Jefferies 2018 Global Energy Conference November 2018 2 Important - - PowerPoint PPT Presentation

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Jefferies 2018 Global Energy Conference November 2018 2 Important - - PowerPoint PPT Presentation

Jefferies 2018 Global Energy Conference November 2018 2 Important Information Forward-Looking Statements This presentation includes certain statements that may constitute forward -looking statements for purposes of the federal securities


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SLIDE 1

Jefferies 2018 Global Energy Conference

November 2018

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SLIDE 2

2

Important Information

2

Forward-Looking Statements This presentation includes certain statements that may constitute “forward-looking statements” for purposes of the federal securities laws. All statements, other than statements of historical fact included in this communication, regarding our opportunities in the Delaware Basin, our strategy, future operations, financial position, estimated results of operations, future earnings, future capital spending plans, prospects, plans and objectives of management are forward-looking statements. When used in this communication, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “guidance,” “forecast” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. You should not place undue reliance on these forward-looking statements. Although the Company believes that the plans, intentions and expectations reflected in or suggested by the forward- looking statements in this communication are reasonable, no assurance can be given that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied by the forward-looking statements. Some factors that could cause actual results to differ include, but are not limited to, its ability to acquire additional acreage from the sellers pursuant to the acquisition purchase agreement, the ultimate timing, outcome and results of integrating the acquired assets into its business and its ability to realize the anticipated benefits, commodity price volatility, inflation, lack of availability of drilling and completion equipment and services, environmental risks, drilling and other

  • perating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of

development expenditures and the other risks and uncertainties under Risk Factors in the Company’s Annual Report or Form 10-K filed with the Securities and Exchange Commission (the “SEC”) and in other public filings with the SEC by the Company. The Company’s SEC filings are available publicly on the SEC’s website at www.sec.gov. These forward-looking statements are based on management's current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. All forward-looking statements speak only as of the date of this communication. Except as otherwise required by applicable law, the Company disclaims any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this communication. Use of Non-GAAP Financial Measure This presentation includes the use of Adjusted EBITDAX and PV-10, which are financial measures not calculated in accordance with generally accepted accounting principles (“GAAP”). Please refer to the appendix for a reconciliation of Adjusted EBITDAX to net (loss) income, the most comparable GAAP measure. Adjusted EBITDAX is a non-GAAP financial measure that is used by Rosehill’s management and external users of our financial statements, such as industry analysts, investors, lenders and rating

  • agencies. The Company defines Adjusted EBITDAX as net income (loss) before interest expense, income taxes, depreciation, depletion, and amortization, accretion and impairment of oil and

natural gas properties, (gains) losses on commodity derivatives excluding net cash receipts (payments) on settled commodity derivatives, gains and losses from the sale of assets, transaction costs incurred in connection with the Transaction and other non-cash operating items. Adjusted EBITDAX is not a measure of net income as determined by GAAP. PV–10 is a non-GAAP financial measure used by management, investors and analysts to estimate the present value, discounted at 10% per annum, of estimated future cash flows of the Company’s estimated proved reserves before income tax and asset retirement obligations. Management believes that PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, the Company believes the use of a pre-tax measure is valuable for evaluating the Company. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP. Other Disclaimers This presentation has been prepared by Rosehill and includes market data and other statistical information from sources believed by Rosehill to be reliable, including independent industry publications, government publications or other published independent sources. Some data is also based on Rosehill’s good faith estimates, which are derived from its review of internal sources as well as the independent sources described herein. Although Rosehill believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy and completeness. Some of the results in this presentation are preliminary, such as production estimates, Adjusted EBITDAX, capital spending and debt levels. Any such preliminary results are based on the most current information available to management. As a result, Rosehill’s final results may vary from these preliminary estimates. Such variances may be material; accordingly, you should not place undue reliance on these preliminary estimates.

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SLIDE 3

3

Pure Play Delaware Basin Operator

Pecos County Ward County Reeves County Winkler County Loving County Lea County ▪ Net Acres: ~11,500 ▪ Inventory: ~480 Locations (2) ▪ Average Operated Working Interest: ~86%(3)

Rosehill Acreage

Well positioned in, arguably, the most prolific basin in the U.S.

  • Leading Delaware Basin small-cap E&P company

➢ Two core operating areas: Northern and Southern ➢ 53 gross operated producing horizontal wells ➢ Net daily production exceeded 20,000 BOEPD in early September ➢ Total proved reserves 31.1 MMBOE (1)

  • Northern Delaware Basin

➢ 4,010 net acres in Loving County, Texas and Lea County, New Mexico ➢ Acreage substantially held by production ➢ Offset operators (APC, CXO, COP and EOG) ➢ Premier acreage in the heart of Loving County with 4 formations and 10+ landing zones ➢ Continued development with the expected drilling of 24 – 26 wells in 2018

  • Southern Delaware Basin

➢ 7,553 net acres located primarily in northern Pecos County, Texas ➢ Manageable lease expiration schedule of 8% and 52% expiring in 2019 and 2020, respectively ➢ Offset operators (OXY, FANG, JAG and PE) ➢ Continuing to pursue block-up/bolt-on opportunities ➢ Drilled and logged five pilot wells with Wolfcamp laterals across the acreage – currently flowing back the first four wells

(1) Rosehill’s proved reserve estimate at December 31, 2017 was prepared by Ryder Scott Company, L.P., using SEC guidelines. (2) Reflects operated locations only; ROSE has identified an additional 50 non-operated locations. (3) Average working interest in operated areas.

