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Company Presentation May 2018 Forward-Looking Statements This presentation includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of


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SLIDE 1

Company Presentation May 2018

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SLIDE 2

Forward-Looking Statements

This presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can be identified by terminology such as “may,” will,” “could,” “should,” “expect,” “plan,” “project,” “forecast,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “outlook,” “continue” the negative of such terms or other comparable

  • terminology. All statements, other than historical facts included in this presentation, that address activities, events or developments that WildHorse Resource Development

Corporation (WRD) expects or anticipates will or may occur in the future and such things as WRD’s future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth of WRD’s business and operations, plans, market conditions, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. All forward looking statements speak only as

  • f the date of this presentation. Although WRD believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are

reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. WRD cautions you that these forward-looking statements are subject to risks and uncertainties, most of which are difficult to predict and many of which are beyond WRD’s control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to: commodity price volatility; inflation; lack of availability of drilling and production equipment and services; environmental risks; drilling and other operating risks; regulatory changes; the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital; and the timing of development

  • expenditures. Information concerning these and other factors can be found in WRD’s filings with the Securities and Exchange Commission (SEC), including its Forms 10-K,

10-Q and 8-K. Consequently, all of the forward-looking statements made in this presentation are qualified by these cautionary statements and there can be no assurances that the actual results or developments anticipated by WRD will be realized, or even if realized, that they will have the expected consequences to or effects on WRD, its business

  • r operations. WRD has no intention, and disclaims any obligation, to update or revise any forward-looking statements, whether as a result of new information, future results
  • r otherwise.

Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels.

2

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SLIDE 3
  • I. Company Overview

3

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SLIDE 4

10 20 30 40 50 2015 2016 2017 2018E MBoe/d

Premier E&P Company with Top Tier Returns, Growth and Margins

1. Eagle Ford wells drilled and completed as of March 31, 2018, excludes test wells and wells with insufficient production to estimate an EUR. 2. Includes locations outside of CGA’s 3P area. See “Management Locations” in the Appendix section of this presentation for more information. 3. Reserve data based on December 31, 2017 reserve report audited by Cawley, Gillespie & Associates (“CGA”) excluding the North Louisiana assets divested on March 29, 2018. 4. Includes 71 gross (53 net) Austin Chalk locations. 5. Based on consensus pricing as of 5/1/18: $61.50 / $2.97 for 2018, $62.00 / $3.00 for 2019, $62.75 / $3.01 for 2020, $61.00 / $3.15 for 2021, $57.00 / $3.20 for 2022 and thereafter for WTI and Henry Hub, respectively. 6. 2018E based on midpoint of guidance. 7. See slide 34 in the Appendix for reconciliation of EBITDAX.

Premier Acreage Position in the Eagle Ford

Second largest Eagle Ford position in the industry

4

  • TOP TIER RETURNS, GROWTH AND MARGINS
  • 89% growth in 2018 Eagle Ford production at guidance

midpoint

  • High realizations and low operating costs lead to superior

cash margins

  • PROVEN ABILITY TO EXECUTE
  • Outperformance of Gen 3 Eagle Ford wells
  • Increased the Eagle Ford type curve to an EUR
  • f 95 Boe/ft from 91 Boe/ft (1)
  • Average of 117 wells, located throughout the

acreage position, are outperforming the 95 Boe per foot public Eagle Ford type curve

  • 20%+ efficiencies in drilling days and cash operating

costs/Boe achieved in 2017

  • POSITIONED FOR LONG TERM GROWTH
  • Deep Eagle Ford inventory
  • 3,154 net locations at the 95 Boe/ft type curve(2)
  • Over 30 years of inventory at current pace
  • Austin Chalk upside potential on ~100,000 net acres
  • Infrastructure in place to support long-term growth
  • FINANCIAL STRENGTH AND FLEXIBILITY
  • Low leverage profile with no near term maturities
  • Net Debt / Q1’18 Annualized EBITDAX(7)

at 1.3x, expected to trend downward

  • Liquidity of $948 MM at Q1’18(8)

Key Investor Considerations Peer Leading Production Growth in the Eagle Ford(5)

Eagle Ford

Net Acres ~404,000 Proved Reserves (MMboe) 385.6 % Liquids 88% % Oil 73% PV10 of Proved Reserves ($MM) $3,209 Q1'18 Production (Mboe/d) 40.4 % Liquids 88% Drilling Locations Gross 4,785 Net 3,207 Development well IRR 60%

(3) (4) (5)

8. Pro-forma for the issuance of $200 million of 6.875% Senior Notes due 2025 in April 2018 and repayment of borrowings under the revolving credit facility.

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SLIDE 5

80% 90% 100% 110% 120% 130% 140% 150% Jan-18 Feb-18 Mar-18 Apr-18 May-18 WRD S&P E&P Index

17.6 8.7 52.4 31.3

First Quarter 2018 Review: Best in Class Execution

Production Growth(5)

1. Eagle Ford wells drilled and completed as of March 31, 2018, excludes test wells and wells with insufficient production to estimate an EUR. 2. See slide 34 in the Appendix for reconciliation of EBITDAX. 3. Pro-forma for the issuance of $200 million of 6.875% Senior Notes due 2025 in April 2018 and repayment of borrowings under the revolving credit facility. 4. Based on all U.S. E&P companies as of May 1, 2018. 5. Production data for the first quarter 2017 and 2018 includes the North Louisiana assets.

Q1’17 Q1’18

EBITDAX Growth and Decreasing Leverage(2)

Net Production

(Mboe/d)

  • WRD delivered best in class execution in the first quarter 2018
  • Crude oil realizations in the first quarter of 2018 were 103% of WTI
  • 117 Eagle Ford Gen 3 wells online continue to outperform the 95 Boe/ft type curve(1)
  • Brought online 19 gross (18.4 net) Eagle Ford wells and 4 gross (3.6 net) Austin Chalk wells

in the first quarter of 2018

  • Strengthened balance sheet and liquidity position
  • Issued $200 million of 6.875% senior unsecured notes in April 2018
  • Net Debt / Q1’18 Annualized EBITDAX at 1.3x(2)
  • Increased the borrowing base on the credit facility to $1.05 billion from $875 million
  • Liquidity increased by $359 million to $948 million from Q4’17(3)

Year to Date Highlights Stock Price Outperformance Year to Date

Q1’17 Q1’18 Net Oil Production

(Mbo/d) 41% 5% 36% Incremental Return

3rd Best E&P Stock Performance Year-to-Date(4) 34.6 1.8x 158.6 1.3x EBITDAX

(SMM)

Net Debt / Annualized EBITDAX Q1’17 Q1’18 Q1’17 Q1’18

5

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SLIDE 6

2018 Catalysts for Growth and Value Creation

  • Closed the North Louisiana divestiture positioning WRD as the premier Eagle Ford pure play
  • Post divestiture, WRD has an oilier production profile with higher margin production, improved balance sheet

metrics and liquidity

  • Increased Eagle Ford acreage to ~404,000 net acres from ~263,000 net acres at year-end 2016
  • WRD increased the Eagle Ford type curve to 95 Boe/ft from 91 Boe/ft based on continued outperformance
  • Plan to drill and complete 100 to 110 Eagle Ford and Austin Chalk wells in 2018
  • Active delineation program planned in the Eagle Ford and Austin Chalk

Transition to Eagle Ford Pure Play Increased Eagle Ford Type Curve

6

  • Development of an in-field sand mine will reduce D&C costs by an estimated $400K-$600K per well

(a 58% reduction in sand costs at the midpoint) with an expected start date by first quarter 2019

  • Sand mine gives WRD greater operational control and reduces volatility in sand costs
  • Projected sand savings of $1.2 - $1.8 billion over ~3,000 net locations
  • Sand mine contains over 40+ years of reserves

Reduction in D&C Costs

In-Field Sand Mine

Austin Chalk Upside

  • Conservative location count of 53 net locations based on 1,500’ spacing and ~15,000 net acres. WRD expects

that an additional ~85,000 net acres have Austin Chalk development potential

  • Conservative Washington County budget type curve of 341 Boe per foot (64% gas, 29% NGLs, and 7% oil)
  • Brought online the Morgan #1H/Brodnax #1H in Washington County with at an IP-30(1) of 2,483 Boe/d or 14.9

MMcfe/d (67% natural gas, 32% NGLs, and 1% oil) on a 5,311’ lateral

1. The initial production rates represent the peak average of the initial production rates for the applicable consecutive days of production.

