Horizontal San Andres Case HistoriesDecember 4-7, 2017
Midland, TX
2
FOUNDED
• Steward Energy
REEVES CO. ENTRY
• Build 10k acre Reeves Co. position
• Prove 5000’ column with vertical drilling & testing program and 1
HZ Wolfcamp “A” 2mile lateral
EXIT
• Marketed sale to APC
• 2.95X ROI in 2 yrs
ESCROW PERIOD
• Study markets
• Scout prospects
• Assemble team
FOUNDED
• Steward Energy II
SAN ANDRES ENTRY
• Masten, Michael, Arrowhead, & Ariel
Prospects
• ~30,000 net acres
CONFIRMATION
• Masten, Browning, Colt, Arrowhead all
gather key petrophysical data and
test concepts
EXPANSION
• Additional equity raised
• 5 bank RBL Credit Facility
• Bronco, Mustang, & Corona strategically add to core footprint
2017 DEVELOPMENT
PROGRAM
• 1.5 rig program
• Leasehold commitments
• Build production base
2018+ DEVELOPMENT
PROGRAM
• 1 rig program drilling from cash flow
• Extend commercial limits throughout 100k
acres leasehold
• Down spacing tests
The Steward Energy Story
2012 2014 2015 2016
• Concerned with commodity price instability and cost structure of unconventional plays
• Goal: build an E&P that would thrive in extended $40/BBL environment
• Refocus on the fundamental marriage of science and business necessary for an independent E&P
• Assemble an enhanced team
• “Unconventional Development of Conventional Oil Fields”
2017 2018+
3
Preliminary Focus
(1)Ross & Ross, 1987(2)Central Basin Platform Stratigraphy – Ruppel, 2002; Kerans, 2006; Ruppel & Ward, 2013(3)EIA (Slaughter, Levelland, Wasson, Seminole fields) – https://www.eia.gov/naturalgas/crudeoilreserves/top100/pdf/top100.pdf(4)Kuskraa, 2014, Advanced Resources International; estimates from Yoakum, Terry, Dawson, and Gaines counties only -http://www.co2conference.net/wp-content/uploads/2015/01/3-Kuuskraa_Carbon_Management_Workshop_Midland_TX_DEC_2014.pdf
• Since early 2015 Steward Energy has evaluated over 100 deals across many NA Basins, both marketed and unsolicited, ranging in value from $100K to over $1B
• Based on the ability to create value in a low commodity price environment, focus quickly turned to a newly developing play in the Permian – horizontal San Andres
• Steward Energy’s development is focused in an area that contains 4 of the top 50 oil fields (by reserves) in the United States(3)
• Total resource potential exceeds 100 Billion Barrels of Oil(4)
• Core-measured porosity values can exceed 10% in reservoir interval
• Historically underdeveloped areas due to technological and economic limitations during early development
Permian
1st SS
Cutoff
Glorieta Glorieta
Lower San Andres
SERIES/AGE (Ma(1))
Delaware Basin
Central Basin Platform(2)
Midland Basin
“Clearfork Sh”
“Avalon Sh”
268
Upper San Andres
Non-DepositionBrushy Canyon
Brushy Cyn Equivalent
Cherry Canyon
271
260
Upper San Andres
Upper San Andres
Lower San Andres
Lower San Andres Shale
(NM) (TX)(NM) (TX)
4
SEII Asset Summary
Bronco Prospect - Yoakum and Lea CountyNet Mineral Acres 19,081 (88.00% SEII WI)
Michael Prospect - Yoakum CountyNet Mineral Acres 13,132 (93.75% SEII WI)
Arrowhead Prospect - Yoakum CountyNet Mineral Acres 8,182 (81.5% SEII WI)
Masten Unit - Cochran CountyNet Mineral Acres 3,194 (100% SEII WI)
Firewater Prospect - Gaines CountyNet Mineral Acres 4,707 (87.5% SEII WI)
Ariel Prospect - Cochran CountyNet Mineral Acres 4,665 (87.5% SEII WI)
Mustang Prospect – Yoakum CountyNet Mineral Acres 7,522 (87.5% SEII WI)
Apache Corona - Yoakum CountyNet Mineral Acres 22,291 (79% SEII WI)
SEII TOTALOperated Leasehold 97,647 Gross; 82,774 NetOperated Production 12,600 BOEPD Gross*; 8,300 BOEPD Net**November 2017 MTD average
What is a Residual Oil Zone (ROZ)?5
Movable hydrocarbons have been swept leaving water plus residual oil molecules clinging to the rock The resultant pressure of the incompressible water in the pore is so great that the compressible oil molecules can’t move
For oil to mobilize, the pore must first be de-pressurized resulting in high initial water production
With some of the incompressible water removed, oil molecules expand, coalesce, & release from the pore surface The well then produces both oil and water
*A horizontal well with a multi-stage frac expedites this de-pressuring process
1
2
3
Imagine an ROZ pore space….
