St. Lucia 76 2833 #11H Completion Procedure

April 19, 2016

1 4/19/16

AFE #: 1600428 XTO WI: 100% XTO ID: 518262 API #: 42-301-32845 ELEVATION: KB: 3124'; GL: 3099', KB-GL = 25' SURF. LOCATION: Sec.21 Blk 76 Abst 1237, 400 FSL & 840 FWL BH LOCATION: Sec 33 Blk 76 Abst 1237, 200 FSL & 840 FWL DIRECTIONS: From Jal, take hwy 128 W to MM 23. N on C1 to State Line

(road turns into 652 on Texas side). Turn left at water station and go 4 miles. Right 2.2 miles. Turn left (XTO sign) just before Pumpjack and go 2 miles. Right at XTO sign for 100 yards. Left for 4 miles to “T”. Right 2 miles. Right 0.5 to location. (attached)

DOWNHOLE WELL DATA:

CONDUCTOR CASING: 20" 53#, B @ 90'. 65 sx. Circ

INTERMEDIATE CSG: 9-5/8", 40#, J-55 @ 4803'. 2915 sx. Circ. DV @ 1091’ PRODUCTION CSG: 7", 29# CYP-110 @ 11606'. 1195 sx. MJ @ 10675’. TOC=2500’?

LINER: 4 1/2", CYHCP-110: 13.5# 22,579’. 865 sx 11#, 1315 sx 13.2#.

TOC = ?’ (CBL) Marker Jt: 16,070’ and 21,142’ BURST = 10,640 psi Liner Top: 11123' MD. KOP: 11400' MD. 90 Deg: 12500' MD, 12090' TVD PBTD: 22486' MD, 12040’ TVD TD: 22579' MD, 12040' TVD

St. Lucia 76 2833 #11H Completion Procedure

April 19, 2016

2 4/19/16

Contacts:

Company Service Contact Office Cell EmailXTO Engineer David Luna 620-6742 296-3955 david_luna@xtoenergy.comXTO Consultant Mo Gomez 894-7980 Anselmo_Gomez@xtoenergy.comXTO Consultant Tom Smithhart 741-0866 Tommy_Smithhart@xtoenergy.comXTO Engineer Blake Short 254-1749 Blake_Short@xtoenergy.comBaker Fracing Matt Johnson Acct Mgr 556-3262 Matthew.Johnson5@bakerhughesBaker Fracing Javier 685-8937 238-0298 Javier.Rodriguez@bakerhughes.comBaker Frac Hobbs V. Matinez 575-392-5556 575-441-1420 victor.martinez4@bakerhughes.comCudd Toe Prep Kenny Jones 575-631-7456 Kjones@cudd.comWeatherford Frac Head Payton Kemp 250-3501 Payton.Kemp@Weatherford.comWeatherford Frac Head Brad Franks 307-705-3196 Bradley.Franks@weatherford.comViking Coil Chem Brody Melton 888-865-3714 553-8860 brody.melton@viking-ct.comViking Coil Jeramiah 888-865-3714 664-8008 jeramiah.maynard@viking-ct.comViking Coil S. Crabtree 888-865-3714 254-7488 shawn.crabtree@viking-ct.comViking Bit/Motor Jeramiah 888-865-3714 664-8008 jeramiah.maynard@viking-ct.comAPS H2O Transfer Chester Miller 575-746-1096 575-513-9396 cmiller@americansafety.netAPS H2O Transfer Coly Hokett 575-746-1096 575-746-7350 chokett@americansafety.netNeptune ClO2 Alex Gonzalez 885-672-6700 360-9020 agonzalez@neptunesc.comNeptune ClO2 Lambert G. 885-672-6700 360-9376 lgonzalez@neptunesc.comGE: Well Head/Tree Toi Blalack 368-0661 210-8849 faletoi.blalack@ge.comGE: Well Head/Tree Chris Weick 368-0661 210-3504 Christopher.Weick@ge.comGE: Well Head/Tree Nick Poltiz 368-0661 260-8298 Nick.Politz@ge.comWeatherford Packer Trey Hamilton 575-393-1717 806-215-5722 Trey.Hamilton@weatherford.comWeatherford Packer Eric Reyes Sales 634-0354 Eric.reyes@weatherford.comWeatherford Packer Chandler Butt Midland Sale 713-252-1597 Chandler.Butt@weatherford.comDesert Rch Water Mike Huber Manager 557-9580 Mike_Huber52@yahoo.comRancher Water Pete Nolen Co Manager 337-873-7383 petenolen@ymail.comGenco Trl,trsh,potty Watt Fuller 575-236-6010 528-9826 wfuller@genco.usGenco lt plnt, manlft Will Worley 563-1859 210-0477 wworley@genco.usOF Testing Flowback BJ 575-825-1175 bobbyfowler2@gmail.comOF Testing Flowback Bobby Fowler 575-390-3293 welltestr@aol.comOF Testing Sales Leslie Koerth 361-571-2438 Lesliekoerth@gmail.comMVA Trking Truck/Tanks Ricky Mares 806-215-3685 rmares1215@gmail.comRenegade Wireline KJ Stanton 524-7239 312-0797 KJStanton@renegadewls.comRenegade Wireline Boadie Hobbs 686-1106 638-8308 bhobbs@renegadewls.comRenegade Wireline Jay Young 686-1106 638-9793 jyoung@renegadwls.comRenegade Wireline Adam Estes 686-1106 853-1423 adamestes1011@yahoo.comWeatherford Plugs John Burke 238-6702 john.burke2@weatherford.comDownhole T Plugs Richard 803-7505 Richard.South erland@downholetechnology.comDownhole T Plugs Kasey 713-851-2269 Kasey.West brook@downholetechnology.com

