking shoe track assy consisting of: 3-1/2” Float Shoe (YJOS) 1 joint – 3-1/2” IBT, 2 Centralizer 10’ from each end w/ stop ring 1 joint – 3-1/2” IBT, 1 Free floating centralizer 3-1/2” Float/Landing Collar (YJOS) 1 joint – 3-1/2” IBT, 1 Free floating centralizer XO – 3-1/2” IBT pin x ACME box All float equipment and shoetrack couplings to be threadlocked (from shoe to XO). Ensure proper operation of float shoe and float collar. Utilize a collar clamp until weight is sufficient to keep slips set properly 4. Continue running 3-1/2” production liner Fill casing while running using fill up line on rig floor. Use “API Modified” thread compound. Dope pin end only w/ paint brush. Install solid body centralizers on every joint to the TOL. Leave the centralizers free floating. Install 10’ pup every ~500ft. Install RA tag in every other pup so they are placed every ~1000ft. 5. Continue running 3-1/2” production liner Page 24 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX Page 25 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 7. Run in hole w/ 3-1/2” liner to the 7-5/8” casing shoe. 8. Fill the casing with fill up line and break circulation at 1,000 feet or as the hole dictates. 9. Circulate 1.5X bottoms up at shoe before entering open hole. Obtain slack off weight, PU weight, rotating weight and torque of the casing before entering open hole. 10. Slowly run through shoe. Continue to RIH w/ casing no faster than 1 jt./minute. Watch displacement carefully and avoid surging the hole. Slow down running speed if losses are seen. 11. Set casing slowly in and out of slips. 12. PU 3-1/2” X 7-5/8” YJOS liner hanger/LTP assembly per YJOS rep. RIH 1 stand and circulate one liner volume to clear string. Obtain slack off weight, PU weight, rotating weight and torque parameters of the liner. 13. Continue running in hole at slow speeds to avoid surging well. Discuss target running speeds with drilling engineer to avoid surging the hole. 14. Swedge up and wash last stand to bottom. Tag and P/U 5’ off bottom. Note slack-off and pick- up weights. 15. Stage pump rates up slowly to circulating rate.Circ and condition mud with liner on bottom. Circulate 2X bottoms up or until pressures stabilize and mud properties are correct and the shakers are clean. Reduce the low-end rheology of the drilling fluid by adding water and thinners. 16. Rotate and reciprocate string if hole conditions allow. Circ until hole and mud is in good condition for cementing. Page 26 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 16.0 Cement 3-1/2” Production Liner 1. Hold a pre-job safety meeting over the upcoming cement 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 cement unit at acceptable rates. Pump 20 bbls of freshwater through all of Halliburton’s equipment, taking returns to cuttings bin, prior to pumping any fluid downhole 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 cmt operation. Document efficiency of all possible displacement pumps prior to cement job. NOTE: Rotate the liner throughout the cement operations until ~10bbls before plug bump. If unable to rotate due to high torque, reciprocate the pipe. If unable to reciprocate, place liner on depth and cement without rotation and reciprocation. 2. Pump 5 bbls spacer to fill surface lines. 3. Test surface cement lines to 4500 psi. 4. Pump remaining spacer. ~50bbls spacer planned. 5. Mix and pump lead and tail cement per volumes below. Ensure cement is pumped at designed weight. Volumes assume 40% OH excess. Page 27 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX Estimated Total Cement Volume: 6. Drop drillpipe dart and displace with drilling mud. 7. Displace cement at max rate of 5 bbl/min. Reduce pump rate to 2-3 bpm prior to DP dart/LWP entering into liner. NOTE: Ensure liner is at setting depth during plug launch in case of inadvertently setting liner hanger. 8. If elevated displacement pressures are encountered, position liner at setting depth and cease reciprocation. Monitor returns & pressure closely while circulating. Notify Drilling Foreman immediately of any changes. 