Company Presentation

October 2, 2017

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

2

I. Company Overview

3

WRD Has Built a Premier Platform for Growth

Note: Q2 2017 daily production excludes assets acquired from Anadarko Petroleum Corporation and affiliates of KKR (“Acquisition”); drilling locations pro forma for Acquisition. 1. Includes acreage that WildHorse has the right to lease within the Terryville Complex. 2. Reserve data as of December 31, 2016; includes 22.9 MMBoe in PDP reserves from Acquisition (audited proved reserves not currently available). 12/31/16 reserve report audited by Cawley, Gillespie & Associates (“CGA”). 3. See slides 28 and 29 for assumptions embedded in WildHorse IRR calculations. IRR based on consensus Pricing as of 8/2/17 4. 2017E growth rates based on 2016 production pro forma for Clayton Williams acquisition. 5. Eagle Ford wells drilled and completed as of June 30, 2017, excluding six wells with not enough production data to estimate an EUR. 6. Q2’17 annualized EBITDAX pro forma for Acquisition.

Red: 80

Green: 0

Blue: 0

Red: 0

Green: 60

Blue: 113

Red: 191

Green: 191

Blue: 191

Red: 128

Green: 205

Blue: 237

Red: 17

Green: 143

Blue: 255

Red: 255

Green: 212

Blue: 212

Red: 255

Green: 232

Blue: 167

Red: 191

Green: 191

Blue: 191

Red: 167

Green: 207

Blue: 157

Red: 176

Green: 218

Blue: 255

Premier Acreage Positions in the Eagle Ford and North Louisiana

TX

OK

AR

MS

LA

Second largest Eagle Ford position in the

industry

In and around the prolific Terryville

Complex

4

2nd Largest Eagle Ford Position: ~385,000 net acres in largely contiguous block which drives efficient development

Deep Eagle Ford Inventory: ~2,000 net locations of 91 boe/ft

Eagle Ford type curve (>30 years of inventory at current pace)

Robust Production Growth: 61% in 2017E (4) and 83% in 2018E based on updated analyst estimates

Outperforming Eagle Ford Type Curve: 41 Gen 3 wells averaging

101 boe/ft (5), 11% above our 91 boe/ft Eagle Ford type curve Conservative Balance Sheet: Net Debt / Q2’17 PF annualized

EBITDAX of 1.8x (6)

Attractive Hedging Profile: 75% of 2H’17 production hedged with additional hedges in 2018-2020

Significant Management Ownership: Management team is highly

aligned with shareholders

Catalysts Ahead: Additional Gen 3 wells, testing Gen 4 design, further evaluation of the Austin Chalk, refracs and testing two Eagle Ford landing zones

Attractive Valuation: Meaningful valuation discount to peers on 2017 and 2018 EV/EBITDAX

Key Investor Considerations

Total Company

Net Acres(1) ~484,000

Proved Reserves (MMboe)(2) 175.4

% Liquids 68% % Oil 59%Q2 2017 Production (Mboe/d) 22.6 % Liquids 65%Drilling Locations: Gross 5,829 Net 3,299

Eagle Ford

Net Acres ~385,000Proved Reserves (MMboe)

(2) 127.6 % Liquids 92% % Oil 81%Q2 2017 Production (Mboe/d) 16.1 % Liquids 90%Drilling Locations: Gross 4,416 Net 2,651

Single-well IRR (3) 46%

North Louisiana

Net Acres(1) ~99,000

Proved Reserves (Bcfe)(2) 286.8

% Gas 98%Q2 2017 Production (MMcfe/d) 39.1 % Gas 96%Drilling Locations: Gross 1,413 Net 648

Single-well IRR (3) 61%

Brought online first Austin Chalk well in Washington County, the Winkelmann #1H, at an IP-30 of 2,387 boe/d (26% oil, 38% natural gas, and 36% natural gas liquids)