St. Lucia 76 2833 #11H Completion Procedure

April 19, 2016

3 4/19/16

RECOMMENDED PROCEDURE Frac Date: May 16th Before frac

1) MIRU WL unit and Mast. Run 4 ½” JB-GR to 11600’ (18 deg). Run CBL (2500 psi) from 11600’ to 9000’ and 400’ strip across TOC (2500’?). 4 ½” MJ:16070 & 21142. 7” MJ:10,675’.

2) MIRU 10K Frac Valve (two), Flow Cross, & Frac Head. RU 10K pump. Hold at 7200

psi 10 min, check for leaks. Continue up to 8100 psi and open toe sleeve. Inject in at max pump rate. Take screen shot and send to engineer. Flush with 50 bbl FW.

3) Install riser w/ valve on 7” by 9 5/8” valve in cellar. Pressure up to 500 psi.

1 week before frac 4) MIRU 1 500 BBL Gas Buster, 2 500 bbl Return Tanks (next to Gas Buster) and 8 frac

tanks.

5) Load 8 working frac tanks and XTO Frac pit w/340,000 bbls fresh water. Make sure pond is full. Desert Rand is supplying all the water at 9,000 bpd. Confirm water tests (CLO2 in it) with Frac Co. Water should be treated with ClO2 during filling of frac tanks. ClO2 can setup off of the location to save room if necessary.

6) MIRU 10K manifold and hookup to Gas Buster, Flowback/Return tanks, and pit.

7) MIRU wireline company. Will use 10k Lubricator system.

8) MIRU frac equipment. Ensure all surface iron is rated for 10K working pressures. PT lines to 10000 psi. Install 1000 psi pop-off on backside (7” X 9 5/8”). Hook up transducer to monitor this.

9) Frac stage 1 (toe sleeve: 22438’) at 50 bpm. Follow pump schedule below.

St. Lucia 76 2833 #11H Completion Procedure

April 19, 2016

4 4/19/16

10) TIH with 4 guns (8, 8, 9, & 9 shots) using 10k Lube and perf as follows:

Stage 1: Toe Sleeve: 22480' 50 bpm

STG Fluid PPA (Gal) (BBL) BPM (lbs) Slurry Slurry (min)

Pad SW 7,500 178.6 50 178.6 179 3.6100 M SW 0.5 10,000 238.1 50 5,000 243.5 422 4.9100 M SW 1 10,000 238.1 50 10,000 248.8 671 5.0100 M SW 1.5 11,000 261.9 50 16,500 279.6 950 5.6100 M SW 2 11,000 261.9 50 22,000 285.5 1,236 5.740/70 SW 0.5 14,000 333.3 50 7,000 340.8 1,577 6.8

" SW 1 14,000 333.3 50 14,000 348.3 1,925 7.0" SW 1.5 15,000 357.1 50 22,500 381.3 2,306 7.6

" SLC SW 1.8 11,111 264.5 50 20,000 286.0 2,592 5.7Flush SW 21,000 500.0 50 500.0 3,092 10.0

124,611 2,967 117,000 3,092 61.8TOTALS:

St. Lucia 76 2833 #11H Completion Procedure

April 19, 2016

5 4/19/16

11) Frac Wolfcamp A formation (34 stages) fr/22438' (done above) – 12500' down 4 ½” liner at 80 BPM (786 bbls 10% HCl) w/ Slickwater carrying 15M lbs (7M 100, 6M 40/70, &

Plug & Perf Information 80 bpm 6 spf, 3 1/8"

Stage Plug 9 holes 9 holes 8 holes 8 holes

2 22355 22325 22250 22175 22100 34 shots per stage

3 22055 22025 21950 21875 21800 75' between clusters

4 21755 21725 21650 21575 21500

5 21455 21425 21350 21275 21200

6 21155 21125 21050 20975 20900

7 20855 20825 20750 20675 20600

8 20555 20525 20450 20375 20300

9 20255 20225 20150 20075 20000

10 19955 19925 19850 19775 19700

11 19655 19625 19550 19475 19400

12 19355 19325 19250 19175 19100

13 19055 19025 18950 18875 18800

14 18755 18725 18650 18575 18500

15 18455 18425 18350 18275 18200

16 18155 18125 18050 17975 17900

17 17855 17825 17750 17675 17600

18 17555 17525 17450 17375 17300

19 17255 17225 17150 17075 17000

20 16955 16925 16850 16775 16700

21 16655 16625 16550 16475 16400

22 16355 16325 16250 16175 16100

23 16055 16025 15950 15875 15800

24 15755 15725 15650 15575 15500

25 15455 15425 15350 15275 15200

26 15155 15125 15050 14975 14900

27 14855 14825 14750 14675 14600

28 14555 14525 14450 14375 14300

29 14255 14225 14150 14075 14000

30 13955 13925 13850 13775 13700

31 13655 13625 13550 13475 13400

32 13355 13325 13250 13175 13100

33 13055 13025 12950 12875 12800

34 12755 12725 12650 12575 12500

St. Lucia 76 2833 #11H Completion Procedure

April 19, 2016

6 4/19/16

2M 40/70 SLC). Est. TP 8200 psig. Max TP @ 9400 psig. Set global “kick out” on frac pumps to 9500 psi. Stage individual pump kick outs from 9400 psi to 9600 psi (popoff=9600 psi). Monitor backside throughout entire frac job.

*Please see Frac Schedule below:

12) RDMO Frac equipment.

Stage 2 thru 4: PnP Stages, 80 bpm

STG Fluid PPA (Gal) (BBL) BPM (lbs) Slurry Slurry (min)

PnP SW 5,000 119.0 14 119.0 119 8.5Acid 10% 1,000 23.8 42 23.8 143 0.6Pad SW 20,000 476.2 80 476.2 619 6.0

100 M SW 0.5 42,000 1000.0 80 21,000 1022.5 1,642 12.8100 M SW 1 42,500 1011.9 80 42,500 1057.4 2,699 13.2100 M SW 1.5 42,000 1000.0 80 63,000 1067.5 3,766 13.3100 M SW 2 42,000 1000.0 80 84,000 1090.0 4,856 13.640/70 15# 0.5 60,000 1428.6 80 30,000 1460.7 6,317 18.3

" 15# 1 60,500 1440.5 80 60,500 1505.3 7,823 18.8" 15# 1.5 60,000 1428.6 80 90,000 1525.0 9,348 19.1

" SLC 15# 1.8 33,333 793.7 80 60,000 857.9 10,205 10.7Flush SW 18,900 450.0 80 450.0 10,655 5.6

427,233 10,172 451,000 10,655 140.5TOTALS:

Stage 5 thru 34: PnP Stages, 80 bpm

STG Fluid PPA (Gal) (BBL) BPM (lbs) Slurry Slurry (min)

PnP SW 5,000 119.0 14 119.0 119 8.5Acid 10% 1,000 23.8 42 23.8 143 0.6Pad SW 20,000 476.2 80 476.2 619 6.0

100 M SW 0.5 42,000 1000.0 80 21,000 1022.5 1,642 12.8100 M SW 1 42,500 1011.9 80 42,500 1057.4 2,699 13.2100 M SW 1.5 42,000 1000.0 80 63,000 1067.5 3,766 13.3100 M SW 2 42,000 1000.0 80 84,000 1090.0 4,856 13.640/70 SW 0.5 60,000 1428.6 80 30,000 1460.7 6,317 18.3