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SLIDE 4

4

Profitable Growth And Acquisition Strategy

4

  • Enhance EUR per capital dollar invested through modifications to drilling and

completion techniques and cost reductions

  • Drive down cash operating costs and improve margins to grow cash flow and

maximize returns

  • Aggregate small to moderate acreage positions that are strategic and accretive
  • Strong balance sheet and public currency allows for this aggregation
  • Decrease horizontal and vertical spacing in horizontal wells
  • Test additional zones and acquire additional acreage
  • Capital expenditures focused on highest return horizons
  • Opportunistically add hedges to minimize downside exposure
  • As of Q3’18, 95% of production on pipe
  • Pursue longer term options to Gulf Coast and other markets
  • Sustain growth in cash flow while maintaining low financial leverage
  • Target attractive corporate level return, CROCI of 44% through Q3’18

Optimize Operations Expand Delaware Footprint Maintain Financial Discipline Expand Drilling Inventory Ensure Ample Transportation Capacity Deliver Value to Shareholders

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SLIDE 5

5

Deliver Value Through Execution

5 Q3’18 Highlights

✓Average production of 19,750 net BOEPD,

surpassed 20,000 BOEPD in September

✓Delivered Adjusted EBITDAX of $56.7 million,

an increase of 15% over Q2’18

✓Reduced combined LOE and cash G&A unit

cost by 18% or $1.81/BOE compared to Q2’18

✓Reduced combined LOE and cash G&A unit

cost by 35% or $4.65/BOE compared to Q1’18

✓Announced first well results in Southern

Delaware

✓Completed equity offering – tripled

unaffiliated public float at modest overall dilution

✓New transportation and marketing

agreements in Northern & Southern Delaware increase flow assurance and enhance margins

2018 Objectives

✓Surpass 15,000 BOEPD by Mid-Year 2018 ✓Fully Implement Improved Gen-3 Completion

Design In Loving County

✓Drive Unit Costs Lower And Increase Margins ✓Establish Operations In Southern Delaware by

Mid-Year 2018 With Production Results by Q3’18

✓Test Multiple Horizons In Southern Delaware ✓Pursue Additional Acquisition Opportunities In

Delaware Basin

 Further Strengthen Balance Sheet

(partially addressed with equity raise)

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6

Well Hedged to Protect 2019+ Cash Flows

Crude Oil Hedge Positions2 2018 2019 2020 2021 2022

Crude Oil Swaps Hedge Volume (BBL) 699,000 2,664,000 1,960,000 2,160,000 1,100,000 Average Price ($/BBL) $55.15 $53.59 $60.09 $61.21 $58.42 Crude Oil Collars Hedge Volume (BBL) 182,000 601,000 Average Ceiling Price ($/BBL) $61.28 $61.30 Average Floor Price ($/BBL) $57.53 $55.21 Crude Oil 3Ways Hedge Volume (BBL) 1,531,832 3,294,000 Average Ceiling Price ($/BBL) $68.52 $70.29 Average Floor Price ($/BBL) $57.62 $57.50 Average Short Put Price ($/BBL) $45.51 $47.50 $(8) $(4) $- $9 $21 $(10) $- $10 $20

$45 $50 $55 $60 $65 Adjusted EBITDAX Impact (MM)

Adjusted EBITDAX Sensitivity

(based on 20,000 boepd production and 2019 hedge positions) 0.0x 1.0x 2.0x

$45 $50 $55 $60 $65 Peer Average Debt / TTM Adjusted EBITDAX

Leverage Ratio Sensitivity1

(based on midpoint of 2018 guidance and 2019 hedge positions)

(1) Leverage ratios include impact from EBITDAX sensitivities at 20,000 boepd production level. (2) Positions are as of November 7, 2018 (Contract months: October 2018 – Forward). See appendix for summary of all hedge positions.

BASE

Pricing Assumption – WTI/Bbl Pricing Assumption – WTI/Bbl

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SLIDE 7

7

Drilling Locations Provide Substantial Inventory

33 10 45 19 61 19 50 70 80 93 480 50 530

Brushy Canyon Upper Avalon Lower Avalon / 1st Bone Spring 2nd Bone Spring Shale 2nd Bone Spring Sand 3rd Bone Spring Shale 3rd Bone Spring Sand Upper Wolfcamp A (X/Y) Lower Wolfcamp A Wolfcamp B Gross Operated Gross Non-Op Total Gross Operated and Non-Op

Wolfcamp B Lower Wolfcamp A Upper Wolfcamp A 3rd Bone Spring 2nd Bone Spring 1st Bone Spring Upper Avalon Brushy Canyon Lower Wolfcamp B Upper Wolfcamp B Wolfcamp A 3rd Bone Spring 2nd Bone Spring 1st Bone Spring Bone Spring Lime Brushy Canyon

Gross operated wells per target formation

(1) Locations as of December 31, 2017, assumes 24 wells drilled annually per rig.