Given the success of this well, WRD plans further delineation and testing of its Austin Chalk position East Texas position includes 285,000 net acres with legacy Austin Chalk wells and an additional 100,000 net acres of

undeveloped Austin Chalk

Successful Austin Chalk Well

Q2 2017 and Recent Activity

Increased average daily production by 55% to 22.6 Mboe/d for the second quarter 2017 compared to 14.6 Mboe/d for the second quarter 2016

Reported adjusted EBITDAX of $52.4 million for the second quarter 2017 compared to $21.7 million for the second quarter 2016 Closed financing of $435 million Series A Perpetual Convertible Preferred Stock Increased borrowing base on WRD’s credit facility to $650 million from $450 million

41 gross Gen 3 wells online averaging a 101 boe per foot EUR (1), which is 11% above the current 91 boe per foot type curve 10 gross wells online on the Clayton Williams acquisition acreage with the average of the wells exceeding a 91 boe per foot type curve Brought online 3 gross wells on acreage without assigned locations Brought online 6 gross wells adjacent to the Acquisition acreage with the average of the wells exceeding a 91 boe per foot type curve

Acquired ~111,000 net acres and 7.6 Mboe/d (Q4’16) of net production from Anadarko Petroleum and affiliates of KKR for $594 million

Acquisition closed June 30, 2017 Post acquisition, WRD operates the second largest Eagle Ford position with ~385,000 net acres Acquisition added 711 net locations in the Eagle Ford 91 Boe/ft type curve area with attractive single-well IRRs of 46% (4)

Highlights

Continued Eagle Ford Gen 3 Outperformance

Eagle Ford Acquisition

Red: 80

Green: 0

Blue: 0

Red: 0

Green: 60

Blue: 113

Red: 191

Green: 191

Blue: 191

Red: 128

Green: 205

Blue: 237

Red: 17

Green: 143

Blue: 255

Red: 255

Green: 212

Blue: 212

Red: 255

Green: 232

Blue: 167

Red: 191

Green: 191

Blue: 191

Red: 167

Green: 207

Blue: 157

Red: 176

Green: 218

Blue: 255

Strong leadership through veteran Memorial / NGP team with credible track record Premier operational expertise developing the Eagle Ford and Terryville Complex

• Successful track record of acquiring, developing, and monetizing assets throughout the Eagle Ford / North Louisiana

5

1. Eagle Ford wells drilled and completed as of June 30, 2017, excluding six wells with not enough data to estimate an EUR. 2. Q2’17 annualized EBITDAX pro forma for Acquisition. 3. WRD hedging as of August 4, 2017; Peer group hedging based on most recently available public information. 4. See slide 28 for assumptions embedded in Eagle Ford IRR calculation. IRR based on Consensus Pricing as of 8/2/17: $51.16 / $3.16 for 2017, $54.90 / $3.14 for 2018, $58.00 / $3.05 for 2019, $62.50 / $3.24 for 2020,

$66.50 / $3.40 for 2021 and thereafter for WTI and Henry Hub, respectively.

Net debt / Q2’17 annualized EBITDAX of 1.8x (2)

$517 million of liquidity at June 30, 2017 73% of consensus 2H’17 production hedged (peer group at 54%) (3)

43% of consensus 2018 production hedged (peer group at 32%) (3) 6.5 MMboe of production hedged in 2019-2020

Strong Balance Sheet and Hedging Program

103

145

147

167

180

190

213

252

270

356

385

528

Carrizo

Marathon

Murphy Oil

SM Energy

Apache

BP

ConocoPhillips

BHP Billiton

Chesapeake

Sanchez Energy

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 7/31/2017.