9. Bump the plug and pressure up to up as required by YJOC procedure to set the liner hanger (ensure pressure is above nominal setting pressure, but below pusher tool activation pressure). Hold pressure for 3-5 minutes. NOTE: Do not overdisplace by more than 1bbl. Shoe track volume is 0.7 bbls. 10. Slack off total liner weight plus 30k to confirm hanger is set. Production Liner Cement Volumes Total 10.5ppg Spacer 50.0 bbls Surface Casing OD 7.625 in Suface Casing ID 6.875 in Hole Size 6.75 in Casing OD 3.5 in Casing ID 2.992 in DP OD 4.5 in DP Capacity 0.01374 bbl/ft DP x Casing Annular Capacity 0.02624 bbl/ft Liner x Casing Annular Capacity 0.03402 bbl/ft Liner x OH Annular Capacity 0.03236 bbl/ft Casing Capacity 0.00870 bbl/ft OH Excess 40% Lead Cement - 12# Liner x OH 283 bbls Liner x Casing 5.1 bbls Total Lead 288.3 bbls Tail Cement - 15.3# - Length: 500 ft ST Length 80 ft Casing x OH 22.7 bbls Shoetrack 0.70 bbls Total Tail 23.3 bbls Total Job 311.6 bbls Displacement Volume* 74.4 bbls *Note volume change if LS is modified Page 28 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 11. Continue pressuring up to activate LTP pusher tool and set packer with running tool in compression. 12. Pressure up to 4,500 psi to neutralize the pusher tool and release the running tool from the liner. 13. Bleed pressure to zero to check float equipment. Watch for flow. Note amount of fluid returned after bumping plug and releasing pressure. 14. P/U past free-travel verify setting tool is released, confirmed by loss of liner weight 15. Pressure up drill pipe to 500 psi and pick up to remove the bushing from the liner. Bump up pressure as required to maintain 500 psi DP pressure while moving pipe until the pressure drops rapidly, indicating pack-off is above the sealing area (ensure that 500 psi will be enough to overcome hydrostatic differential at liner top). 16. Immediately with the loss of pressure and before DP reaches zero, initiate circulation while picking up to position the bottom of the stinger inside the tieback sleeve. Increase pump rate to wellbore clean up rate until the sleeve area is thoroughly cleaned. 17. Pick up to the high-rate circulation point above the tieback extension, mark the pipe for reciprocation, do not re-tag the liner top, and circulate the well clean. Watch for cement returns and record the estimated volume. Rotate & circulate to clear cement from DP. 18. RD cementers and flush equipment. POOH, LDDP and running tool. Verify the liner top packer received the required setting force by inspecting the rotating dog sub. Ensure to report the following on WellView: 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 Pump rate while displacing, note whether displacement by pump truck or mud pumps, weight & type of displacing fluid Note if casing is reciprocated or rotated during the job Calculated volume of displacement , actual displacement volume, whether plug bumped & bump pressure, do floats hold Percent mud returns during job, if intermittent note timing during pumping of job. Final circulating pressure Note if pre flush or cement returns at surface & volume Note time cement in place Note calculated top of cement 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 cdinger@hilcorp.com and zachary.browning@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 29 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 17.0 3-1/2” Liner Tieback Polish Run 1. PU liner tieback polish mill assembly per YJOS rep and RIH on drillpipe. 2. RIH to top of liner assembly and establish parameters. Polish tieback receptacle per YJOC procedure. 3. If not completed yet, test 3-1/2” liner and LTP to 3000 psi and chart for 30 minutes. WOC until tail cement reaches 500psi UCS prior to performing pressure test. 4. Displace to CI fluid (8.4ppg freshwater with Corrosion inhibitor). Flow check well for 30min. 5. POOH, laying down DP. LD polish mill. Page 30 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 18.0 3-1/2” Tieback Run, ND/NU, RDMO 1. PU 3-1/2” tieback assembly and RIH with 3-1/2” 9.2# L-80 EUE. Ensure any jewelry is picked up per tally. No SSSV required. 