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

15

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

16

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

19

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

24

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