Rosehill has employed conservative spacing in determining its drilling inventory

20 Rig-Years of Drilling Inventory with Identified Upside (1)

Current Focus Area: Southern Delaware – 4-6 Wells Per Section Current Focus Area: Northern Delaware – 4-6 Wells Per Section

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SLIDE 8

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  • Sophisticated offset operators (APC,

EOG, CXO, etc.) actively developing 11 distinct benches over a 4,500 foot thick hydrocarbon column

➢ Rosehill has established production from 4 formations and 7 landing zones, currently testing the 8th landing zone, the 2nd Bone Spring Shale

  • Repeatable drilling due to individual

reservoir homogeneity

  • Production averages ~75% oil, ~87%

liquids

  • Rosehill’s well results have improved

across its footprint

➢ Improving recoveries due to refinement of drilling and completion methodology ➢ Committed to best-in-class technology such as microseismic guided completions and sophisticated downhole imaging logs to define fracture trends and improve landing target selection

Source: IHS, Drilling Info.

Loving Co. Lea Co.

Density Porosity >6% Resistivity >20 Ohms

4,500 Feet

Type Log

Delaware Basin Wolfcamp A Structure

  • 1000
  • 2000
  • 3000
  • 4000
  • 5000
  • 6000
  • 7000
  • 8000
  • 9000
  • 10000

Depth

Weber 26 G1 Peak Rate: 1,859 BOEPD Wolfcamp A Lower Kyle 26 ST-1 Peak Rate: 2,130 BOEPD 2nd Bone Spring Sand

Northern Delaware Basin Execution

Z&T 32 A1, B3 & C1 Peak Rates: 2,366 BOEPD 2,086 BOEPD 2,297 BOEPD Wolfcamp A Lower Type Log

Tatanka Fed 1H Peak Rate: 1,532 BOEPD Wolfcamp A Lower Weber 26 F1, F2, E1 Peak Rates: 1,827 BOEPD (LWCA) 1,641 BOEPD (WCA X/Y) 1,467 BOEPD (LWCA) Wolfcamp A

Heart of the Delaware

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SLIDE 9

9 50 100 150 200 250 30 60 90 120 150 180 210 240

  • Cum. Oil Production (MBO)

Producing Days

GEN 3 Type Curve Weber 26 C3 Weber 26 F2

50 100 150 200 250 30 60 90 120 150 180 210 240

  • Cum. Oil Production (MBO)

Producing Days

GEN 3 Type Curve Weber 26 E2 Weber 26 C4

Strong Northern Delaware Basin Well Performance

(1) (1)

3rd Bone Spring Sand Wolfcamp A Upper

  • Gen-3 type curves are ~30%

higher than Gen-2

  • Recent results performing at or

above Gen-3 type curves

  • Superior rock quality paired

with improved completion techniques translates to higher returns Wolfcamp A Lower

(1)

50 100 150 200 250 30 60 90 120 150 180 210 240

  • Cum. Oil Production (MBO)

Producing Days

GEN 3 Type Curve Weber 26 C2 Z&T 32 A1 Z&T 32 B3 Z&T 32 C1 Weber 26 E1 Weber 26 F1

Well Statistics Z&T 32 A1 Z&T 32 B3 Z&T 32 C1 Weber 26 E1 Weber 26 F1 Weber 26 E2 Weber 26 F2 Target Formation LWCA LWCA LWCA LWCA LWCA 3BSSND UWCA 1st Production date 2/26/18 2/22/18 2/22/18 8/22/18 8/21/18 8/21/18 8/21/18 Lateral length (ft.) 4,863 4,863 4,863 4,361 4,799 4,761 4,361 IP-30 (BOEPD) (2) 2,101 1,856 2,064 1,383 1,566 962 1,586 Clusters / Stage 35 35 35 20 20 20 20 Proppant (lbs. / ft.) 3,552 3,084 2,900 2,624 2,442 2,597 2,665

(1) Actual results after flowback and cleanup; producing days exclude downtime. (2) Average daily production, highest average 30-day rate achieved per well.

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(1) EUR data based on 2-stream (wet) gross. (2) Calculated using prices of $57/BBL oil & $2.97/MCF natural gas for 2018, $54/BBL oil and $2.87/MCF natural gas.