2. No-go tieback seal assembly in liner PBR and mark pipe. PU pup joint(s) if necessary to space out tieback seals in PBR. 3. PU hanger and terminate control line through hanger. Land string in hanger bowl. Note distance of seals from no-go. 4. Install packoff and test hanger void. 5. Test 3-1/2” tubing and IA to 3000 psi and chart for 30 minutes. 6. Install BPV in wellhead 7. N/D BOPE 8. N/U dry-hole tree and test Page 31 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 19.0 CBL and Nitrogen Operation (Post Rig Work) Pre-Sundry work: 1. Review all approved COAs 2. MIRU E-line and pressure control equipment 3. Log well with CBL tool (send results to AOGCC to review) 4. RDMO E-line Coiled Tubing Procedure 1. MIRU Coiled Tubing and pressure control equipment 2. PT lubricator to 250psi low / 2500psi high a. Provide AOGCC 48hr notice for BOP test 3. MU cleanout BHA 4. RIH to PBTD, cleanout well as necessary (based on CBL depth) and swap well over to 8.4 ppg water. a. If well is left with 9.4 ppg mud or less, mud may be circulated out with Nitrogen, based on Operations Engineer direction without swapping to water. 5. Once well is clean with 8.4 ppg water a. Reverse circulate water 6. RDMO CT 7. Leave N2 pressure on well when coil is rigged down Submit Completion sundry for perforating well. Attachments included below: 1. Coil Tubing BOP Diagram 2. Standard Nitrogen Operations Page 32 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX Page 33 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX ***Suspend well – close out drilling permit with 10-407*** Page 34 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 20.0 Diverter Schematic Page 35 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 21.0 BOP Schematic Page 36 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 22.0 Wellhead Schematic Page 37 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 23.0 Anticipated Drilling Hazards 9-7/8” Hole Section: Lost Circulation: Ensure 500 lbs of medium/coarse fibrous material & 500 lbs different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. 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 between 30 – 60 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 initial 200’ of drilling to reduce the likelihood of washing out the conductor shoe. To help ensure 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 38 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 6-3/4” Hole Section: Lost Circulation: Ensure 1000 lbs of each of the different sizes of Calcium Carbonate are available on location to mix LCM pills at moderate product concentrations. Given the high risk of losses, ensure all LCM inventory is fully stocked before drilling out surface casing. Hole Cleaning: Maintain rheology w/ viscosifier as necessary. Sweep hole w/ 20 bbls hi-vis pills as necessary. Optimize solids control equipment to maintain density and minimize sand content. Maintain YP between 20 - 30 to optimize hole cleaning and control ECD. Wellbore stability: Maintain MW as necessary using additions of Calcium Carbonate as weighting material. A torque reduction lube may be used in this hole section in concentrations up to 3% if needed. 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. Increase fluid density as required to control running coals. Emphasize good hole cleaning through hydraulics, ROP and system rheology. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 39 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 24.0 Hilcorp Rig 147 Layout Page 40 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 25.0 FIT/LOT 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 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 41 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 26.0 Rig 147 Choke Manifold Schematic Page 42 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 27.0 6-3/4” Hole Section MASP MD TVD Planned Top: 1,250 1,112 Planned TD: 8,000 5,469 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad SURFACE CASING 1112 478 Gas / Water 8.27 0.43 BEL_10 1449 561 Gas / Water 8.27 