Attractive Differentials

  • Proximity to Gulf Coast markets with no takeaway and logistical constraints
  • 100% of crude oil production priced at a Louisiana Light Sweet (LLS) premium
  • Differentials drive top tier margins
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SLIDE 7

North Louisiana Divestiture – WRD is the Premier Eagle Ford Pure Play

Rationale 7

  • On March 29, 2018, WRD closed the North Louisiana divestiture for a total net

sales price of approximately $206.4 million after customary preliminary purchase price adjustments of $9.7 million

  • Additionally, WRD could receive contingent payments of up to $35

million based on the number of wells spud on the North Louisiana assets

  • ver the next four years
  • Asset Summary:
  • ~90,000 net acres
  • Year end proved 2017 reserves of 412.1 Bcfe (41% proved developed /

98% natural gas)

  • Q1’18 production of 72.2 MMcfe/d (97% natural gas)

Summary

  • WRD becomes a pure play Eagle Ford E&P with a single basin focus
  • Oilier Eagle Ford production profile
  • Eagle Ford production generates higher margins
  • Smoother production cadence with faster Eagle Ford cycle times
  • Improved leverage and liquidity metrics
  • Divestiture proceeds help fund the 2018 drilling program

✓ ✓ ✓ ✓ ✓ ✓

98%

41 28 299 86

Oil NGLs Gas

North Louisiana

PUD PD

Reserves More Oil-Weighted Post Divestiture Proved Reserves by Basin

73% 15% 12%

Eagle Ford

62% 13% 25%

Total Company

2%

Divestiture Increases Proved Reserve Oil Mix from 62% to 73%

Total 385.6 MMboe Total 68.7 MMboe Eagle Ford North Louisiana

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SLIDE 8

100 118 145 147 165 190 213 241 250 270 286 359 404 520 SilverBow EP Energy Marathon Murphy Oil SM Energy BP ConocoPhillips BHP Billiton Apache Chesapeake Sanchez Energy Magnolia WildHorse EOG Resources (000s Acres)

Net Acreage Positions (1) Operator Acreage Positions (1)

1. Net acreage positions per Company Investor Presentations, Company Filings and published reports as of March 2018. 2. Pending Magnolia Oil & Gas Corporation acquisition announced on March 20, 2018.

WRD Operates the Second Largest Eagle Ford Position

TX LA AR OK NM

80 Miles Oil Wet Gas/Condensate Dry Gas Eagle Ford Shale

(2)

8

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SLIDE 9

105 386 163 71 72 8 (11) (21) 100 200 300 400 500

YE 2016 Total Reserve Adds Acquisitions Performance Revisions Price Revisions Production North Louisiana Adjustment YE 2017 Total

73% 15% 12%

Eagle Ford Proved Reserves More than Tripled at Attractive Costs

2017 Proved Reserve Additions Proved Reserves Breakout

Note: Reserve information based on year end 2017 and 2016 audited reserve reports by CGA excluding the North Louisiana assets divested on March 29, 2018. 1. See slides 35 – 36 for additional disclosures related to WRD’s PV-10 and 3P reserves. 2. See slide 37 for WRD’s Finding and Development cost ( F&D) calculation. 3. Pro-forma for the impact of the North Louisiana divestiture on reserve adds, performance revisions, and price revisions at the year 2017 CGA reserve report.

9 Reserves Overview 2017 Drilling Program Added $2.6 Billion in PV10

  • PV-10(1) of proved reserves increased by 412% to $3.2 billion at year end

2017 from $626 million at year end 2016

  • 268% increase in proved reserves at year end 2017
  • Increased 3P reserves by 193% to 1,450 MMboe
  • Eagle Ford drill-bit finding and development (“F&D”) costs excluding

acquisitions and price revisions averaged $3.28 per Boe(2)

  • Replaced 2,498% of estimated Eagle Ford production in 2017 including

performance revisions and excluding price revisions and acquisitions

  • Pro-forma proved reserve life of 45 years based on 2017 Eagle Ford

production and reserves

79 25 299 86

83% 10% 7%

2017 Proved Reserves

Oil NGLs Gas

2016 Proved Reserves 2017 Proved Reserves 2016 Proved Reserves

PUD PD

385.6 MMboe 104.7 MMboe

$626 $3,209 $1,440 $479 $791 $374 ($295) ($207) $0 $1,000 $2,000 $3,000 $4,000 YE 2016 Total Reserve Adds Acquisitions Performance Revisions Price Revisions Production North Louisiana Adjustment YE 2017 Total

(3) (3)

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SLIDE 10

1,996 3,154 3,207 655 53

500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 WRD YE 2016 Eagle Ford (EUR 95 Boe/ft) Austin Chalk WRD YE 2017

$Millions

$0 $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 $8,000 $9,000 $10,000 $11,000 $12,000 Current Valuation SEC Pricing Consensus Pricing

Net Locations (1)

Deep Inventory of Economic Locations at a Compelling Valuation

1. As of December 31, 2017 and pro-forma for the Lee County acquisition closed on March 1, 2018, we identified 3,207 net horizontal drilling locations. The locations were specifically identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic and engineering data. We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other operators across our acreage, combined with our interpretation of available geologic and engineering data. The drilling locations on which we actually drill will depend on the availability of capital, regulatory approval, commodity prices, costs, actual drilling results and other factors. Of our 3,207 estimated drilling locations, 544, 700 and 1,516 are associated with CGA’s proved, probable and possible reserves as of December 31, 2017. Accordingly, 446 of these locations are within management’s 3P area and do not have any reserves assigned to them. There are no assurances that these locations will perform like we expect. All of our assumptions with respect to our drilling locations, including estimated ultimate recoveries, expected costs to drill and complete, internal rates of return and economic break-even prices are speculative in nature and may prove to be inaccurate. The Lee County acquisition includes 110 net Eagle Ford management locations. 2. Assumes WRD closing share price of $25.92 as of 5/1/18.

10 Significant Upside to Current Valuation (PV-10 $MM) (3)(4)(5)

PDP $1,264 PUD $1,944 POSS $3,039 PDP $1,539 PUD $2,772 PROB $2,198 POSS $4,037 Market Cap $2,625 Net Debt $450

Net Horizontal Locations by Area(4)

Multiple decades of drilling inventory across Eagle Ford on net locations(1) Best in class execution led to 21% increase in Eagle Ford locations

Total Proved $3,209 Total Proved $4,311 Eagle Ford (EUR 91 Boe/Ft) Eagle Ford Other

Eagle Ford Locations Austin Chalk Locations

PROB $1,674

2,651

Preferred

(2)

YE 2017 Audited Reserves

$802

3. See slides 35 – 36 for additional disclosures related to WRD’s PV-10 and 3P reserves. 4. Excludes locations and PV-10 of the North Louisiana assets divested on March 29, 2018. 5. See a reconciliation on slide 35 of Eagle Ford PV-10 to GAAP PV-10 reported in the year-end 2017 10-K.