" SW 1 60,500 1440.5 80 60,500 1505.3 7,823 18.8" SW 1.5 60,000 1428.6 80 90,000 1525.0 9,348 19.1

" SLC SW 1.8 33,333 793.7 80 60,000 857.9 10,205 10.7Flush SW 18,900 450.0 80 450.0 10,655 5.6

427,233 10,172 451,000 10,655 140.523.8 bbls of acid per stage = 786 bbls (33,000 gallons). 9400 psi max treating pressureTOTALS:

St. Lucia 76 2833 #11H Completion Procedure

April 19, 2016

7 4/19/16

13) Wait 24 hours after last stage was pumped before starting cleanout.

14) Perform 2 3/8” Coil cleanout with JZ bit, 3 1/8” motor, and AVs at 220+. CO to where you tag Toe Valve (22438’). RDMO Coil.

15) MIRU WL trk, 5k lubricator, and mast truck. TIH w/WL & set 7” prod. Packer

w/Ceramic Rupture Disk (packer diagram attached) at 11000’ (correlate to MJ at 10675’). Record casing pressure prior to setting. RDMO WL. Bleed down casing.

16) MIRU PU. MI 2-7/8", 6.5#, N-80, 8RD, EUE tbg.

17) TIH w/on/off tool. Circulate hole w/packer fluid. Connect tubing with packer per tool hand landing procedure.

18) RU GE 5K Tree. Install test equipment.

19) MIRU SL unit w/5k lubricator. TIH w/“rupture” bar. Pressure tubing to pressure

recorded prior to setting packer. Break rupture disc at 11000'. Monitor & record pressure. TOH & RDMO SL. Open well up to test equipment. RDMO PU.

20) Open 7” by 9 5/8” valve to remove any pressure.

21) Flow test well through test/rental equipment. Monitor fluids for any debris (sand). Keep flow rate above 160 BPH. Once oil & gas hits then turn through separator and keep rate above 125 BPH. Turn through production facilities once well has cleaned up.

Once well stops flowing: Consult w/Midland on artificial lift. Prepared by:_________________________________ Date:_______________

David Luna Approved by:________________________________ Date:_______________

Jack Mohr Approved by:________________________________ Date:_______________ James Fort

St. Lucia 76 2833 #11H Completion Procedure

April 19, 2016

8 4/19/16

EOL: 22,577'TVD: 12,040'TD: 22,579'PBTD:22,486'

4-½” 13.5#, CYHC P-110 LINER FR/11,123'-22,579'. CMT’D W/580 SX IN 6-1/8" HOLE

St. Lucia 76 2833 11H400' FSL & 840' FWL

SEC 21, Blk 76, Abst 1237PSL/Ross SURVEY

Loving CO, TXAPI# 42-301-32845

ELEV: GL: 3099'KB: 3124'

AGL: 25'

7" 29#, CYP-110 CSG (6.125" DRIFT) SET @ 11606' (TVD =11606'). CMT’D STG 1 W/ 730 SX 11.5#, 2ND STG 465 SX H 14.4#. MJ @ 10675'. TOC @ 2500' (CBL). 8-¾” HOLE.

39' MKR JT:10675'

Liner Top @ 11123'KOP @ 11400'Liner MJ @ 16070' & 21143'

FS @22,577' FC @22,531'LC @22,486'Toe@22,438'

20" CONDUCTOR @ 90'. CMT’D W/ 65SX OF REDI-MIX. CIRC, 24" HOLE.

9-5/8" 40#, J-55 @ 4803'. CMT’D W/ 2915 SX. CIRC12-1/4” HOLE

TOC @ ?' (CBL)

END OF CURVE: 12,500'TVD: 12,070'

DV @ 1091'

Plug & Perf Information 80 bpm 6 spf, 3 1/8"