WRD Operates the Second Largest Eagle Ford Position

TX LA

AR OK

NM

0 80

Miles

Oil

Wet Gas/Condensate

Dry Gas

Eagle Ford Shale

Hawkwood

Apache

6

1,996 1,996

655

493

155

2,651

648

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Eagle FordEUR (91 Boe/ft)

Other RCT Other TotalLocations

Net Locations(1)

1,910

2,336 2,350 2,350

219

591 646 648

2,129

2,927 2,996 2,998

0

500

1,000

1,500

2,000

2,500

3,000

3,500

$35.00 / $2.00 $45.00 / $2.50 $55.00 / $3.00 $65.00 / $3.50

Eagle Ford North Louisiana

Net Locations

Deep Inventory of Economic Locations

1. As of May 11, 2017, we identified 3,299 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 3,299 estimated drilling locations, 201, 342 and 1,156 are associated with proved, probable and possible reserves as of December 31, 2016. Accordingly, 1,599 of these locations do not have any reserves assigned to them which includes 949 locations associated with the Acquisition. 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.

Net Horizontal Locations by Area Inventory Breakevens (10% Pre-tax IRR)

Multiple decades of drilling inventory across Eagle Ford and North Louisiana based

on net locations(1)

3,299 Net Locations

Additional upside locations in:

~130,000 Eagle Ford net acres with no locations assigned – actively delineating

Austin Chalk in Burleson County; Buda, Woodbine, Georgetown and Pecan Gap across much of our Eagle Ford acreage

Testing a stack/stagger development of the Upper and Lower Eagle Ford

Eagle Ford North Louisiana

Eagle Ford Locations

North Louisiana Locations

7

Leading Industry Metrics at a Compelling Valuation

8

Enterprise Value / EBITDAX

Note: Enterprise value based on closing stock price as of August 3, 2017; Peer group includes:CPE, CRZO, EGN, LPI, MTDR, OAS, PDCE, PE, QEP, RSPP, SM, SN, SRCI, WPX AND XOG. Based on FactSet consensus estimates as of August 3, 2017. 1. 2017E growth rates based on 2016 production pro forma for Clayton Williams acquisition. 2. Both WRD and peer group production based on consensus estimates as of August 3, 2017. WRD hedging as of August 4, 2017; Peer group hedging based on most recently available public information.

Production Growth EBITDAX Growth

YE Net Debt / EBITDAX % Hedged – Total Production (2) % Hedged – Oil Production (2)

61%

83%

48%

33%

0%

20%

40%

60%

80%

100%

2017E Growth Rate 2018E Growth Rate

WRD Peer Group

172%

106%

64%

44%

0%

40%

80%

120%

160%

200%

2017E Growth Rate 2018E Growth RateWRD Peer Group(1)

2.2x

1.3x

2.7x

2.2x

0.0

1.0

2.0

3.0

2017E 2018E

WRD Peer Group

79%

56%59%

31%

0%

20%

40%

60%

80%

100%

Rem. 2017 2018WRD Peer Group

73%

43%

54%

32%

0%

40%

80%

Rem. 2017 2018WRD Peer Group

7.4x

3.5x

8.1x

5.7x

0.0

2.0

4.0

6.0

8.0

10.0

EV/2017E EBITDAX EV/2018E EBITDAXWRD Peer Group

Top Tier Debt-Adjusted Production Growth and EBITDAX Margin

9

Debt-Adjusted Production Growth 2016-2018E (1)

2017E EBITDAX Margin (2)

1. Source: Raymond James Equity Research. 2016 – 2018E Debt Adjusted Production is defined as a two year CAGR of total production normalized by a debt adjusted share count, whereby long term debt is translated into an equivalent number of common shares assuming the current share price. Chart data as of May 2017.

2. 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). Chart data as of August 2017.