Northern Delaware Basin

Type Curve Summary

Type Curve Upper Wolfcamp A (UWCA) Lower Wolfcamp A (LWCA) Wolfcamp B (WCB) Lateral Length (Ft.) 5,000 5,000 5,000 Completion Gen-3 Gen-3 Gen-3 Well Cost ($MM) $7.0 $7.3 $7.9 EUR (1) (MBOE) 996 1,037 822 IRR (2) 100% 100% 52% ROI (2) 2.2x 2.3x 1.5x Payback (2) (Years) 0.80 0.75 1.55

Strong Economics Through Improved Drilling and Completion Efficiencies, With Upside in Other Horizons

  • 50

100 150 200 250 300 350

  • 200

400 600 800 1,000 1,200 1 3 5 7 9 11 13 15 17 19 21 23

Cumulative Oil (MBO) Daily Oil (BOPD) Months

Loving & Lea Type Curves

UWCA LWCA WCB

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Future Growth Area

Emerging Southern Delaware Basin

Note: Well level data from the Texas Railroad Commission, IHS, Jagged Peak Energy, Inc., Diamondback Energy, Inc. and Parsley Energy Inc. Data as of 11/1/2018.

  • White Wolf asset consisting of

6,925 net acres and ~250 locations across 5 to 6 benches with initial drilling in the Wolfcamp A and B

  • Active offset development by

Diamondback, Parsley and Jagged Peak targeting Wolfcamp A/B and Bone Spring reservoirs with majority of offsetting wells completed with Gen-1 and Gen-2 fracs (sub 2,500 lbs/ft of sand)

  • Drilled five pilots and Wolfcamp

laterals with comprehensive coring and best-in-class Schlumberger wireline logging, including CMR and imaging logs. Petrophysical and core data anchor new 110 square mile 3D seismic survey

  • Refined and revised geologic

model, quantified reservoir and mechanical properties and established presence of extensive natural fracture network and max/min stress directions

  • Identified new potential Bone

Spring Targets

Reeves Pecos

Wolfcamp A

Structure CI = 100 Ft

JAG IP24 155 BOEPD/1,000 Ft Wolfcamp B FANG IP24 195 BOEPD/1,000 Ft Wolfcamp B

Coyanosa Field

Patriot IP24 155 BOEPD/1,000 Ft Wolfcamp B JAG IP24 234 BOEPD/1,000 Ft 2nd Bone Spring FANG IP24 163 BOEPD/1,000 Ft Wolfcamp A Parsley (3 Well Pad) AVG IP24 311 BOEPD/1,000 Ft Wolfcamp A & B JAG Woodford FANG IP24 279 BOEPD/1,000 Ft Wolfcamp B Rosehill Trees Estate 77 Wolfcamp B DUC Rosehill Neal Lethco 41 Wolfcamp B Flowing Back Rosehill Hatch 16 Wolfcamp B Flowing Back Rosehill State Blanco 58 Wolfcamp A Flowing Back Rosehill Sisters 17 Wolfcamp B Flowing Back FANG IP24 135 BOEPD/1,000 Ft Wolfcamp B FANG IP24 144 BOEPD/1,000 Ft Wolfcamp B Rosehill State Blanco 58 3 Well Pad Wolfcamp A & B DUCs

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Wolfcamp Structure

CI = 100 Ft

  • Drilled new 3-well pad on State Blanco

58, offsetting the Trees Estate 77 #A001, in the Wolfcamp A and B

  • Five initial pilots and associated

laterals drilled with four laterals completed to date

  • Encouraging early results highlighted

by IP 24 rates normalized for lateral length on par with surrounding

  • perators
  • Initial findings include a high oil

content, extensive natural fracturing, and strong formation conductivity

  • Actions underway to implement

artificial lift across area and significantly increase future flow rates

  • Preliminary “Fast Track” 3D seismic

data over White Wolf recently

  • received. Final seismic volumes

available Q1 2019

  • Pilot wells provided initial technical

framework for full-scale development ➢ Define landing targets, fracture trends and horizontal well direction ➢ Provide structural, petrophysical and geomechanical data that will calibrate the 3D Seismic Earth Model.

Development On Track In Southern Delaware Basin

Hatch 16 #I001 Wolf B Neal Lethco 41 #H001 Wolf B State Blanco 58 #A003 Wolf A Sisters 17 #A001 Wolf B Trees Estate 77 #A001 Wolf B DUC

Pilot Well

Initial Well Results IP 24 BOEPD IP 24 BOEPD per 1,000 ft. Four Well Average 956 198 Potential w/ Artificial Lift 1,150 – 1,350 240 - 275

State Blanco 58 3 Well Pad Wolf A & B DUCs

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Finding the Sweet Spot in Southern Delaware Basin

  • Wolfcamp A and B

reservoirs are in a localized depositional “Sweet Spot” between the Coyanosa-Waha Ridge and the Central Basin Platform, in a setting that produces rock quality similar to the Reeves County Core.