ROZ – Pre-Frac1 ROZ – Initial Frac2 ROZ – Post-Frac3
Residual Oil Rim
Water
Grain De-Pressuring Water
Water
Grain
Movable Oil
Water
Grain
Stimulated Frac
Stimulated Frac
Oil-Wet Rock Oil-Wet Rock Oil-Wet Rock
How do we Recognize a Residual Oil Zone (ROZ)?6
Arrowhead 717H Pilot
Anhydrite (Not ROZ)
Dolomite(ROZ)
Limestone and/or Tight Dolomite
(Not ROZ)
Top ROZ
Base ROZ
In the San Andres of Yoakum County, an ROZ interval is identified by several key variables
• Lithology ROZ interval typically is dolomitic and sits sandwiched between an interval of anhydrite above and limestone beneath
• Log Character ROZ intervals often have a distinctive “bow shaped” profile in the Resistivity and Porosity portions of their logs
• Cuttings, Samples and Well Tests Old wells are ripe with information and these are used to identify intervals with mud log shows, fluorescence, and even sulfur water observed in Drill Stem Tests (part of biogenic processes as bacteria eat components of the oil)
PorosityGR Resistivity
www.residualoilzones.com
What are the limits of ROZ development?
• The lower limits of ROZ are governed by an “economic limit” rather than a distinct oil-water contact
• Developing multiple “benches” will be more appropriate to effectively drain ROZ intervals
• Resulting economics are linked to a number of factors including oil price, water disposal, frac efficiency, drainage, and oil-gas takeaway capability
• Similar to the evolution of these anchor San Andres fields, Steward believes the full & effective development of the ROZ resource will span generations
100% Oil Saturation 0%
Oil Saturation Profile
??? ROZ Economic Limit ???
ROZ
MPZ
SwSatu
ration
Increases
7
Reference Map
Digital Logs
Steward Acreage
San Andres Field Outlines
Now that we know what ROZ is and how to recognize it on a log, let’s look at a distribution of wells across the area…
8
Petrophysical Processed Log
Bronco
Michael
Arrowhead
Corona
Mustang
Masten
Ariel
Bronco Prospect9
• “Conventional” reservoir properties in the Chambliss (movable water + movable hydrocarbon) that transition downward to a ROZ system in the Brahaney (movable water + immovable hydrocarbon)
• In ROZ systems, hydrocarbons don’t move until pressure in the pore space is decreased high initial water production, then the well produces water + hydrocarbon once pressure is low
• Bronco production is taking advantage of both types of systems
Marker
Chambliss(Conventional)
Brahaney(ROZ)
1 2 3 4 5 6What A Melon 1H (Pilot)
Track Description
1: Gamma Ray
2: Res (>10 Ohm-m)
3: Eff Por (> 2%)
4: Mineralogy
5: Saturations
6: Oil In Place
Mineralogy
Clay
Quartz
Calcite
Dolomite
Anhydrite
Saturations
Oil
Free Water
Arrowhead Prospect10
• Arrowhead-like ROZ reservoirs consist of:
1) Tight, anhydrite-rich top (with increasing percentage towards the north)
2) Reservoir section with increasing water saturation deeper into the section
3) Tight, limestone or dolomitic base
• The tight rock above and below are acting as “buffers” to help constrain frac growth
Track Description
1: Gamma Ray
2: Res (>10 Ohm-m)
3: Eff Por (> 2%)
4: Mineralogy
5: Saturations
6: Oil In Place
Mineralogy
Clay
Quartz
Calcite
Dolomite
Anhydrite
1 2 3 4 5 6
Marker
Saturations
Oil
Free Water
Bound Water
Top ROZ
Base ROZ
Increasing water saturation towards base
Arrowhead 717H (Pilot)
Michael Prospect11
Browning State 5063 1H (Pilot)
• Browning-like ROZ reservoirs are similar to Arrowhead-like and consist of:
1) Tight, anhydrite-rich top
2) Reservoir section with increasing water saturation as you move deeper into the section
3) Tight, limestone or dolomitic base
• The major obstacle is how THICK the overall column is there is little to no containment of fracgrowth downward hence access to tremendous amounts water
1 2 3 4 5 6
Marker
Top ROZ
Base ROZ
Track Description
1: Gamma Ray
2: Res (>10 Ohm-m)
3: Eff Por (> 2%)
4: Mineralogy
5: Saturations
6: Oil In Place
Mineralogy
Clay
Quartz
Calcite
Dolomite
Anhydrite
Saturations
Oil