71%

47%42% 40%31% 31%

26% 26% 23% 21% 20% 20% 19% 17% 17% 15%14% 13%10% 7% 6% 5% 3% 3% 1% 0%(0%)(0%)(1%)(2%)(3%)(7%)

(13%)(17%)(18%)

(30%)

(15%)

0%

15%

30%

45%

60%

75%

90%SR

CI

RSP

P

FAN

G PE

WR

D

LPI

OA

S

WPX

CX

O

PXD

EG

N

MT

DR

CN

X

EO

G

CL

R

XE

C

CO

G

AR

APA

RR

C

MR

O

CR

ZO

OX

Y

NFX

HE

S

CH

K

DV

N

WL

L

MU

R

QE

P

APC

NB

L

SWN

SM

NO

G

75% 74% 71% 71%65% 64% 62% 61% 60% 59% 58% 57% 55% 54% 53%

52% 49% 48% 45%

0%

15%

30%

45%

60%

75%

90%

CLR WRD SM RSPP GPOR COG EOG OAS DVN EPE NFX APC WLL SWN WPX RRC ECR AR CHK

II. Eagle Ford Overview

10

0

20,000

40,000

60,000

80,000

100,000

0 30 60 90 120 150 180

0 20

Miles

WRD Gen 3 wells continue to outperform 91 Boe/ft type curve across the acreage position

• 41 gross Gen 3 wells online averaging a 101 boe per foot EUR (1)

Current Eagle Ford producing wells exist across entire ~800 square mile area

10 gross wells online on the Clayton Williams acquisition acreage with the average of the wells exceeding a 91 boe per foot type curve (2)

Brought online 6 gross wells adjacent to the Acquisition acreage with the average of the wells exceeding a 91 boe per foot type curve

Gen 3 Completions Outperforming Type Curve (6 Mo Cum)(4)

1. Eagle Ford wells drilled and completed as of June 30, 2017, excluding six wells with not enough data to estimate an EUR. 2. Excludes three wells with not enough data to estimate an EUR. 3. 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. 4. The first day of the peak IP30 rate is considered day 1 of cumulative production. Data is normalized for 6,500’ laterals, downtime, and irregular production. Excludes three wells with not enough production history. 5. Represents ~130,000 net acres with no locations assigned – actively delineating. 6. See slide 28 for assumptions embedded in Eagle Ford IRR calculation. IRR based on Consensus Pricing as of 8/2/17: $51.16 / $3.16 for 2017, $54.90 / $3.14 for 2018, $58.00 / $3.05 for 2019, $62.50 / $3.24 for 2020, $66.50 / $3.40 for 2021 and thereafter for WTI and Henry

Hub, respectively.

Red: 80

Green: 0

Blue: 0

Red: 0

Green: 60

Blue: 113

Red: 191

Green: 191

Blue: 191

Red: 128

Green: 205

Blue: 237

Red: 17

Green: 143

Blue: 255

Red: 255

Green: 212

Blue: 212

Red: 255

Green: 232

Blue: 167

Red: 191

Green: 191

Blue: 191

Red: 167

Green: 207

Blue: 157

Red: 176

Green: 218

Blue: 255

Cum

ulat

ive

Prod

uctio

n (B

oe)

Recent Well Results Outperform and Delineate Extensive Acreage Position

IRR Sensitivity at Consensus Price Deck(6)

Horizontal Well Activity(3)

Candace #1H EUR: 138 Boe/Ft

IP30 = 1,081 BOE/D (88% oil) 7,481’ LL (9/2/16)

Mach A #2H EUR: 111 Boe/Ft

IP30 = 607 BOE/D (64% oil) 6,672’ LL (2/22/17)

Altimore #1H EUR: 126 Boe/Ft

IP30 = 1,048 BOE/D (84% oil) 6,435’ LL (3/31/2017)

Belmont Stakes #1H EUR: 135 Boe/Ft

IP30 = 740 BOE/D (65% oil) 5,831’ LL (10/1/16)

91 Boe/ft Type Curve

Gen 3 Avg Boe Cum (41 wells)

11

Days

Chmelar South #1H EUR: 130+ Boe/Ft

IP30 = 1,011 BOE/D (92% oil) 6,915’ LL (5/22/17)