3rd Bone Wolf A

Mapped Interval

Pecos Wolfcamp A & B Thickness

Coyanosa Field

Reeves

  • The ponded Wolfcamp depositional environment at White Wolf generated highly
  • rganic-rich, thick Wolfcamp A and B Shales with high porosity, high TOC and

extensive natural fracturing

  • Wolfcamp A and B are low GOR oil reservoirs with extensive natural fracture

systems enhanced by the deep, structurally controlled Coyanosa Field offsetting White Wolf to the west. Coyanosa has produced 2.4 TCF and 40 MMBO from deep, Paleozoic reservoirs since the 1960’s

  • Conventional and sidewall core analysis confirms thermal maturity, oil saturations,

TOC content and porosity in the Bone Spring and Wolfcamp

Wolf B

A A’

A A’ < 9.4 Miles > < 4.4 Miles > White Wolf

Rt PhiE Sw GR/TOC Brit

2nd Bone

1,000 Ft

Stratigraphic Cross Section A – A’ Datum: Top of Wolfcamp A

Rt PhiE Sw GR/TOC Brit Oil in Place Rt PhiE Sw GR/TOC Brit

White Wolf

Oil in Place Oil in Place

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(1) EUR data based on 2-stream (wet) gross. (2) Calculated using prices of $57/BBL oil & $2.97/MCF natural gas for 2018, $54/BBL oil and $2.87/MCF natural gas.

Southern Delaware Basin

Type Curve Summary

Contiguous acreage position enables extended laterals on 40 - 50% of identified locations, which can improve well economics

  • 50

100 150 200 250 300

  • 200

400 600 800 1,000 1,200 1 3 5 7 9 11 13 15 17 19 21 23

Cumulative Oil (MBO) Daily Oil (BOPD) Months

Southern Delaware Type Curves

UWCA LWCA WCB Type Curve Upper Wolfcamp A (UWCA) Lower Wolfcamp A (LWCA) Wolfcamp B (WCB) Lateral Length (Ft.) 5,000 5,000 5,000 Completion Gen-3 Gen-3 Gen-3 Well Cost ($MM) $6.9 $7.1 $7.8 EUR (1) (MBOE) 763 743 771 % Oil (1) 86% 86% 86% IRR (2) 66% 51% 69% ROI (2) 1.7x 1.6x 1.7x Payback (2) (Years) 1.35 1.65 1.30

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Northern Delaware

  • Core Loving oil and gas gathering provided by Gateway Gathering &

Marketing Company, a wholly owned subsidiary of Rosemore, Inc.

➢ Oil delivered into Plains All American system, gas delivered into Energy Transfer and EnLink systems. No minimum volume commitments (oil or gas) ➢ Approximately 95% of oil piped as of Q3’18, recent marketing agreement with Plains improves flow assurance and enhances margin

  • Weber oil and gas gathering provided by Targa Resources – 100% of oil

piped with capacity of 10,000 BPD to Midland

  • Tatanka oil currently trucked, recent agreement with Plains for pipeline

connection, gas gathered by Energy Transfer

➢ 100% of oil expected to be piped once Plains connection is completed

Southern Delaware

  • Majority of oil and gas gathering for White Wolf area dedicated to Brazos

Midstream

➢ No minimum volume commitments (oil or gas) ➢ System expected to be fully in place Q1’19

  • Reached agreement with Oryx for pipeline transportation of oil to various

in-basin markets

➢ Favorable economic terms, structured as a multi-year acreage dedication with no minimum volume commitments (oil or gas) ➢ Optionality for future delivery to other markets

Pecos County Ward County Reeves County Winkler County Loving County Lea County

Weber Core Loving Tatanka White Wolf

Ample Transport Capacity to Midland MidCush Basis Substantially Hedged in FY18 & FY19 95% Oil Piped as

  • f Q3’18

Midstream Infrastructure

Flexible and Well Positioned for Growth

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SLIDE 16

16 Capacity Utilization 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18

30 day average (BWPD)

Gross Water Production - Loving County

  • Brought three Loving County SWD wells online during 2018

➢ Current disposal capacity of ~155,000 barrels of water per day (“BWPD” )

➢ Significantly reduces 3rd party trucking and disposal cost

  • Permitting 3 SWD wells for additional capacity of 60,000 to 120,000 BWPD
  • Over 25,000 ft. of pipeline for optimal flexibility in directing produced water

Water Solutions

Northern Delaware

  • Brought online 1st SWD in Southern Delaware with initial 20,000 BWPD

capacity, plans to increase to 40,000 BWPD with upgrades in progress

  • Permitting 3 SWD wells for additional capacity of 60,000 to 120,000 BWPD
  • Other 3rd party arrangements in place for additional capacity at favorable

economic terms

Southern Delaware

Water Sourcing Agreements in Place to Accommodate Development Plan

~155,000 BWPD Disposal Capacity Gross Water Production Currently utilizing ~40% of available disposal capacity in Loving County

  • Average water disposal volumes of ~85,000

BWPD in 2019

  • Significant value to ROSE – recent water systems

have transacted at EBITDA multiples of 8.0 to 12.0x

$0.00 $1.00 $2.00 $3.00 ROSE 3rd Party (Piped) 3rd Party (Trucked)

Per Barrel Dispoal Cost

Produced Water Disposal Cost

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Profitable Growth With Strong Balance Sheet

(1) Growth is calculated using 2017 Actuals and midpoints from 2018 Guidance, as applicable. (2) Adjusted EBITDAX is a non-GAAP measure. Please refer to appendix for a reconciliation of Adjusted EBITDAX to Net Income. (3) Assumes 2018 realized pricing (excluding hedges) of $55/BBL, Natural Gas $3.00/MCF and NGLs at 33% of WTI.