Free Water
Bound Water
Increasing water saturation towards base
Typical Drilling Program
12-1/4” surface hole – 2,400’9-5/8”, J-55, 36#, LTC casingDrilled to 2,400’ to cover problematic red beds
8-3/4” production hole – ~ 10,800’ for a 1.0 mile, ~13,400’ for a 1.5 mile lateralBuild curve with 9O/100’, add 150’ tangent section at 45O, finish curve at 10.5O/100’
-tangent section minimizes gas interference in ESP’s
5-1/2”, L-80, 20#, BTC casing – 8,990# burst, 7,817# with safety factorAirlock casing floatation system used in 1.5 mile lateral to aide in running casing
Geo-steering in the lateral prevents porpoising (unwanted sumps), control isolated to +/- 5’ window
Off-lease locations allow for first penetration 100’ from lease lineShortened shoe track allows for last penetration 100’ from lease line – optimized lateral length of 5,080’
Pressure activated toe sleeve allows for interventionless pump down for first frac stage
12
Drilling Optimization to Maximize Lateral Length
• Steward has optimized drilling locations to yield about 15% more completed lateral length
• Off lease surface locations: ~100’ First Take Point from heel (closest allowed by field rules)
• Shorter casing shoe track: ~100 Last Take Point from toe (closest allowed by field rules)
• Wells are directionally controlled to optimize production with a S to N “toe-up” lateral
• In spite of increased footage drilled and directional control, the incremental costs are negligible compared to NPV of additional completion interval
• Casing float system: Reduces casing run time on longer laterals and assists getting casing to TD
Previous TD ~ 10,000’ MD
Current TD ~ 11,000’ MD
13
Bottom Hole Location
Is Drilling Orientation Important?
• Analysis of 16 - 1.5 mile laterals in the Bronco Prospect revealed that laterals drilled from South to North outperform those wells that were drilled North to South
• This sample suggest ~29% better EUR for a 1.5 mile well drilled from South to North
• 1Q17 Steward tested this theory on the 1.0 mile Hair Splitter 454 Lease and similarly saw 26% higher EUR’s in the S-N infill wells
Orientation Avg Peak Rate Avg EUR
N-S (7 wells) 459 BOPD 509 MBO
S-N (9 wells) 454 BOPD 656 MBO
S-N N-S
14
Completion Evolution
• SEII is continually working to optimize drilling and completion techniques
*Final Manzano frac pumped 06/2016
• The updated San Andres 1.0 Mile type curve is based on a $2.6MM AFE• Based upon a blend of Steward and Pre-Acquisition results and associated costs
• A current 1.0 mile AFE is ~ $3.1MM due to:• Longer drilling time to maximize lateral length• Higher completion costs from increased stage count and sand volume
• Frac alone is ~ $400,000 higher than type curve costs
• Based on early results, longer lateral length and denser perf spacing outperform the type curve but more time is needed to confirm
“1.0” Mile Lateral
Completed Length
Perf Spacing
Stage Count
100 Mesh Sand/Stage
30/50 Sand/Stage
Pre-Acquisition* 4100 320 13 45,000 145,000
Steward Gen 1.1 5080 350 14 45,000 145,000
Steward Gen 1.2 5080 335 16 45,000 145,000
Steward Gen 2.1 5080 310 18 7,500 145,000
Steward Gen 2.2 5080 250 20 5,000 145,000
Steward Gen 3.1 5080 250 20 5,000 205,000
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Drilling Program – Bronco Completions
• Post – Acquisition drilling program includes 21 wells already completed (two pending oil production)WellLateral Length
Online Cum BOEPeak Rate,
BOEPDCurrent Rate,
BOEPD
Stage Lengthft/stage
Frac Stages 100 Mesh#/stage
30/50 #/stage
Cousin Willard 2H 1.0 11/22/2016 69,872 584 143 362 12 45,000 145,000
Blazin Skies 1H 1.0 1/26/2017 38,830 297 146 348 14 45,000 145,000
Whiteport 1H 1.0 2/7/2017 128,817 918 491 344 14 45,000 145,000
Hair Splitter 2H 1.0 2/25/2017 88,015 952 215 358 14 45,000 135,000
Hair Splitter 4H 1.0 3/7/2017 90,229 889 316 313 16 45,000 145,000
Banjo Bill 2H 1.5 4/8/2017 96,822 721 331 318 24 7,000 145,000
Blazin Skies 4H 1.0 5/3/2017 66,100 689 218 310 16 7,500 145,000