0.43 BEL_13 1487 577 Gas / Water 8.27 0.43 BEL_44 1822 721 Gas / Water 8.27 0.43 BEL_53 2135 856 Gas / Water 8.27 0.43 BEL_56 2270 914 Gas / Water 8.27 0.43 BEL_65 2523 1023 Gas / Water 8.27 0.43 BEL_80 2717 1158 Gas / Water 8.65 0.45 BEL_82 2755 1175 Gas / Water 8.65 0.45 BEL_90 2835 1211 Gas / Water 8.65 0.45 BEL_134 3576 1647 Gas / Water 9.23 0.48 BEL_135 3629 1673 Gas / Water 9.23 0.48 T-3 3874 1790 Gas / Water 9.23 0.48 T-5 4017 1859 Gas / Water 9.23 0.48 T-6 4161 1928 Gas / Water 9.23 0.48 T-8 4372 2029 Gas / Water 9.23 0.48 T-10 4485 2083 Gas / Water 9.23 0.48 T-11 4616 2146 Gas / Water 9.23 0.48 T-12 4750 2210 Gas / Water 9.23 0.48 T-16 5233 2442 Gas / Water 9.23 0.48 T-17 5317 2483 Gas / Water 9.23 0.48 T-18 5455 2549 Gas / Water 9.23 0.48 TD in T-18 5469 2625 Gas / Water 9.23 0.48 Offset Well Mud Densities Well MW range Bottom (TVD) Date Kalotas 8 9.0 - 9.4 7,183 2022 Kalotas 9 9.0 - 9.5 7,551 2025 Kalotas 10 9.1 - 9.5 7,861 2025 Assumptions: 1. Fracture gradient at shoe is estimated to be 16 -21 ppg 2. Planned mud density for the 6-3/4" hole section is 9.5 ppg. 3. Calculations assume "Unknown" reservoir contains 100% gas (worst case). 4. Calculations assume worst case event is 100% evacuation of wellbore to gas. Fracture Pressure at 7-5/8" shoe considering a full column of gas from shoe to surface: TVD Frac Grad 1112 ft X 1.092 psi/ft 1214 psi 1214(psi) - [0.1(psi/ft)*1112(ft)]= 1103 psi Surface MASP from pore pressure during production mode (Complete evacuation to gas) 5469 ft X 0.480 psi/ft 2625 psi Downhole 2625.12(psi) - [0.1(psi/ft)* 5469(ft)]=2078 psi Summary: 1. MASP while drilling 6-3/4" production hole is governed by pore pressure with gas to surface Maximum Anticipated Surface Pressure Calculation 6-3/4" Hole Section WELL: Kalotsa 13 WP02 FIELD: Ninilchik Page 43 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 28.0 Spider Plot w/ 660’ Page 44 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 29.0 Surface Plat As-Built Page 45 Rev 0.0 Jan 20, 2026 Kalotsa 13 Drilling Procedure PTD XXX-XXX 1 McLellan, Bryan J (OGC) From:Zachary Browning <zachary.browning@hilcorp.com> Sent:Monday, February 9, 2026 5:25 PM To:McLellan, Bryan J (OGC) Subject:RE: [EXTERNAL] Kalotsa 13 PTD Bryan, Good afternoon. Fully agree with you. The program speci es the absolute minimum KT that would be acceptable to move forward, which is based on 15bbls with no safety factor. But our target FIT will generally be higher to provide a healthier kick tolerance. In some instances I will instruct the rig to bring the test up to leak-o , in other cases, if no leak-o is seen we will shut in once we have achieved >25bbls KT or so. This is what we did recently on Kalotsa 11 (16.5ppg minimum FIT speci ed in the program, but we targeted >19.0ppg). Thanks, Zach From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, February 9, 2026 5:14 PM To: Zachary Browning <zachary.browning@hilcorp.com> Subject: [EXTERNAL] Kalotsa 13 PTD Zach, I’m reviewing the Kalotsa 13 PTD. You are planning a FIT to 13.7 ppg which I agree provides 15 bbls kick tolerance, with no safety factors or choke allowance built in. This is the bare minimum we look for to allow the rig crew time to detect a kick, verify and space out and get the well shut-in. Why not take your FIT a bit higher and verify that you have a more healthy kick tolerance? Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Revised 7/2022 TRANSMITTAL LETTER CHECKLIST WELL NAME: ______________________________________ PTD: _____________________________________________ ___ Development ___ Service ___ Exploratory ___ Stratigraphic Test ___ Non-Conventional FIELD: __________________________ POOL: ____________________________________ Check Box for Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI LATERAL (If last two digits in API number are between 60-69) The permit is for a new wellbore segment of existing well Permit Number _____________, API Number 50-______________________. Production from or injection into this wellbore must be reported under the original API Number stated above. Spacing Exception