Capital Spending ($MM) Average Daily Production (BOEPD) Adjusted EBITDAX ($MM) (2) Debt / TTM Adjusted EBITDAX

$25 $228

2016 2017 2018 E

2.9x 1.7x 1.4x - 1.6x

2016 2017 2018 E

$47 $159

2017 2018 TTM 2018 E

  • Avg. WTI ($/BOE) (3)

$55 5,838 14,448 15,500 - 17,000

2017 2018 TTM 2018 E

$350 - $375 $170 - $190

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SLIDE 18

18 $0 $10,000 $20,000 $30,000 $40,000 $50,000 $60,000 A B C D E F G H I XX J

Peer Average = $28,000

Rosehill is valued below peers based on enterprise multiples….

Rosehill’s compelling investment profile

Peers

0.0x 2.0x 4.0x 6.0x 8.0x A B C D E F G H I J K L M N O P Q R S XX T Peer Average = 5.2x

ROSE

Enterprise Value / 2018 Adjusted EBITDAX (1)

…...as well as on an acreage basis when adjusting for current production levels.

(1) Source: Credit Suisse Equity Research - E&P Weekly Comp Sheet (November 5, 2018) for peers (oil-weighted resource plays) and Rosehill estimates for ROSE. Peers include CDEV, CLR, CPE, CXO, EGN, FANG, JAG, LPI, NFX, OAS, PDCE, PE, PXD, QEP, SM, SRCI, WLL, WPX, XEC and XOG. (2) Source: Company Filings, FactSet, Investor Presentations. Market Data as of November 7, 2018. Peers include CDEV, CPE, CXO, EGN, FANG, HK, JAG, LPI, PE, REN. Adjusted Enterprise Value is calculated by subtracting the value of most recent reported production valued at $30k/BOEPD from Enterprise Value.

Adjusted Enterprise Value / Acre (2)

Peers ROSE

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SLIDE 19

19

55 75 150 210

$0 $50 $100 $150 $200 $250 $300

Sep'17 Dec'17 Mar'18 Jun'18 Nov'18

Borrowing Base ($MM)

0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x 3.5x A B C D E F G H I J K L M N O XX P Q R S T

  • Completed equity offering in late September

➢ Issued ~7 million shares for net proceeds of ~$40MM, tripled unaffiliated public float at modest overall dilution

  • As of June 30, 2018, the Company increased its

borrowing base by 40%, to $210 million

➢ Recently called redetermination expected to be complete in early December ➢ Attractive borrowing cost of 200 – 300 bps above LIBOR, based on facility usage

  • Net Debt to 2018 Adjusted EBITDAX forecasted at

1.4x – 1.6x

  • No near term maturities

(1) As of September 30, 2018 and pro forma for equity offering. (2) Represents 8.7 MM Class A common shares on an as-converted basis. (3) Warrants are exercisable for Class A shares at a price of $11.50 on a 1:1 conversion basis. Assumes no net share settlements.

Capitalization and Liquidity (MM) (1)

Cash $51 Revolving Credit Facility $194 10% Second Lien Note 94 Total Debt $288 8% Series A Preferred (2) $84 10% Series B Preferred 152 Total Preferred $236 Total Liquidity $116 Class A Common Shares 13.7 Class B Common Shares 29.8 Warrants (3) 25.6MM Cash to ROSE from Exercise of Warrants (3) $294

Net Debt / 2018 Adjusted EBITDAX

Peer Average = 1.9x ROSE

Source: Credit Suisse Equity Research - E&P Weekly Comp Sheet November 5, 2018) for peers (oil- weighted resource plays) and Rosehill estimates for ROSE. Prices: Credit Suisse price forecasts (WTI/Henry Hub) of: 2018 - $67.25/$2.85; 2019 - $67.00/$2.75. Peers include CDEV, CLR, CPE, CXO, EGN, FANG, JAG, LPI, NFX, OAS, PDCE, PE, PXD, QEP, SM, SRCI, WLL, WPX, XEC and XOG.