Goodnight #3H EUR: 120+ Boe/Ft

IP30 = 724 BOE/D (93% oil) 5,833’ LL (5/28/17)

Farmer’s North #1H IP30 = 682 BOE/D (94% oil)

6,463’ LL (6/18/17) Drilled on WRD acreage

w/o assigned locations

Cooper B #1H EUR: 107 Boe/Ft

IP30 = 576 BOE/D (85% oil) 4,780’ LL (2/22/17)

Winkelmann #1H (Austin Chalk) IP30 = 2,387 BOE/D (26% oil)

4,762’ LL (6/3/17)

Additional WRD Acreage(5) WRD Acreage with Locations WildHorse Legacy EF HZ Well

EUR (Boe / Ft)

91 100 110 120 130 140

46% 56% 70% 84% 100% 120%

Completion Evolution Has Led to Superior Well Performance and Increased Returns

Increased Intensity Has Improved EURs (EUR / 1,000 ft) (1) IRR Sensitivity (2)

76 81

101

0

20

40

60

80

100

120

Gen 1 Gen 2 Gen 3

MBoe

15 41

1,500 2,600 3,700

7

Wells Completed Target Proppant (lbs/ft)

Red: 80

Green: 0

Blue: 0

Red: 0

Green: 60

Blue: 113

Red: 191

Green: 191

Blue: 191

Red: 128

Green: 205

Blue: 237

Red: 17

Green: 143

Blue: 255

Red: 255

Green: 212

Blue: 212

Red: 255

Green: 232

Blue: 167

Red: 191

Green: 191

Blue: 191

Red: 167

Green: 207

Blue: 157

Red: 176

Green: 218

Blue: 255

1. Eagle Ford wells drilled and completed as of June 30, 2017, excluding six wells with not enough data to estimate an EUR. 2. IRR sensitivities assume $3.00 Henry Hub for the life of the well.

12

Period 2014 – 1Q15 2Q15 – 4Q15 2016 – present Testing

Target Proppant Loading (lbs/ft) 1,500 2,600 3,700 4,000 – 5,000

Fluid Type Hybrid Gel Slickwater Slickwater Slickwater

Stage Spacing 200’ 200’ 150’ 100’ – 150’

Clusters per Stage 5 7 9 6 - 9

WRD Eagle Ford Completion Design Evolution

Generation 1 Generation 2 Generation 3 Generation 4

• Gen 3 completion designs coupled with restricted choke management have increased EURs • Currently testing Gen 4 – have not reached the limits of completion optimization

EUR / Ft Oil Price

(BOE) % $40.00 $45.00 $50.00 $55.00 $60.00

91 0% 19% 27% 37% 47% 59%

100 10% 25% 35% 46% 59% 72%

110 21% 32% 45% 59% 74% 93%

120 32% 41% 55% 72% 92% 114%

130 43% 49% 67% 88% 111% 140%

140 54% 60% 80% 105% 134% 172%

EU

R I

mpr

ovem

ent

Source: Corporate Filings and Company Data. 1. Differentials based on average realized $/Bbl for the three months ended 6/30/17. Companies included in Permian: FANG, LPI, RSPP, CXO; Companies included in Eagle Ford: CRZO, SN;

Companies included in DJ Basin: PDCE and SRC (XOG excluded due to timing of earning release); Companies included in Bakken: CLR, WLL; Companies included in SCOOP / STACK: NFX.