The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce or inject is contingent upon issuance of a conservation order approving a spacing exception. The Operator assumes the liability of any protest to the spacing exception that may occur. Dry Ditch Sample All dry ditch sample sets submitted to the AOGCC must be in no greater than 30-foot sample intervals from below the permafrost or from where samples are first caught and 10-foot sample intervals through target zones. Non- Conventional Well Please note the following special condition of this permit: Production or production testing of coal bed methane is not allowed for this well until after the Operator has designed and implemented a water-well testing program to provide baseline data on water quality and quantity. The Operator must contact the AOGCC to obtain advance approval of such a water-well testing program. Well Logging Requirements 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 the Operator in the attached application, the following well logs are also required for this well: Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for all well logs run must be submitted to the AOGCC within 90 days after completion, suspension, or abandonment of this well, or within 90 days of acquisition of the data, whichever occurs first. BELUGA-TYONEK GASNINILCHIK Kalotsa 13 226-005 WELL PERMIT CHECKLISTCompanyHilcorp Alaska, LLCWell Name: NINILCHIK UNIT KALOTSA 13Initial Class/TypeDEV / PENDGeoArea820Unit51432On/Off ShoreOnProgram DEVWell bore segAnnular DisposalPTD#:2260050Field & Pool:NINILCHIK, BELUGA-TYONEK GAS - 562503NA1 Permit fee attachedYes C061505, ADL359242, ADL 3843722 Lease number appropriateYes3 Unique well name and numberYes NINILCHIK, BELUGA-TYONEK GAS - 562503 - governed by CO 701C4 Well located in a defined poolYes5 Well located proper distance from drilling unit boundaryYes6 Well located proper distance from other wellsYes7 Sufficient acreage available in drilling unitYes8 If deviated, is wellbore plat includedYes9 Operator only affected partyYes10 Operator has appropriate bond in forceYes11 Permit can be issued without conservation orderYes12 Permit can be issued without administrative approvalYes13 Can permit be approved before 15-day waitNA14 Well located within area and strata authorized by Injection Order # (put IO# in comments) (For NA15 All wells within 1/4 mile area of review identified (For service well only)No16 Pre-produced injector: duration of pre-production less than 3 months (For service well only)No17 Nonconven. gas conforms to AS31.05.030(j.1.A),(j.2.A-D)Yes18 Conductor string providedYes19 Surface casing protects all known USDWsYes20 CMT vol adequate to circulate on conductor & surf csgYes21 CMT vol adequate to tie-in long string to surf csgYes22 CMT will cover all known productive horizonsYes Casing design calcs not included.23 Casing designs adequate for C, T, B & permafrostYes24 Adequate tankage or reserve pitNA25 If a re-drill, has a 10-403 for abandonment been approvedYes26 Adequate wellbore separation proposedYes27 If diverter required, does it meet regulationsYes28 Drilling fluid program schematic & equip list adequateYes29 BOPEs, do they meet regulationYes MPSP = 2078 psi, BOP test rated to 5k psi (BOP test to 2500 psi)30 BOPE press rating appropriate; test to (put psig in comments)Yes31 Choke manifold complies w/API RP-53 (May 84)Yes32 Work will occur without operation shutdownNo33 Is presence of H2S gas probableNA34 Mechanical condition of wells within AOR verified (For service well only)Yes35 Permit can be issued w/o hydrogen sulfide measuresYes Expected pressure range is 0.43 to 0.479 psi/ft (8.3 to 9.2 ppg EMW), increased pressure in Lwr BLGA / TYNK36 Data presented on potential overpressure zonesNA37 Seismic analysis of shallow gas zonesNA38 Seabed condition survey (if off-shore)NA39 Contact name/phone for weekly progress reports [exploratory only]ApprTCSDate1/23/2026ApprBJMDate2/9/2026ApprTCSDate1/23/2026AdministrationEngineeringGeologyGeologic Commissioner:Date:Engineering Commissioner:DatePublic CommissionerDateJLC 2/10/2026