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SLIDE 11

Type Well Assumptions 95 Boe/Ft Wellhead EUR (MBoe) 574 Oil EUR (Mbbl) 508 % Oil 89% Gas EUR (MMcf) 393 Sales EUR (MBoe) 620 Oil EUR (Mbbl) 508 Gas EUR(MMcf) 234 NGL EUR (Mbbl) 72 % Gas 6% % Oil 82% % NGL 12% % Liquids 94% GOR (Mcf/bbl) 0.77 Lateral Length (ft) 6,500 Shrinkage 60% Variable Water Cost ($/Water Bbl) $1.17 Type Curve 30-day Oil IP (Bbl/d) 621 30-day Gas IP (Mcf/d) 480 30-day IP (Boe/d, 3-Stream) 757 30-day IP (Boe/d) per 1,000' 116 Initial Decline (%) 77% B Factor 1.40 Terminal Decline (%) 6% NPV 10 & IRR

D&C

$5.9MM $6.1MM $6.5MM NPV10 ($MM) $6.7 $6.5 $6.1 IRR (%) 72% 68% 60%

1. Eagle Ford wells drilled and completed as of March 31, 2018, excludes test wells and wells with insufficient production to reach a peak IP30 rate as of March 31, 2018. The first day of the peak IP30 rate is considered day 1 of cumulative production. Data is normalized for 6,500’ laterals and downtime. 2. D&C costs based on WRD sand mine estimated savings of $400,000 to $600,000 per well at well costs of $5.9 and $6.1 million per well. 3. IRR sensitivities based on consensus pricing as of 5/1/18: $61.50 / $2.97 for 2018, $62.00 / $3.00 for 2019, $62.75 / $3.01 for 2020, $61.00 / $3.15 for 2021, $57.00 / $3.20 for 2022 and thereafter for WTI and Henry Hub, respectively

Eagle Ford Type Curve Increased from 91 to 95 Boe/ft

Type Curve (1) Eagle Ford Single Well Summary 11

20% 40% 60% 80% 100% 120% 140% 160% $50.00 $55.00 $60.00 $65.00 $70.00 $75.00 $80.00

IRR

Oil Price

IRR Sensitivity

(2)

40 80 120 160 200 1 3 5 7 9 11 13 14 16 18 20 22 24 Months 95 Boe/ft Type Curve Gen 3 Average Boe Mboe Cumulative

$5.9 D&C Capex(2) $6.1 D&C Capex(2) $6.5 D&C Capex

(3)

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SLIDE 12

WRD Projected to Have Industry Leading Metrics

Debt Adjusted Production Growth 2017E-2018E (1) Debt Adjusted Cash Flow Growth 2018E (3) 12

Note: Peer groups vary as a result of sourcing data from several different equity research firms cited below. 1. Source: Raymond James equity research. 2. Source: Simmons & Company equity research report. See slide 37 for ROCE calculation methodology. 3. Source: Citi equity research. 4. Source: Guggenheim Securities Equity Research. Guggenheim Research defines EBITDAX Margin as EBITDAX (Revenue, plus/minus realized hedging, minus LOE, minus production and ad valorem tax, minus gathering, processing and transportation expense, minus general and administrative expense (excluding non-cash compensation)) divided by revenue (including realized hedging).

2018E ROCE (2) 2018E EBITDAX Margin (4)

0% 10% 20% 30% 40% 50% 60% 0% 5% 10% 15% SRCI WRD CRZO LPI SN OAS WPX WLL QEP 0% 20% 40% 60% 80% 100% 120% WRD CDEV JAG WPX PE XOG FANG SRCI CRZO CPE MRO CLR OAS XEC 0% 30% 60% 90% WRD CLR RSPP SM OAS WPX EPE NFX WLL

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SLIDE 13

60% 68% 72% 0% 20% 40% 60% 80% 100% $6.5MM D&C $6.1MM D&C ($400K Savings) $5.9MM D&C ($600K Savings)

Developing an In-Field Sand Mine

Sand Mine Increases Well Returns and Provides Greater Operational Control

Sand Mine Overview and Rationale Returns Uplift from Sand Mine Savings

  • Estimated cost of $65-$75MM for acquisition, evaluation, and construction
  • Expected to be operational by the first quarter of 2019
  • Contains 85 million tons of sand or over 40 years of reserves
  • Reserves contain fine grade 100 mesh and 40/70 sand, comparable to

the product WRD currently sources from third parties

  • Rationale
  • Sand Savings: 58% reduction in sand costs on $/ton (1)
  • Well Cost Savings: Estimated reduction of $400K-$600K per well
  • Increased Returns: Incremental single well returns of up to 12%
  • Short Payback Period: Capital investment recovered in less than two

years upon completion based on the current pace of WRD’s activity

  • Greater Operational Control: WRD-owned sand supply mitigates

transportation costs and reduces volatility in completion costs

In-Field Location Significantly Reduces Transportation Costs 13

Sand Seams WRD Sand Mine Location

` WRD Sand Mine

WRD Acreage Projected sand savings of $1.2 - $1.8 billion over ~3,000 net locations

1. At midpoint of estimated well cost savings. 2. Based on consensus pricing as of 5/1/18: $61.50 / $2.97 for 2018, $62.00 / $3.00 for 2019, $62.75 / $3.01 for 2020, $61.00 / $3.15 for 2021, $57.00 / $3.20 for 2022 and thereafter for WTI and Henry Hub, respectively 3. Map of sand seams sourced from Google Earth.

(3)

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SLIDE 14

Capacity and Optionality Around Midstream, Vendor Services, Water and Infrastructure

Optionality Around Takeaway Capacity Significant Midstream and Vendor Infrastructure Multiple Vendors for Key Services

TX NM OK LA AK

Eaglebine Express (Sunoco)

Burleson Lee Washington Freshwater Pond Brazos Milam

  • Multiple vendors for all key services provides flexibility and ample capacity
  • Limited long term contracts
  • Secured dedicated freshwater supply from 35 ponds and an agreement with the

Brazos River Authority

  • ~ 462 million Bbls of fresh water rights per year (~1,023 wells per year)
  • Diversified sand supply with multiple sand suppliers in close proximity
  • Developing in-field company sand mine online by first quarter 2019
  • Negotiated sand contracts to secure prices in 2018
  • Close proximity to market and well-developed midstream infrastructure
  • In-field gathering and extensive market assets in place to ensure flow

and downstream connectivity

  • Diverse physical marketing portfolio with access to Gulf Coast refining

markets

  • Proximity to market minimizes transportation cost and related

commitments while maximizing margins

WRD HQ Houston, TX

14 Service Category Current Vendors Available Drilling 2 10+ Pressure Pumping 2 6+ Coil Tubing 2 6+ Proppant 5 10+ Cementing 2 4+ Chemicals 10 10+ Fuel 2 6+ Ample Water Supply

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SLIDE 15

$5.6 $0.6 $0.4 ($0.1) $6.5 ($0.4 - $0.6) $5.9 - $6.1

$0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 2017 Target Development Well Service Cost Inflation Sand Transportation Increase Negotiated Sand Contracts 2018 Budget Well Sand Mine Savings Future Target Development Well

WildHorse Operated In-Field Sand Mine Offers Significant Savings

Current and Development Well D&C Costs ($MM) 15

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SLIDE 16
  • WRD Gen 3 wells continue to
  • utperform 95 Boe/ft type curve

across the acreage position

  • Current Eagle Ford producing

wells exist across entire ~800 square mile area

  • Brought online 19 gross (18.4

net) wells Eagle Ford wells in the first quarter of 2018

  • Brought online 4 gross (3.6 net)

Austin Chalk wells in the first quarter of 2018

  • Potential on ~100,000 net acres

prospective for the Austin Chalk

  • Used refracs to cost effectively

delineate the acreage with a Gen 3 completion design

  • Position includes upside potential
  • n ~94,000 net acres outside of

CG&A’s 3P area without assigned locations

1. Data for WildHorse based on actual results reported by WildHorse management. The initial production rates represent the peak average of the IP rates for the applicable consecutive days of production; IP rates are not normalized for lateral

  • length. Dates are first production. WildHorse Gen 3 wells as of December 31, 2017 and additional recently highlighted wells.