Proximity to Gulf Coast Leads to Advantaged Oil Pricing

Comparative Basin Differentials (1)

WTI Cushing # Basin

Differential

U.S. Shale Basins

Permian Basin

DJ Basin

Bakken

South Texas Eagle Ford

WRD Eagle Ford

($3.74)

($4.59)

($7.14)

($1.36)

SCOOP / STACK

($5.63)

($2.87)

Red: 80

Green: 0

Blue: 0

Red: 0

Green: 60

Blue: 113

Red: 191

Green: 191

Blue: 191

Red: 128

Green: 205

Blue: 237

Red: 17

Green: 143

Blue: 255

Red: 255

Green: 212

Blue: 212

Red: 255

Green: 232

Blue: 167

Red: 191

Green: 191

Blue: 191

Red: 167

Green: 207

Blue: 157

Red: 176

Green: 218

Blue: 255

WildHorse 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

Sufficient pipeline take-away capacity decreases risk of midstream bottleneck

Potential upside to develop an integrated midstream system to service Eagle Ford assets

13

Eagle Ford Wells Outperform Competing Basins and Peers on Cash Margin

$33.17

$27.12

$21.54 $21.48 $21.34

$2.47

$2.13

$2.53 $1.54 $2.54

$3.99

$4.64

$6.28 $8.07

$2.10

$1.36

$3.28 $6.36

$1.55

$4.58

$7.16 $10.99 $11.43

$15.51 $17.61

$48.15 $48.15 $48.15 $48.15 $48.15

$0.00

$11.00

$22.00

$33.00

$44.00

$55.00

WRD Eagle Ford Permian Bakken Eagle Ford DJ Basin

$/Boe

Cash Margin: WRD Eagle Ford vs. Competing Basins(1) (2Q 2017)

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 Eagle Ford: CRZO and SN; Companies included in DJ Basin: PDCE and SRC (XOG excluded due to timing of earnings release);

Companies included in Bakken: CLR and WLL.

Cash Margin

Production &

Ad Valorem Taxes

LOE & GP&T

Differential

Commodity Mix

14

$48.15 Q2 2017 Average WTI Price

III. North Louisiana Overview

15

Athens

Weyerhaeuser

Lincoln

Union Claiborne

Bienville

Jackson

Ouachita

RCT

RRC Terryville

Field

Bear Creek

Athens

Weyerhaeuser

Horizontal Development Focus Area

Low Decline PDP Base with Horizontal Development Upside

North Louisiana Acreage Position

Contiguous Position in the Prolific Terryville Field ~99,000 net acres across four areas in

North Louisiana – Ruston-Choudrant-Tremont (“RCT”) Field, Weyerhaeuser, Bear Creek and Athens

• Geologically analogous to RRC’s Terryville Field

• Drilled 15 operated horizontal wells to date

• Management drilled 55 wells for MRD / RRC prior to turning over operation in January 2015

648 net (1,413 gross) locations in North Louisiana

• 493 net (946 gross) RCT drilling locations

• 127 net (410 gross) Weyerhaeuser drilling locations

• ~61% IRRs for RCT Upper Red(2)

Q2 2017 net production of 39.1 MMcfe/d

• 96% natural gas

High realized pricing given proximity to Henry Hub

Wholly-owned midstream subsidiary enhances single-well economics

Currently operating two rigs

Horizontal Well Activity(1)

Spillers 18-7 HC-1 (WRD) IP30 = 19.4 MMcfe/d (98% gas)

8,884’ LL (3/26/15)

Ates 18 7 HC-1 (WRD) IP30 = 16.0 MMcfe/d (98% gas)

6,705’ LL (9/7/15)

Taylor 13-12 H-1 (WRD) IP30 = 21.8 MMcfe/d (98% gas)

6,796’ LL (12/11/14)

Davison 16-9 HC 2 (MRD) IP30 = 27.3 MMcfe/d (78% gas)

6,116’ LL (12/15/14)

DL Sanford 18-7 HC 1 (MRD) IP30 = 31.1 MMcfe/d (79% gas)

7,010’ LL (8/9/14)

Dowling 27 34 HC-1 (MRD) IP30 = 33.7 MMcfe/d (81% gas)

7,620’ LL (6/6/15)

Dowling 19-30-HC 1 (MRD) IP30 = 29.4 MMcfe/d (81% gas)

6,624’ LL (6/23/14)

Bellevue Timber 16-9 HC-1 (MRD) IP30 = 36.4 MMCFE/D (79% gas)