Whiteport 4H 1.0 5/16/2017 79,893 772 402 269 18 5,000 145,000
Nevermind 3H 1.0 6/2/2017 32,444 554 190 252 20 5,000 145,000
Pinkman 4H 1.0 6/3/2017 6,051 112 29 254 18 5,000 145,000
Backslider 2H 1.0 6/6/2017 44,428 470 242 245 20 5,000 145,000
Say My Name 6H 1.0 6/21/2017 1,632 81 14 263 16 5,000 187,000
Pollos Hermanos 5H 1.5 7/9/2017 19,544 368 129 277 24 5,000 145,000
Paradise City 583 4H 1.5 7/14/2017 31,931 439 335 248 30 5,000 145,000
Moondance 534 1H 1.0 7/18/2017 55,886 672 525 248 20 5,000 145,000
Blazin Skies 453 2H 1.0 7/26/2017 38,618 472 290 247 20 5,000 145,000
Heisenberg 3H 1.5 8/14/2017 10,208 476 407 235 30 5,000 205,000
Heisenberg 7H 1.5 8/20/2017 39,073 890 252 297 24 5,000 205,000
Even Flow 584 4H 1.0 9/4/2017 13,967 399 344 222 20 5,000 205,000
Whiteport 537 3H 1.0 9/11/2017 33,635 889 372 248 20 5,000 205,000
Greasy Bend 584 1H 1.0 9/24/2017 13,131 420 300 221 20 5,000 205,000
Road Dirt 534 4H 1.0 9/30/2017 19,633 762 621 248 20 5,000 205,000
Under The Bridge 452 3H 1.5 10/10/2017 14,048 752 702 238 30 5,000 205,000
Gen
1.1
2.1
3.1
*Production as of 11/21/17
1.2
2.2
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Drilling Program – Whiteport
• The Whiteport lease currently has four 1.0 mile laterals• Previous Operator drilled the first well on the lease (#2H) – generally considered the best well in Bronco at time of acquisition• SEII drilled the next three wells – 1H, 4H, and 3H each with a progressively more aggressive completion
• Productivity has increased with each wellWhiteport 2H 564 BOEPD (Pre-Acq)Whiteport 1H 685 BOEPD (Gen 1.1)Whiteport 4H 672 BOEPD (Gen 2.1)Whiteport 3H 774 BOEPD (Gen 3.1)
17
Drilling Program – Road Dirt / Moondance
• Road Dirt 3H (nearest offset well at 0.5 miles away) was an underperforming acquired well drilled in early 2015• Moondance 1H was initially completed with a 20 stage Gen 2.2 frac
• Oil production commenced after 22 days and quickly climbed to 669 BOEPD• Road Dirt 4H was recently completed with a 20 stage Gen 3.1 frac
• Oil production commenced after 9 days and quickly climbed to 739 BOEPD• Moondance 2H was recently completed with a 20 stage Gen 3.1 frac
• Oil production commenced last week after 14 days and is currently producing 661 BOEPD and climbing
18
Bronco Production Profile
• Initial completion employs ESP’s that can move > 2,000 BFPD• Once fluid production drops to ~ 600 BFPD the ESP is pulled and replaced with a rod pump
• ESP’s have higher operating costs and less run time than rod pumps
• Wells drilled with no direct offsets tend to produce water longer prior to oil production• Initial pump intake pressure (PIP) is higher and it takes longer to draw down to the range where oil is released from the pores
• Wells drilled with direct offsets generally have lower initial PIP• Lower initial PIP = less pressure to draw down = earlier oil production
• San Andres horizontal wells often exhibit severe calcium carbonate scaling tendencies• Existing wells often require an extensive cleanout to restore production• New wells are proactively treated to delay the onset of scale production
• Frac water cleaned with chlorine dioxide• Frac stages treated with liquid and solid scale inhibitor
Well Offset Well First Production Days to first oil
Whiteport 2H No direct offset 03/10/16 24
Whiteport 1H Direct offset to WP 2H 02/08/17 12
Whiteport 4H No direct offset 05/17/17 22
Whiteport 3H Direct offset to WP 4H and WP 2H 09/12/17 6
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Bronco Scale Cleanout
• Calcium sulfate (CaSO4) scale is a known significant issue in horizontal San Andres wells• Post-acquisition, 24 wells were identified as having limited production due to scale (lower water and oil production, PIP off trend)
• Most of the program was executed within four months of acquisition utilizing up to five workover rigs• Procedure refined over time to arrive at current design