2. The dark grey area represents ~310,000 net acres within CGA’s and management’s 3P reserve area. 3. The light grey area represents ~94,000 net acres outside of CGA’s and management’s 3P reserve area with no assigned locations. 4. Two well pads represented with average EURs, initial production rates, oil mix, and lateral lengths.

Well Results Continue to Outperform and Delineate Acreage Position

Horizontal Well Activity (1)

Ascari B #1H EUR: 110 Boe/Ft IP30 = 711 Boe/d (91% oil) 7,038’ LL (12/20/2017) BCMT A #1H EUR: 121 Boe/Ft IP30 = 533 Boe/d (69% oil) 6,878’ LL (7/4/17) Candace #1H EUR: 181 Boe/Ft IP30 = 1,081 Boe/d (88% oil) 7,481’ LL (9/2/16) Belmont Stakes #1H EUR: 115 Boe/Ft IP30 = 740 Boe/d (65% oil) 5,831’ LL (10/1/16)

16

Chmelar South #1H EUR: 149 Boe/Ft IP30 = 1,011 Boe/d (92% oil) 6,915’ LL (5/22/17) Goodnight #3H EUR: 121 Boe/Ft IP30 = 724 Boe/d (93% oil) 5,833’ LL (5/28/17) Hovorak EF Unit #1H EUR: 124 Boe/Ft IP30 = 926 Boe/d (91% oil) 6,470’ LL (6/11/2017) Cooper B #1H EUR: 107 Boe/Ft IP30 = 576 Boe/d (85% oil) 4,780’ LL (2/22/17) Altimore #1H EUR: 126 Boe/Ft IP30 = 1,048 Boe/d (84% oil) 6,435’ LL (3/31/2017) Wilde EF 1H / Teal EF 1H(4) EUR: 91 Boe/Ft IP30 = 602 Boe/d (93% oil) 6,513’ LL (10/20/2017) Balcar Unit #1(Refrac) IP30 uplift: 370 Boe/d (92% oil) 4,973’ LL (3/18/2018) Morgan #1H/ Brodnax #1H(4) (Austin Chalk) IP30: 2,483 Boe/d (1% oil) 5,311’ LL (3/7/2018)

Additional WRD Acreage(3) WRD Acreage with Locations(2) WildHorse Gen 3 wells

Fritsche 109 #1(Refrac) IP30 uplift: 481 Boe/d (88% oil) 5,387’ LL (1/1/2018) Brollier AC #1H (Austin Chalk) IP30 = 3,030 Boe/d (8% oil) 5,684’ LL (1/18/18) Lillie Hohlt #1H (Austin Chalk) IP30 = 2,604 Boe/d (3% oil) 4,815’ LL (11/19/17) Dusek A #1H EUR: 130 Boe/Ft IP30 = 890 Boe/d (91% oil) 7,438’ LL (11/22/2017) Irene #1H /Inez #1H/Lero #1H(4) IP30 = 778 Boe/d (90% oil) 6,404’ LL (3/22/2018)

Legacy Eagle Ford wells

Winkelmann #1H (Austin Chalk) EUR: 400+ Boe/ft IP30 = 2,387 Boe/d (26% oil) 4,762’ LL (6/3/17)

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SLIDE 17

Washington County Austin Chalk Budget Type Curve (5,000’ lateral)

500 1,000 1,500 2,000 2,500 3,000 3,500 30 60 90 120 150 180 210 240 270 300 330 360

Barrels of Oil Equivalent Per Day

1. The initial production rates represent the peak average of the initial production rates for the applicable consecutive days of production. 2. IRR sensitivities based on consensus pricing as of /1/18: $61.50 / $2.97 for 2018, $62.00 / $3.00 for 2019, $62.75 / $3.01 for 2020, $61.00 / $3.15 for 2021, $57.00 / $3.20 for 2022 and thereafter for WTI and Henry Hub, respectively.

Additional type curve details:

  • Current Austin Chalk location count of 53 based on ~15,000 net acres in Washington County – WRD expects that an additional ~85,000 net acres have development potential
  • Peak IP-30 of 1,755 Boe/d (7% oil, 29% NGLs, 64% gas)(1)
  • IRR of 34% at consensus pricing based on a current well costs of $7.8 million per well(2)
  • IRR of 39% and 37% at consensus pricing based on estimated well costs of $7.2 to $7.4 million per well upon completion of WRD’s in-field sand mine(2)

EUR: 341 Boe Per Foot 17

Days Washington County Austin Chalk Budget Type Curve Winkelmann #1H Lillie Hohlt #1H Brollier AC 1H

7% 29% 64% Oil NGLs Gas

Brodnax #1H Morgan #1H

slide-18
SLIDE 18

Source: Corporate Filings and Company Data. 1. Differentials based on average realized $/Bbl for the three months ended 12/31/17. Companies included in Permian: FANG, LPI, RSPP, CXO; Companies included in Eagle Ford: CRZO, SN; Companies included in DJ Basin: PDCE and SRCI (XOG excluded due to timing of earning release); Companies included in Bakken: CLR, WLL; Companies included in SCOOP / STACK: NFX. 2. Based on Citigroup equity research with annotations including LLS pricing by WRD with data from FactSet as of May 2, 2018.

Proximity to Gulf Coast Leads to Advantaged Oil Pricing

Q1’18 Comparative Basin Differentials (1)

WTI Cushing # Basin Differential U.S. Shale Basins

Permian Basin DJ Basin Bakken South Texas Eagle Ford WRD Eagle Ford ($1.20) ($5.81) ($4.08)

$1.91

SCOOP / STACK ($4.78) ($0.33)

  • WRD receives LLS pricing minus transportation costs
  • Regional location provides lower operating costs and better realized pricing due

to proximity to demand centers for oil, natural gas and NGLs

  • Low basis differentials along the Gulf Coast represent competitive

advantage when compared to other plays

  • WRD realized 103% of WTI during Q1’18
  • Entered into LLS-WTI basis swaps for 2018 to secure favorable pricing
  • Potential upside to develop an integrated midstream system to service Eagle

Ford assets 18 Comparative Basin Differentials (1) LLS Premium Outperforms WTI-Midland Differentials(2)

$(12.00) $(10.00) $(8.00) $(6.00) $(4.00) $(2.00) $- $2.00 $4.00 $6.00 $8.00 Jan-17 Mar-17 May-17 Jul-17 Sep-17 Nov-17 Jan-18 Mar-18 May-18 Jul-18 Sep-18 Nov-18 Jan-19 Mar-19 May-19 Jul-19 Sep-19 Nov-19

Current - WTI-Midland 1 Week Ago - WTI - Midland 1 Month Ago - WTI-Midland 2 Months Ago - WTI-Midland 3 Months Ago - WTI-Midland 4 Months Ago - WTI-Midland

Current WTI-LLS Current WTI-Midland

slide-19
SLIDE 19

Eagle Ford Wells Outperform Competing Basins and Peers on Cash Margin

$46.64 $37.15 $34.11 $29.90 $29.17 $3.00 $2.83 $3.21 $2.29 $2.94 $3.87 $5.09 $5.85 $9.22 $3.55 $1.73 $3.12 $0.32 $4.81 $9.92 $16.07 $16.57 $21.14 $22.40 $63.44 $62.87 $62.87 $62.87 $62.87 $0.00 $10.00 $20.00 $30.00 $40.00 $50.00 $60.00 WRD Eagle Ford Permian Bakken Eagle Ford DJ Basin $/Boe

Cash Margin: WRD Eagle Ford vs. Competing Basins(1) (1Q 2018)

Source: Company filings and investor presentations. Note: Assumes 6:1 gas to oil ratio. Commodity mix represents the difference between average WTI price and the weighted average commodity price per Boe of the company’s production (using Henry Hub for gas and assuming NGL pricing equal to 35% of WTI). Does not include G&A and other corporate level costs. 1. Companies included in Permian: CXO, FANG, LPI and RSPP; Companies included in Bakken: CLR and WLL; Companies included in Eagle Ford: CRZO and SN; Companies included in DJ Basin: PDCE, SRC and XOG.