Capital Structure

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SLIDE 20

20

  • Profitable Growth

➢ Drill And Complete Existing Inventory Of ~480 Locations ➢ Organic Leasing ➢ Accretive Acquisitions

  • Conservative Financial Management

➢ Maintain Strong Balance Sheet ➢ Grow Cash Flow To Support Drilling And Acquisitions ➢ Expand Liquidity And Borrowing Base

  • Increase Shareholder Value

Focused On The Future

Well Done is Better Than Well Said and We Have the Results to Prove It

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SLIDE 21

APPENDIX

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SLIDE 22

22

Experienced Management Team

  • Gary Hanna – Chairman, Interim President and CEO

➢ Over 35 years of industry experience – with Rosehill since September 2015 ➢ Currently Chairman of Energy XXI Gulf Coast Inc.; Former Director of Hercules Offshore Inc. ➢ Former CEO and Chairman of EPL Oil & Gas, Inc. prior to sale to Energy XXI in 2014

  • Craig Owen – CFO

➢ Over 25 years of financial experience in the energy industry – joined Rosehill in June 2017 ➢ Former Senior VP and CFO of Southwestern Energy ➢ BBA Accounting from Texas A&M University and Certified Public Accountant

  • Brian K. Ayers – Vice President of Geology

➢ Over 38 years of industry experience – with Rosehill since 2012 ➢ Former CEO of Centurion Exploration, VP of Domestic Exploration at Coastal Oil & Gas Corporation and Houston Division Manager for Samson Resources ➢ BA Geophysical Science from University of Chicago – MBA (Finance) from Millsaps College

  • R. Colby Williford – Vice President of Land

➢ Over 29 years of petroleum land management experience – with Rosehill since 2014 ➢ Former VP of Land at Momentum Oil & Gas, America Capital Energy and Centurion Exploration ➢ BBA in International Business from University of Houston - Downtown

  • Paul Larson – Vice President of Engineering

➢ Over 28 years of petroleum engineering experience – with Rosehill since 2015 ➢ Former Asset Manager at SM-Energy and Sinochem, Project Manager/Team Lead at Unocal 76 ➢ BS and MS in Petroleum Engineering from Tulsa University – BS in Mechanical Engineering from University of New York

  • Bryan Freeman – Vice President of Operations

➢ Over 23 years of petroleum engineering experience – with Rosehill since 2016 ➢ Former Production and Operations Manager at SM-Energy and Engineer at Chevron ➢ BS of Engineering from University of Texas at Tyler – MS in Engineering from University of Texas

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23

Board Of Directors

  • Gary Hanna – Chairman, Interim President & CEO

➢ Over 35 years of industry experience – with Rosehill since September 2015 ➢ Currently Chairman of Energy XXI Gulf Coast Inc.; Former Director of Hercules Offshore Inc. ➢ Former CEO and Chairman of EPL Oil & Gas, Inc. prior to sale to Energy XXI in 2014

  • Frank Rosenberg – Director

➢ Former President and CEO of Crown Central Petroleum Corporation; Current Co-Chair and Chief Investment Officer of Rosemore, Inc. ➢ Currently Director of Tema Oil & Gas, Gateway Gathering & Marketing, and Glen Eagle Resources and Chairman of Attransco

  • Ed Kovalik – Director

➢ Over 17 years of experience in the financial services industry, primarily in the energy space ➢ Former head of Rodman & Renshaw’s Energy Investment Banking team ➢ Currently a director on the boards of River Bend Oil and Gas as well as Marathon Patent Group

  • Harry Quarls – Director

➢ Managing Director of Global Infrastructure Partners; Former Managing Director & Practice Leader for Global Energy, Booz & Co. ➢ Current Chairman of Woodbine Holdings LLC and MD America Energy; Director of Opal Resources ➢ Former Chairman of the Board of Penn Virginia Corporation and US Oil Sands Inc.

  • William Mayer – Director

Over 45 years of financial services experience

Founding Partner of Park Avenue Equity Partners; Former President and CEO of The First Boston Corporation ➢ Currently a Director of Rosemore, Inc.; Lee Enterprises; BlackRock Capital Investment Corporation; Premier, Inc.; Finworx, Inc.; Hambrecht Partners Holdings; and Miller Buckfire

  • Francis Contino – Director

➢ Former EVP – Strategic Planning and CFO of McCormick & Co., Inc.; Managing Partner of Baltimore office of Ernst & Young. ➢ Currently Director of Mettler-Toledo International Inc.

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SLIDE 24

24

December 31, 2017 Reserves (SEC Pricing) (1)

Net Oil Net Gas Net NGL Net Equiv. PV-10 (2)

(MBO) (MMCF) (MBBLS) (MBOE) ($MM)

Proved Developed Producing 7,752 12,409 1,982 11,803 $212 Proved Developed Non-Producing 1,062 1,762 304 1,659 $33 Proved Undeveloped 9,622 25,145 3,857 17,670 $123 Total Proved Reserves 18,436 39,316 6,143 31,132 $368 Probable Reserves 1,636 4,576 712 3,110 $20 Possible Reserves 44,959 83,122 12,824 71,637 $213 Total 3P Reserves 65,031 127,014 19,679 105,879 $601

24

(1) Rosehill’s proved reserve estimates at December 31, 2017 were prepared by Ryder Scott Company, L.P., using SEC guidelines. SEC pricing of $51.34/BBL of oil, $2.98/MCF of natural gas and $31.82/BBL NGLs. (2) For a discussion of the use of PV-10, please refer to slide 2.