• Cleanout procedure:• Evaluate ESP for deposition – usually in gas separator and pumps• Run bit to cleanout scale from entire lateral – typically without the benefit of circulation• Pump scale converter across each set of perfs – SC-100 mixed 1:2 (gal/gal) with water and let soak for 24 hours
• This process converts CaSO4 to an acid dispersible byproduct• Acidize each set of perfs with 10,500 gals 15% NEFE HCl and let soak for 6-12 hours• Spot scale inhibitor (polyacrylate / deta phosphonate blend) across each set of perfs and let soak for 48 hours• Run ESP and put on production
• Average cost $250,000• Learnings
• Do not clean out with air foam as this accelerates scale deposition• Circulation is rarely a possibility and not required, sticking not a big issue with jointed pipe
• Little help is gained using nitrogen and foamer, not worth the cost• Many vendors offer polyacrylate / deta phosphonate blends, pricing and availability is key
• The most cost effective method to delay scale precipitation is during the frac
• Frac Job Design• All water, including drill out fluid, is treated with chlorine dioxide (ClO2) prior to going downhole
• Eliminates sulfate reducing bacteria• Polyacrylate / Deta phosphonate inhibitor is pumped in all stages of the frac at 1.8 gpt (about three drums per stage)• Solid scale inhibitor (Carbo ScaleGuard II) is mixed into all proppant stages at a concentration of 1.5% by volume
• Residuals must be checked when well is on production to ensure the well is protected• Polymer tags on liquid scale inhibitor is used to differentiate it from the continuous treating program down cap string
20
Scale Cleanout Identification – Backslider 4H
• The Backslider 4H began experiencing excessive decline in water production quickly followed by a decline in oil production
• Pump Intake Pressure (PIP) also declined steeply and the well was immediately pulled following acquisition
• The tubing and ESP were stuck with scale and the lateral was approximately 75% full of scale
• Each perf stage was converted, acidized, and inhibited per normal procedure
• Post cleanout production increased from 25 to 220 BOPD
21
Scale Cleanout Identification – Smashed Nickel 3H
• The Smashed Nickel failed in June 2016 and was left down pending a new pump design
• A PC pump was run in September 2016 but could not stay running
• Post-acquisition a scale cleanout was performed
• The well returned to IP levels of production at ~350 BOPD
• Prior to failure the well produced ~66,000 BO - since cleanout the well has produced an additional 64,000 BO
22
Drilling Program – Browning 5063H
First Generation Completion Issues
• High rate, slickwater frac grew downward and connected the targeted pay with deeper water interval
• High water production from below made it difficult to sufficiently lower the PIP
Browning State 5063H:
• At 760# PIP, oil production commenced after 160 days and 570,000 bbl water
• Oil cut has doubled from 1% to 2%
• Cumulative water production: 1.8MM BBL
Colt 5867H:
• At 699# PIP, oil production commenced after 250 days and 875,000 bbl water
• Steward elected to shut this well in for SWD capacity
23
Drilling Program – Thunderstruck
• Thunderstruck #1H (offset well 1.0 mile away) drilled by previous operator and peaked at 145 BOEPD (1.5 mile lateral)• Thunderstruck 1231H was initially completed with a 20 stage Gen 2.2 frac (1.0 mile lateral)
• Oil production commenced after 22 days and quickly climbed to 320 BOEPD• Exciting early results from a frontier area
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P50 Bronco Type Curve – 1.0 Mile Wells25
100
200
300
400
10
1,000
BB
L/D
We
ll C
ou
nt
P50 Oil Type Curve P50 Water Type Curve Individual 1.0 Mile Hz wells Well Count
Updates:• 31 well sample size compared to 19 wells at acquisition. 20 wells with over 365 days of production history.• Increased normalized lateral length from 4,000’ to 5,000’ due to SEII efforts to maximize completed lateral interval by drilling off-lease and
utilizing advantageous field rules.