Cash Margin Production & Ad Valorem Taxes LOE & GP&T Differential Commodity Mix

19

$62.87 Q1 2018 Average WTI Price

% Oil 77% 64% 60% 44% 47%

slide-20
SLIDE 20
  • II. Financial Overview

20

slide-21
SLIDE 21

$0 $150 $300 $450 $600 $750 $900 $1,050 $1,200 2018 2019 2020 2021 2022 2023 2024 2025 2026

Strong Balance Sheet and Liquidity Position at 3/31/18

Capitalization Strong Liquidity Position

1. Pro-forma for the issuance of $200 million of 6.875% Senior Notes due 2025 in April 2018 and repayment of borrowings under the revolving credit facility. 2. Excludes unamortized net discount and unamortized debt issuance costs. 3. Liquidation preference. 4. Credit metrics assume 100% equity treatment for the Series A Perpetual Convertible Preferred.

21 No Near Term Maturities

$700MM 6.875% Senior Notes $1,050 MM Borrowing Base ($ in millions) 3/31/2018 Cash $7 WRD Revolving Credit Facility (1) $109 6.875% Senior Notes (1) (2) $700 Total Debt $809 Series A Cum. Perpetual Convertible Preferred (3) $450 Shareholders Equity $1,027 Financial & Operating Statistics Q1'18 Annualized EBITDAX $635 Q1'18 Annualized Interest Expense $53 Q1'18 Daily Production (Mboe/d) 52.4 Credit Metrics (4) Net Debt / Q1'18 Daily Production ($/Boe/d) $15,308 Net Debt / Q1'18 Annualized EBITDAX 1.3x Interest Coverage 11.9x ($ in millions) 3/31/2018 Liquidity Borrowing Base $1,050 Cash $7 Revolver Borrowings (1) ($109) Total Liquidity (5) $948 $MM

(1) (1)

slide-22
SLIDE 22

FY 2018 Guidance (as of February 12, 2018)

2018 Guidance

1. The guidance above is based on the prior accounting convention before the implementation of the new FASB revenue recognition standard (ASC 606, Revenue from Contracts with Customers), effective as of January 1, 2018. After the implementation date, approximately two-thirds of GP&T expense is expected to be recognized as a deduction from revenue while the remainder is expected to be recognized as a GP&T expense line item. See slide 38 for a reconciliation of GP&T in the first quarter 2018 to the prior accounting convention from the new FASB standard. See the MD&A section of WRD’s 10-Q filing to be filed on or before May 15, 2018. 2. Excludes non-cash compensation charges associated with grants under our LTIP and incentive units issued to certain of our officers and employees. WRD does not guide to anticipated average non-cash general and administrative costs. Please see cautionary language under “Cautionary Statements and Additional Disclosures” for additional disclosures because such compensation charges are based in part on the price of our common stock and are too speculative to predict. 3. Based on strip pricing as of February 9, 2018.

22

Low High Net Average Daily Production (Mboe/d) Oil (Mbbls/d) Natural Gas (MMcf/d) NGLs (Mbbls/d) Average Costs (per Boe) Lease Operating Expense Gathering, Processing, and Transportation(1) Cash General and Administrative(2) Taxes Other than Income (% of oil & gas revenue) Commodity Price Realizations (Unhedged)(3) Crude Oil Realized Price (% of WTI NYMEX) Natural Gas Realized Price (% of NYMEX to Henry Hub) NGL Realized Price (% of WTI NYMEX) Drilling Program Wells Spud (Gross) Wells Completed (Gross) D&C Capital Expenditure ($MM) Sand Mine Capital Expenditure ($MM) FY 2018 Guidance 31 - 35 45 - 55 5 - 7 ($2.90) - ($3.40) 46 - 49 90% - 94% 33% - 37% 100 - 110 100 - 110 $700 - $800 $65 - $75 ($1.10) - ($1.40) ($2.00) - ($2.50) 5.0% - 6.0% 98% - 102%

slide-23
SLIDE 23

WildHorse Commodity Hedging Overview

1. Using the midpoint for collars and floors of puts. 2. Represents mid-point of fiscal year 2018 guidance. 3. Hedges as of 5/9/18.

23

Highlights Hedge Summary

  • Disciplined and balanced hedging strategy

focused on minimizing commodity price downside (swaps, collars) and cost effectively maximizing commodity price upside (deferred premium puts)

  • Proactive policy reduces WRD’s exposure to

movements in commodity prices and provides stability to cash flow

  • All trading counterparties have investment

grade ratings at both S&P and Moody’s

  • While 75% of expected Q2 – Q4 2018 oil

production is hedged, 48% of expected oil production provides upside potential to higher commodity prices through the use of put

  • ptions
  • Hedges in place help secure WRD’s peer

leading cash margins

  • Attractive WTI-LLS oil basis hedges lock in a

premium basis differential

Q2 - Q4 2018 2019 2020 Crude Oil Hedge Contracts: Total crude oil volumes hedged (Bbl) 6,895,632 8,402,126 4,511,681 Volumes Hedged (Bbl/d) 25,075 23,020 12,327 Total weighted-average price ($/Bbl) (1) $51.88 $54.32 $53.49 % of Expected Production (2) 75% Natural Gas Hedge Contracts: Total natural gas volumes hedged (MMBtu) 6,730,332 6,425,146 4,846,020 Volumes Hedged (MMBtu/d) 24,474 17,603 13,240 Total weighted-average price ($/MMBtu) (1) $2.79 $2.79 $2.76 % of Expected Production (2) 72% Total Hedge Contracts (Swaps, Collars, Puts): Total hedged production (Mboe) 8,017,354 9,472,984 5,319,351 Volumes Hedged (Boe/d) 29,154 25,953 14,534 Total weighted-average price ($/Boe) (1) $45.02 $48.49 $45.79 % of Expected Production (2) 64% WTI-LLS Oil Basis Hedges Volumes hedged (Bbl) 4,763,026 – – Volumes Hedged (Bbl/d) 17,320 – – Weighted-average price ($/Bbl) $3.03 – – % of Expected Production (2) 52%

slide-24
SLIDE 24

Investment Highlights

Strong Balance Sheet Positioned for Long Term Growth

24

Oil-Weighted Eagle Ford Pure Play Top Tier Returns, Growth and Margins Attractive Differentials and Proximity to End Markets Proven Ability to Execute Abundant Service Capacity and Infrastructure to Support Development

slide-25
SLIDE 25
  • III. Appendix

25

slide-26
SLIDE 26

Previous Position 2nd CWEI Acquisition Burleson Brazos Washington Lee

Lee County Acquisition – March 2018

Focused Strategy of Eagle Ford Acreage Growth and Consolidation

WildHorse continues to execute on a proven strategy of organic leasing and targeted acquisitions to grow its high quality Eagle Ford acreage position to 404,000 net acres

Multiple Acquisitions – Sept. 2015(1)

Previous Position Lee Burleson Brazos Washington Lee

3rd CWEI Acquisition – Dec 2016 Organic Leasing / Acreage Swaps SM Acquisition – January 2015

Initial Position Washington Burleson Brazos Washington Lee

1. Includes three acquisitions in Lee County that occurred over ~12 months.

APC / KKR – June 2017 2nd CWEI Acquisition – Dec 2015

Previous Position Organic Leasing / Swaps Burleson Brazos Washington Lee Burleson Brazos Washington Lee Previous Position 3rd CWEI Acq. Burleson Brazos Washington Lee Previous Position APC / KKR Acq.