Stage Plug 9 holes 9 holes 8 holes 8 holes

2 22355 22325 22250 22175 22100

3 22055 22025 21950 21875 21800

4 21755 21725 21650 21575 21500

5 21455 21425 21350 21275 21200

6 21155 21125 21050 20975 20900

7 20855 20825 20750 20675 20600

8 20555 20525 20450 20375 20300

9 20255 20225 20150 20075 20000

10 19955 19925 19850 19775 19700

11 19655 19625 19550 19475 19400

12 19355 19325 19250 19175 19100

13 19055 19025 18950 18875 18800

14 18755 18725 18650 18575 18500

15 18455 18425 18350 18275 18200

16 18155 18125 18050 17975 17900

17 17855 17825 17750 17675 17600

18 17555 17525 17450 17375 17300

19 17255 17225 17150 17075 17000

20 16955 16925 16850 16775 16700

21 16655 16625 16550 16475 16400

22 16355 16325 16250 16175 16100

23 16055 16025 15950 15875 15800

24 15755 15725 15650 15575 15500

25 15455 15425 15350 15275 15200

26 15155 15125 15050 14975 14900

27 14855 14825 14750 14675 14600

28 14555 14525 14450 14375 14300

29 14255 14225 14150 14075 14000

30 13955 13925 13850 13775 13700

31 13655 13625 13550 13475 13400

32 13355 13325 13250 13175 13100

33 13055 13025 12950 12875 12800

34 12755 12725 12650 12575 12500

Stage 1: Toe Sleeve: 22438' 50 bpm

Alpha Sleeve Performance Calculator Date of Analysis:

Engineer:

Well Parameters Operational Pressures Customer:

Static BHT: 159 deg F Circulation Max Pressure: 3,500 psi Well Name:

Field:

Total Vertical Depth (TVD) @ Alpha Sleeve: 12,070 ft Max. Cementation Pumping Pressure: 3,500 psi End Connections:

RIH Completion Fluid Wt.: 12 ppg Max. Displacement Pressure: 4,000 psi

Cement Wt.: 13.2 ppg Additional Plug Bump Pressure: 1,000 psi

Displacement Completion Fluid Wt.*: 10 ppg

* Note - this is used to determine the opening pressure Notes:

Test and Shift Pressures Rev. L (11/13)

Approximate Casing Test Pressure: 0 psi

Min. Desired Shift Pressure: 8,500 psi

Max. Topside Pressure**: 9,500 psi

** Note - wellhead or casing pressure limit

AT3 Design

Option 1 27 Option 2 28 Option 3 29

Min Surface Pressure 7,563 psi Min Surface Pressure 8,058 psi Min Surface Pressure 8,551 psi

Nominal Surface Pressure 8,140 psi Nominal Surface Pressure 8,655 psi Nominal Surface Pressure 9,169 psi

Maximum Surface Pressure 8,716 psi Maximum Surface Pressure 9,252 psi Maximum Surface Pressure 9,787 psi

Min Absolute Pressure 13,839 psi Min Absolute Pressure 14,334 psi Min Absolute Pressure 14,828 psi

Nominal Absolute Pressure 14,416 psi Nominal Absolute Pressure 14,931 psi Nominal Absolute Pressure 15,446 psi

Maximum Absolute Pressure 14,993 psi Maximum Absolute Pressure 15,529 psi Maximum Absolute Pressure 16,064 psi

RIH Circulation Buffer: 2,808 psi RIH Circulation Buffer: 3,302 psi RIH Circulation Buffer: 3,796 psi

Cementation Buffer: 2,054 psi Cementation Buffer: 2,549 psi Cementation Buffer: 3,043 psi

Displacement Buffer: 2,563 psi Displacement Buffer: 3,058 psi Displacement Buffer: 3,551 psi

Testing Percentage of Nominal 0% Testing Percentage of Nominal 0% Testing Percentage of Nominal 0%

Approx. Casing Test Pressure should be under 90% Approx. Casing Test Pressure should be under 90% Approx. Casing Test Pressure should be under 90%

92% 97% 103%

Max. Casing Test Pressure 7,326 psi Max. Casing Test Pressure 7,789 psi Max. Casing Test Pressure 8,252 psi

Activator Part Number 10412262 Activator Part Number 10412263 Activator Part Number 10411823

Company Representative: Baker Hughes Representative:

Date: Date:

4.5" 13.5# P-110 CDC-HTQ

Closest SelectionLower Pressure Higher Pressure

Lowered Min. Desired Shift Pressure from 8,800 psi to 8,500 psi to

allow for target openning pressure to be achieved.

RIH Cementation and Displacement Pressures are listed as Max

Parameters while maintaining an adaquate buffer.

14-Mar-16

David Luna

XTO Energy

St. Lucia 76 2833 #11H

Phantom, Wolfcamp

Max. Req. Pressure Percentage of Max. Allowable

Topside Pressure

Max. Req. Pressure Percentage of Max.

Allowable Topside Pressure

Max. Req. Pressure Percentage of Max. Allowable

Topside Pressure

X X