Reserves by Category

29% 71% Proved Unproved

Proved Reserves by Commodity

59% 21% 20% Oil Gas NGLs $368 $233 Proved Unproved

PV-10 by Category ($MM) (2) Proved Reserves by Commodity

  • High liquids-weighted reserves drive

value creation

➢ ~80% liquids ➢ Over $600 million total reserve value using SEC pricing

  • All reserves are currently in the

Northern Delaware Basin

  • No reserves booked at December 31,

2017 were associated with Southern Delaware Basin; significant

  • pportunity for future reserves

growth

Significant Reserves Growth

Successful Execution Of Development Plan and Quality Acreage Positions Rosehill for Value and Reserves Gains

13,234 31,132

2016YE 2017YE

Proved Reserves (MBOE) (1)

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25

Hedging Profile

Note: Positions are as of November 7, 2018 (Contract months: October 2018 – Forward).

Hedge positions 2018 2019 2020 2021 2022

Crude Oil Swaps Hedge Volume (BBL) 699,000 2,664,000 1,960,000 2,160,000 1,100,000 Average Price ($/BBL) $55.15 $53.59 $60.09 $61.21 $58.42 Crude Oil Collars Hedge Volume (BBL) 182,000 601,000 Average Ceiling Price ($/BBL) $61.28 $61.30 Average Floor Price ($/BBL) $57.53 $55.21 Crude Oil 3Ways Hedge Volume (BBL) 1,531,832 3,294,000 Average Ceiling Price ($/BBL) $68.52 $70.29 Average Floor Price ($/BBL) $57.62 $57.50 Average Short Put Price ($/BBL) $45.51 $47.50 Midland/Cushing Basis Swaps Hedge Volume (BBL) 920,000 4,800,832 3,513,600 Average Price ($/BBL) ($4.95) ($4.93) ($1.43) Argus WTI CMA Roll Hedge Volume (BBL) 920,000 Average Price ($/BBL) $1.14 Ethane Swaps Hedge Volume (GAL) 2,523,528 12,444,138 Average Price ($/GAL) $0.35 $0.28 Propane Swaps Hedge Volume (GAL) 1,682,352 8,296,218 Average Price ($/GAL) $0.97 $0.79 Pentanes Swaps Hedge Volume (GAL) 560,700 2,765,700 Average Price ($/GAL) $1.53 $1.47 Natural Gas Swaps Hedge Volume (MMBTU) 960,000 2,220,000 1,500,000 1,200,000 1,200,000 Average Price ($/MMBTU) $3.02 $2.88 $2.84 $2.85 $2.87 Natural Gas Basis Swaps Hedge Volume (MMBTU) 1,781,472 2,096,160 Average Price ($/MMBTU) ($1.03) ($1.03)

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2018 Guidance

  • Capital reflects having two rigs drilling and a dedicated frac crew
  • Expect to drill between 32 and 36 wells in 2018

➢ Between 24 and 26 wells drilled in Northern Delaware ➢ Between 8 and 10 wells drilled in Southern Delaware ➢ Additionally, expect to drill four SWD wells Metric 2018 Guidance

Price Assumptions WTI/HH (1) $55 / $3.00 Total Capital ($MM) (2) $350 - $375 Production (BOEPD) 15,500 – 17,000 Adjusted EBITDAX ($MM) (3) $170 - $190 Debt/TTM Adjusted EBITDAX 1.4x - 1.6x

(1) Assumes 2018 realized pricing (excluding hedges) of $52/BBL, Natural Gas $2.35/MCF and NGLs at 33% of WTI. (2) 80% - 85% of Total Capital planned to be utilized for drilling, completion and recompletion activities. (3) Adjusted EBITDAX is a non-GAAP financial measure, please refer to appendix for reconciliation and discussion.

2018 Guidance

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SLIDE 27

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Non-GAAP Measures

The following tables present a reconciliation of Adjusted EBITDAX to net income (loss), the most directly comparable GAAP financial measure for the periods indicated.

Q3'18 Q2'18 Q1'18 2018 Guidance Net income (loss) (84,890) $ 8,664 $ (7,756) $ 51,000 $

  • 58,000

$ Interest expense, net 5,363 4,662 3,867 13,000

  • 17,000

Income tax expense (benefit) 22,923 (15,210) (2,190) 8,000

  • 10,000

Depreciation, depletion, amortization and accretion 47,469 36,506 20,809 98,000

  • 105,000

(Gain) / loss on unsettled commodity derivatives, net 62,315 10,803 18,242 Stock based compensation 2,052 1,760 1,462 Exploration costs 1,348 1,875 436 (Gain) / loss on sale of assets 29 163 133 Other (income) expense, net 105 (57) (100) Adjusted EBITDAX 56,714 $ 49,166 $ 34,903 $ 170,000 $

  • 190,000

$