20 Miles

1st CWEI Acquisition and Comstock Acquisition – June/July 2015

Previous Position 1st CWEI and Comstock Acquisitions Burleson Brazos Washington Lee Burleson Brazos Washington Lee Previous Position Lee County Acq.

26

slide-27
SLIDE 27

WildHorse Acreage Positioned in the Highly Productive, Liquids-Rich Eagle Ford

Top of Eagle Ford Structural Map Gross Thickness Isopach Map

Lee Washington Burleson Milam Bastrop Fayette Austin Waller Grimes Brazos Lee Washington Burleson Milam Austin Waller Grimes Brazos Fayette

Oil Gravity Gas / Oil Ratio

60.0 57.5 55.0 52.5 50.0 47.5 45.0 42.5 40.0 37.5 35.0

°API

10,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 250

Mcf / STB

Deep Shallow

  • 6,000'
  • 7,000'
  • 8,000'
  • 9,000'
  • 10,000'
  • 11,000'
  • 12,000'
  • 13,000'
  • 14,000'

Thin Thick

500' 450' 400' 350' 300' 250' 200' 150' 100' 50'

Brazos Milam Washington Lee Fayette

  • Geology matters:
  • Gas to oil ratio
  • Clay content
  • Oil gravity
  • Pore pressure – geopressure
  • f ~0.75 Psi / Ft
  • The Eagle Ford is a Cretaceous

sediment where the formation’s carbonate content can exceed 70% in WildHorse’s position

  • Gross Eagle Ford thickness ranges

from over 100’ to greater than 400’ across the acreage position

  • Thickness allows greater potential

for stacked / staggered development opportunities in both the Eagle Ford and the Austin Chalk

  • Clay content increases in the

Northeast portion of the play in Brazos and Madison counties

  • Rich carbonate content and lower

clay content allow more effective hydraulic fracturing Lee Washington Burleson Milam Bastrop Fayette

Grimes

Brazos Burleson

Grimes

WRD Acreage WRD Acreage WRD Acreage WRD Acreage

27

slide-28
SLIDE 28

10 20 30 40

2015 2016 2017 2018E

20 40 60 80 100 120

YE 2016 Type Curve YE 2017 Type Curve Gen 3 Gen 3

Gen 3 Design Unlocks Improved EURs and Significant Eagle Ford Oil Growth

1. Eagle Ford wells drilled and completed including refracs as of December 31, 2017, excludes test wells and wells with insufficient production history to estimate an EUR. 2. Source: BMO Equity Research.

28 Increased Intensity Has Improved EURs(1) Outperformance on both Bo/ft and Boe/ft (1)

76 Bo/Ft 78 Bo/Ft 91 Boe/Ft 95 Boe/Ft 111 Boe/Ft Boe/ft

WRD’s Eagle Ford Oil Mix Leads Other Active Basins (2) Significant Year over Year Eagle Ford Oil Growth

76 81 99 111 20 40 60 80 100 120

Gen 1 Gen 2 Gen 3 Eagle Ford Gen 3 Eagle Ford + Austin Chalk

15 98 1,500 2,600 3,700 7

Wells Completed Target Proppant (lbs/ft)

Boe/ft

82% 78% 69% 69% 60% 50% 32% 29%

0% 20% 40% 60% 80% 100% WRD Bakken PRB Midland Delaware Niobrara Stack Scoop

Oil Mix After Year 1 and 2 of Production

Oil Mix

Year 1 Year 2

80 Bo/Ft

84% 272% 97%

MBbls/d 3,700 101 82 Bo/Ft 99 Boe/Ft

Gen 3

Eagle Ford + Austin Chalk

Performance Gen 3

Eagle Ford

Performance

slide-29
SLIDE 29

WRD’s Attractive Eagle Ford Acquisition Metrics Bolster Full Cycle Returns

Note: WRD location counts for APC / KKR and CWEI acquisitions based on 500’ spacing and include only net locations located in the 91 Boe/ft type curve area. Permian and SCOOP / STACK represent average of transactions from 1/1/2016 to 5/3/2018 based on Company Investor Presentations, Company Filings and published reports. 1. Purchase Price adjusted for production at $40,000 Boe/d. 2. Venado / COG net locations not disclosed. 3. Assumes 435 net locations in Karnes and 1,000 gross locations in Giddings field with average working interest of 30%.

$1,863 $2,103 $2,958 $3,230 $4,449 $6,826 ~$8,000 ~$26,000

$0 $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 Venado / COG WRD EF Acquisitions Magnolia / Enervest Halcon / Hawkwood EP Energy / Carrizo Sundance / Pioneer SCOOP / STACK Permian Basin

Purchase Price / Net Acres PDP Adjusted Purchase Price(1) / Net Acres

($ / acre) ($ / acre)

WRD has agreed to acquire Eagle Ford acreage at attractive economics per net location on a PDP-adjusted basis

  • Over its last two major Eagle Ford acquisitions, WRD has averaged ~$420,000 / net location for 1,348 net locations
  • Since 1/1/2016, acquisitions in the Permian Basin have averaged ~$1.5 million / net location and transactions in the SCOOP / STACK have averaged

~$0.9 million / net location

$420 $545 $586 $650 ~$900 $1,445 ~$1,500

$200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 WRD EF Acquisitions EP Energy / Carrizo Sundance / Pioneer Halcon / Hawkwood SCOOP / STACK Magnolia / Enervest Permian Basin

PDP Adjusted Purchase Price(1)(2) / Net Locations

($ 000's / location)

$3,810 $6,211 $7,414 ~$9,000 $10,000 $10,114 $10,268 ~$29,000

$0 $5,000 $10,000 $15,000 $20,000 $25,000 $30,000 WRD EF Acquisitions Halcon / Hawkwood Magnolia / Enervest SCOOP / STACK EP Energy / Carrizo Sundance / Pioneer Venado / COG Permian Basin

(3)

29

slide-30
SLIDE 30

WRD Perpetual Convertible Preferred Equity Summary

Issuer

  • WildHorse Resource Development Corporation (NYSE: WRD)

Purchaser

  • The Carlyle Group, through its U.S. buyout fund Carlyle Partners VI

Size

  • $450.4 million (as of April 30, 2018)

Date of Original Issue

  • June 30, 2017

Security

  • Series A Perpetual Convertible Preferred Stock

Maturity

  • Perpetual

Conversion Premium / Price

  • Conversion Price of $13.90 per share based on a 20% premium to WRD’s 30-day VWAP per share; WRD’s 30-day VWAP represents $11.58 per

share as of May 10, 2017 Total Conversion Shares

  • 32,402,059 fully converted shares based on a Conversion Price of $13.90 per share (as of April 30, 2018)

Dividend

  • 6.0% annually payable quarterly in arrears in-kind by addition to the liquidation preference, cash or a combination thereof at WRD’s sole election.
  • After 2.5 years if the stock price is equal to or greater than 130% of the Conversion Price, or $18.07, for 25 consecutive trading days dividends

terminate permanently Conversion Rights

  • Issuer: After four years, if the stock price is equal to or greater than 140% of the Conversion Price, or $19.46, for 20 consecutive trading days
  • Holder: At Conversion Price of $13.90 after one year

Financial Covenants

  • No financial covenants

Ranking / Capital Structure

  • Mezzanine equity; junior to all indebtedness and senior to common stock

Voting Rights / Governance

  • Votes on an as converted basis; The Carlyle Group nominates two directors to the WRD Board

30

slide-31
SLIDE 31

NGP and Management(1) WildHorse Resource Development Corporation NYSE: WRD Operating Subsidiaries

56.1%(2) 24.2%(2) 3.3%(2) 16.4%(2) 100%

Public Stockholders The Carlyle Group

$450MM Series A Perpetual Convertible Preferred Stock

KKR

WRD Ownership Chart

1. NGP and Management includes WHR Holdings, LLC; Esquisto Holdings, LLC; WHE AcqCo Holdings, LLC; NGP XI US Holdings, LP ,Management and WRD LTIP shares. 2. Based on common shares outstanding and Series A Perpetual Convertible Preferred Stock as of 3/31/18. 3. As of May 1, 2018 assuming share price of $25.92 per share; Includes Series A Perpetual Convertible Preferred Stock based and common shares outstanding as of 3/31/18.