P50 Bronco Type Curve – 1.5 Mile Wells26
100
200
300
400
10
1,000
BB
L/D
We
ll C
ou
nt
P50 Oil Type Curve P50 Water Type Curve Individual 1.0 Mile Hz wells Well Count
Updates:• 17 well sample size compared to 13 wells at acquisition. 11 wells with over two years of production history.• Increased normalized lateral length from 6,700’ to 7,500’ due to SEII efforts to maximize completed lateral interval by drilling off-lease and
utilizing advantageous field rules.
Type Curve Progression – 1.0 Mile Raw Data27
• SEII has developed three iterations of the Bronco Type curve as more wells have been added to the data set and have additional seasoning since the acquisition evaluation.
• The original Type Curve developed for the acquisition evaluation (July 2016) assumed 4,000’ as the normalized lateral length for on-lease locations.• In March 2017, the assumed perforated lateral length of SEII drilled 1.0 mile wells are maximized at 5,000’ by drilling off-lease• In September 2017, all SEII wells with 30 days of oil production were included and normalized to time zero• Additional daily data shows a flattening of the decline curve as the wells age, improving EUR forecasts • The B-factor was increased from 1.35 to 1.5 to reflect the flatter decline profile
Updated 5,000’ Type Curve (September 2017)
Acquisition – 4,000’ Lateral (July 2016)
Increased 5,000’ Lateral Type Curve (March 2017)
400
BB
L/D
100
10
300
200
EURs:(1) Acquisition Type Curve (4,000’): 335 MBO (2) March Update (5,000’): 428 MBO(3) September Update (5,000’): 503 MBO
Flattening Decline as well ages;Optimization (clean out) timeframe
100
10
300
200
400
EURs:(1) Acquisition Type Curve (6,700’): 597 MBO (2) March Update (7,500’): 712 MBO(3) September Update (7,500’): 758 MBO
Type Curve Progression – 1.5 Mile Raw Data28
• The 1.5 mile type curve continues to show a distinctively flatter decline profile than 1.0 mile wells.• SEII has added three 1.5 mile wells to the type curve data set.• The acquisition evaluation used an assumed completed lateral length of 6,700’. Again, SEII continues to attempt to maximize lateral length by drilling from off-
lease locations. • The assumed lateral length was increased to 7,500’ in March 2017, which resulted in higher EUR.• In September 2017, all SEII wells with 30 days of oil production were included and normalized to time zero.• The B-factor was increased from 1.35 to 1.5 to reflect the flatter decline profile.
Updated 7,500’ Type Curve (September 2017)
Acquisition – 6,700’ Lateral (July 2016)
Increased 7,500’ Lateral Type Curve (March 2017)
BB
L/D
Type Curve and EUR Analysis – 1.0 Mile
1.0 Mile Hz Well PHDWin Curve:
Wellhead breakeven: $21.30 / bbl
29
Price Deck: Oil: $50/BBL Gas: $3.00/MMBtu
1.0 Mile Single Well Economics:
Case CAPEX ($M) Lat. Length EUR (MBBL) PV0 PV5 PV9 IRR Payout (yrs) PV0 ROI PV9 ROI
Flat Pricing $2,600 5,000' 503 $9,404 $6,017 $4,565 81% 1.09 4.62x 2.76x
Type Curve and EUR Analysis – 1.5 Mile
1.5 Mile Hz Well PHDWin Curve:
30
1.5 Mile Single Well Economics:
Case CAPEX ($M) Lat. Length EUR (MBBL) PV0 PV5 PV9 IRR Payout (yrs) PV0 ROI PV9 ROI
Flat Pricing $3,500 7,500' 759 $15,700 $928 $6,754 66% 1.33 5.49x 2.93x
Price Deck: Oil: $50/BBL Gas: $3.00/MMBtu
Wellhead breakeven: $18.60 / bbl
PUD Reserve Growth31
Initial Evaluation Subsequent Updates
Acquisition Evaluation
Steward II – Total Production
• 8/8th operated production of all assets• Buoyed by the success of the workover program and positive drilling results, production decline has been arrested
and production base has more than doubled in 1 year since Bronco acquisition
32