31

Fully Diluted Equity Ownership Pro Forma (2) % Shares Series A Perpetual Convertible Preferred (Carlyle) 24.2% 32,402,059 KKR 3.3% 4,365,210 NGP + Management 56.1% 74,969,507 Public 16.4% 21,943,159

Company Shares Breakout Total Common Shares Outstanding 101,277,876 Total Common Shares Fully Diluted for Carlyle Conversion 133,679,935 Market Capitalization (3) $3,076

slide-32
SLIDE 32

Crude Oil and Natural Gas Hedge Summary

1. Using the midpoint for collars.

32

Q2 - Q4 2018 2019 2020 Gas Hedge Contracts: Swap contracts: Volume (BBtu) 6,730 6,425 4,846 Volume (MMBtu/d) 24,474 17,603 13,240 Weighted-average fixed price $2.79 $2.79 $2.76 Total Gas Hedge Contracts: Total gas volumes hedged (BBtu) 6,730 6,425 4,846 Total gas volumes hedged (MMBtu/d) 24,474 17,603 13,240 Total Weighted-Average Price Total weighted-average price (1) $2.79 $2.79 $2.76 Gas Hedge Summary Oil Hedge Summary Q2 - Q4 2018 2019 2020 Crude Oil Hedge Contracts: Swap contracts: Volume (MBbl) 4,765 6,652 4,512 Volume (Bbl/d) 17,326 18,226 12,327 Weighted-average fixed price $52.39 $54.45 $53.49 Collar contracts: Volume (MBbl) 12 – – Volume (Bbl/d) 44 – – Weighted-average floor price $50.00 – – Weighted-average ceiling price $62.10 – – Put options (bought): Volume (MBbl) 2,119 1,750 – Volume (Bbl/d) 7,705 4,794 – Weighted-average floor price $50.72 $53.83 – Weighted-average put premium ($3.56) ($5.43) – Total Crude Oil Hedge Contracts (Swaps, Collars, Puts): Total crude oil volumes hedged (MBbl) 6,896 8,402 4,512 Total crude oil volumes hedged (Bbl/d) 25,075 23,020 12,327 Total Weighted-Average Price Total weighted-average price (including puts) (1) $51.88 $54.32 $53.49 WTI-LLS Oil Basis Hedges Volumes hedged (MBbl) 4,763 Volumes Hedged (Bbl/d) 17,320 Weighted-average price ($/Bbl) $3.03

slide-33
SLIDE 33

Oil Natural Gas NGLs Total % Oil PV-10 (MBbl) (MMcf) (MBbl) (MBoe) (%) ($M) PDP 61,393 57,720 12,093 83,106 74% $1,232,999 PDNP 3,099 455 46 3,221 96% $31,448 PUD 217,146 223,019 44,997 299,313 73% $1,944,346 Total Proved 281,638 281,194 57,136 385,640 73% $3,208,793

Y-O-Y Growth 225% 523% 448% 268% 412%

Probable 270,860 263,450 54,256 369,024 73% $1,674,217 2P Reserves 552,498 544,644 111,392 754,664 73%

Y-O-Y Growth 188% 549% 425% 233%

Possible 547,067 362,080 87,954 695,368 79% $3,039,475 3P Reserves 1,099,565 906,724 199,346 1,450,031 76%

Y-O-Y Growth 160% 454% 360% 193%

Oil Natural Gas NGLs Total % Oil PV-10 (MBbl) (MMcf) (MBbl) (MBoe) (%) ($M) PDP 18,099 19,206 3,220 24,520 74% $289,013 PDNP 734 324 90 878 84% $15,058 PUD 67,887 25,594 7,109 79,262 86% $322,328 Total Proved 86,720 45,124 10,419 104,660 83% $626,398 Probable 104,874 38,844 10,790 122,138 86% $316,608 2P Reserves 191,594 83,967 21,209 226,798 84% Possible 231,933 79,736 22,149 267,371 87% $662,892 3P Reserves 423,527 163,703 43,358 494,169 86%

WildHorse Resource Development CG&A Reserve Detail (1)

December 31, 2016(2) 33

1. Based on SEC pricing of $51.34 per barrel and $2.98 per mmbtu as of December 31, 2017, and $42.75 per barrel and $2.48 per mmbtu as of December 31, 2016. 2. Pro-forma for the North Louisiana divestiture closed on March 29, 2018 3. See slides 35 - 36 for cautionary statements and additional disclosures regarding PV-10 and 3P reserves.

December 31, 2017(2)

(3) (3)

slide-34
SLIDE 34

Reconciliation of Adjusted EBITDAX

34

This presentation and accompanying schedules include the non-GAAP financial measure Adjusted EBITDAX. The accompanying schedule provides a reconciliation of the non-GAAP financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP. WRD's non-GAAP financial measures should not be considered as alternatives to GAAP measures such as Net Income, operating income, net cash flows provided by operating activities or any other measure of financial performance calculated and presented in accordance with GAAP. WRD's non-GAAP financial measures may not be comparable to similarly-titled measures of other companies because they may not calculate such measures in the same manner as WRD does. Adjusted EBITDAX is a non-GAAP financial measure. We evaluate performance based on Adjusted EBITDAX. Adjusted EBITDAX is defined as net income (loss), plus interest expense; debt extinguishment costs; income tax expense; depreciation, depletion and amortization; impairment of goodwill and long-lived properties; accretion of asset retirement obligations; losses on commodity derivative contracts and cash settlements received; losses on sale of properties; stock-based compensation; incentive-based compensation expenses; exploration costs; transaction related costs; IPO related expenses; the North Louisiana settlement, and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and cash settlements paid; gains on sale of assets and other non-routine items. The following table presents WRD’s fourth quarter of 2018 and 2017 EBITDAX to the most comparable measure calculated in accordance with GAAP:

For the Three Months Ended March 31, (Amounts in $000s) 2018 2017 Net Income (Loss) (115,774) $ 20,252 $ Add (Deduct): Interest expense, net 13,307 5,571 Income tax (benefit) expense (38,093) 11,700 Depreciation, depletion and amortization 59,883 26,443 Impairment of NLA disposal group 214,274

  • Exploration expense

1,708 1,615 (Gain) loss on derivative instruments 40,370 (31,291) Cash settlements received / (paid) on commodity derivatives (20,546) (983) Stock-based compensation 3,156 495 Acquisition related costs 359 599 Debt Extinguishment costs

  • (11)

Initial public offering costs

  • 182

Gain (loss) on sale of properties

  • Adjusted EBITDAX

158,644 $ 34,572 $

slide-35
SLIDE 35

Cautionary Statements and Additional Disclosures

This presentation has been prepared by WildHorse and includes market data and other statistical information from sources believed by WildHorse to be reliable, including independent industry publications, government publications or other published independent sources. Some data is also based on WildHorse’s good faith estimates, which are derived from its review of internal sources as well as the independent sources described herein. Although WildHorse believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy and completeness. PV-10 and 3P Reserves PV-10 is a non-GAAP financial measure and represents the period-end present value of estimated future cash inflows from WRD’s natural gas and crude oil reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using SEC pricing assumptions in effect at the end of the

  • period. SEC pricing for oil and natural gas of $51.34 per Bbl and $2.98 per MMBtu; $42.75 per Bbl and $2.48 per MMBtu; and $50.28 per Bbl and $2.59 MMBtu was based
  • n the unweighted average of the first-day-of-the-month prices for each of the twelve months preceding December 2017, December 2016, and December 2015, respectively.

PV-10 differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes. Moreover, GAAP does not provide a measure of estimated future net cash flows for reserves other than proved reserves. Because PV-10 estimates of probable and possible reserves are more uncertain than PV-10 and standardized estimates of proved reserves, but have not been adjusted for risk due to that uncertainty, they may not be comparable with each other. Nonetheless, WRD believes that PV-10 estimates for reserve categories other than proved present useful information for investors about the future net cash flows of its reserves in the absence of a comparable GAAP measure such as standardized measure. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from reserves on a more comparable basis. WRD includes a full reconciliation of proved PV-10 as of December 31, 2017 to standardized measure in its Form 10-K for the year ended December 31, 2017. In addition, the following table provides a reconciliation of the PV-10 of our Eagle Ford proved reserves to the Standardized measure of discounted future net cash flow for the period presented: Neither PV-10 nor standardized measure represents an estimate of fair market value of WRD’s natural gas and oil properties. WRD and others in the industry use PV-10 as a measure to compare the relative size and value of estimated reserves held by companies without regard to the specific tax characteristics of such entities. The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserve estimates (collectively, “3P”). WildHorse has provided estimates for proved, probable and possible reserves within this presentation in accordance with SEC guidelines and definitions. The estimates for proved, probable and possible reserves as of December 31, 2017 have been prepared by WildHorse’s internal reserve engineers and audited by Cawley, Gillespie & Associates, Inc. (“CGA”), WildHorse’s independent reserve engineers.

35

slide-36
SLIDE 36

Cautionary Statements and Additional Disclosures

WRD has provided summations of its proved, probable and possible reserves and summations of its PV-10 for its proved, probable and possible reserves in this presentation. The SEC strictly prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. Investors should be cautioned that estimates of PV-10 of probable reserves, as well as the underlying volumetric estimates, are inherently more uncertain

  • f being recovered and realized than comparable measures for proved reserves, and that the uncertainty for possible reserves is even more significant. Further, because

estimates of probable and possible reserve volumes have not been adjusted for risk due to this uncertainty of recovery, their summation may be of limited use. Actual quantities that may be ultimately recovered from WildHorse’s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of WildHorse’s ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates. “EUR” or “Estimated Ultimate Recovery,” when referring to a currently producing well, refers to the sum of total gross remaining proved reserves attributable to each location in WildHorse’s reserve report and cumulative sales from such location. EUR is shown on a combined basis for oil/condensates, gas and NGLs after the effects of processing. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineers Petroleum Resource Management System or the SEC’s rules. Management Locations WRD has disclosed a total of 3,207 net horizontal drilling locations in this presentation in the proved, probable, and possible categories as audited by CG&A, WRD’s third party engineers, as well as locations that have been identified by WRD’s management. WRD identified those additional locations using the same methodology as those locations to which probable and possible reserves are attributed—by using existing geologic and engineering data from vertical production and seismic data. Of WRD’s 3,207 net horizontal drilling locations, 2,761 lie within the geographic areas to which proved, probable and possible reserves are attributed by CG&A. The remaining 446 management identified net horizontal drilling locations are within geographic areas to which proved, probable or possible reserves are not attributed, but nonetheless are locations that WRD has specifically identified based on its evaluation of applicable geologic and engineering data accrued over our multi-year historical drilling activities in the surrounding area. The locations have been identified by WRD’s management based on its evaluation of applicable geologic and engineering data from historical drilling activities in the surrounding area. The locations on which WRD actually drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors, and may differ from the locations currently identified.

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Net Locations June 30,

  • Dec. 31,

June 30,

  • Dec. 31,

June 30,

  • Dec. 31,

2017 2017 2017 2017 2017 2017 Eagle Ford 1,343 2,708 1,296 445 2,639 3,154 Austin Chalk 12 53 12 53 Total Locations 1,355 2,761 1,296 446 2,651 3,207 Management Total Locations Locations WRD Locations CG&A

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SLIDE 37

Cautionary Statements and Additional Disclosures

Cash General and Administrative Expenses Our presentation of cash general and administrative ("G&A") expenses is a non-GAAP measure. We define cash G&A as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, and we may express it on a per Boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to

  • ther similarly titled measures of other companies.

Calculation of Net Debt Net Debt is a supplemental non-GAAP financial measure that is used by external users of WRD’s financial statements. We define Net Debt as total debt minus cash and cash

  • equivalents. We believe Net Debt is useful to investors because it provides readers with a more meaningful measure of our outstanding indebtedness. However, this measure is

provided in addition to, not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP. Calculation of Return on Capital Employed (“ROCE”) Simmons Equity Research calculates ROCE (on a pre-tax basis) as adjusted Earnings Before Interest and Taxes (“EBIT”) divided by adjusted capital employed. Adjusted EBIT excludes impairments, unrealized hedging, exploration expense, dry hole expense, asset retirement obligations (“ARO”) and any gains or losses on divestitures (if included in revenues). Adjusted capital employed equals adjusted equity plus debt, preferred stock and minority interest. Adjusted equity utilizes 2009 shareholder’s equity and adds the following items on a rolling basis: impairments, unrealized hedging, exploration expense, dry hole expense and ARO expense. Drill-Bit Finding and Development (“F&D”) Cost Calculation Drill-bit F&D cost is an indicator used to assist in the evaluation of the historical cost of adding proved reserves on a per Boe basis. Consistent with industry practice, future capital cost to develop proved undeveloped reserves are not included in costs incurred. Drill-bit F&D costs are calculated as D&C capital expenditures, including facilities and capital workovers, divided by reserve additions from extensions, discoveries, additions and performance revisions.

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Cost incurred ($'s in millions): Eagle Ford North Louisiana Total WRD 2017 D&C capex including facilities $701.7 $86.1 $787.8 and capital workovers Reserve additions (Mboe): Extensions, discoveries and additions 142.2 20.3 162.5 Performance revisions 72.0 0.2 72.2 Total additions 214.2 20.5 234.7 Total Drill-bit F&D costs ($/boe) $3.28 $4.20 $3.36

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SLIDE 38

Cautionary Statements and Additional Disclosures

GP&T Revenue Recognition Reconciliation – First Quarter 2018 The table below reconciles gathering, processing and transportation (“GP&T”) expense to the reporting convention prior to the implementation of the new FASB revenue recognition standard on January 1, 2018 (ASC 606, Revenue from Contracts with Customers). For additional information on the GP&T reconciliation and the new revenue recognition standard, see the Management’s Discussion & Analysis section of WRD’s 10-Q filing to be filed on or before May 15, 2018.

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Prior Reporting Variance New FASB Revenue Recognition Standard Guidance (prior reporting} Revenues: Gas revenue $28,435 ($805) $27,630 NGL revenue $9,413 ($1,965) $7,448 Other Income $1,166 $134 $1,300 Natural gas price realization (% of Henry Hub) 108%

  • 3%

105% 90% - 94% NGL price realization (% of WTI) 35%

  • 8%

27% 33% - 37% Operating expenses: Lease operating expenses $16,433 ($6) $16,427 GP&T expense $4,103 ($2,751) $1,352 Depreciation, depletion, and amortization $60,016 ($133) $59,883 Other operating (income) expense $518 $140 $658 GP&T per boe $0.87 ($0.58) $0.29 $1.10 - $1.40