6,481’ LL (4/29/15)

Wright 13-24 HC 3 (MRD) IP30 = 30.4 MMcfe/d (83% gas)

6,606’ LL (12/30/13)

Colvin Estate 28-33 HC 1 (MRD) IP30 = 30.4 MMcfe/d (82% gas)

8,104’ LL (4/20/14)

Hearne 33-4 HC 4 (MRD) IP30 = 28.3 MMcfe/d (86% gas)

7,597’ LL (10/28/14)

TL McCrary 14-23-26 HC-2 (MRD) IP30 = 24.6 MMcfe/d (81% gas)

7,010’ LL (6/22/14)

Werner 29-32-5 HC-2 (MRD) IP30 = 28.4 Mmcfe/d (82% gas)

8,300’ LL (2/28/14)

Dowling 19-30-HC 2 (MRD) IP30 = 31.9 MMcfe/d (81% gas)

6,624’ LL (7/21/14)

Lewis 21-28 HC #2 (MRD) IP30 = 26.5 MMcfe/d (85% gas)

7,752’ LL (6/4/15)

Williams 11-12H (Nadel & Gussman) IP30 = 14.0 MMcfe/d (95% gas)

4,419’ LL (5/20/15)

Temple 8-5 HC-3 (MRD) IP30 = 27.4 MMcf/d (85% gas)

7,401’ LL (4/18/15)

Smelley 15-22 HC-1 (WRD) IP30 = 17.0 MMcfe/d (97% gas)

8,410’ LL (6/28/15)

Elliott 2-11 HC-1 (Linn/WRD) IP24hr = 22.3 Mmcfe/d (98% gas)

6,503’ LL (3/31/15)

Harrison 7 6 HC-1 (Nadel/WRD) IP24hr – 15.3 MMcfe/d

(98% gas) 4,245’ LL (7/30/16)

1. Source: Company data and estimates, MRD Investor Presentation, Louisiana Department of Natural Resources, and IHS Enerdeq. 2. See slide 29 for assumptions embedded in North Louisiana IRR calculations.

WildHorse Acreage RRC Terryville Field WildHorse Wells RRC Wells RRC Expansion Wells RRC Permit Fault Line

16

Harrison 7-18H 2-well Pad (WRD) RESTRICTED CHOKE

IP30 = 20.2 MMcfe/d (100% gas) 6,802’ Avg LL (5/10/17)

$2.09 $1.87

$1.66

$0.25

$0.09

$0.07

$0.52

$0.69

$0.14

$0.32

$0.96

$0.50 $0.31

$0.12 $0.41

$0.05

$3.30

$3.55

$3.19

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

WRD NLA Diversified Gas Marcellus

$/Mcfe

North Louisiana Wells Outperform Competing Basins and Peers on Cash Margin

Cash Margin: WRD North Louisiana vs. Competing Basins(1) (Second Quarter 2017)

Source: Company filings and investor presentations. Note: Assumes 6:1 gas to oil ratio. Commodity mix assumes NGLs at 35% of WTI. Due to commodity mix, company and basin Mcfe prices surpass the $3.14 second quarter 2017 average HHUB Price. Does not include G&A and other corporate level costs. 1. Companies included in Marcellus: RICE, EQT, AR, COG, RRC. Companies included in Diversified Gas: SWN, CHK. 2. Gathering, Processing, & Transportation fees exclude intercompany eliminations for non-wholly owned consolidated subsidiaries. 3. Includes GP&T expense.

Cash Margin

Production &

Ad Valorem Taxes

LOE

Gathering, Processing,

& Transportation(2)

Differential

$3.14 Q2 2017 Average HHUB Price

Commodity Mix

Red: 80

Green: 0

Blue: 0

Red: 0

Green: 60

Blue: 113

Red: 191

Green: 191

Blue: 191

Red: 128

Green: 205

Blue: 237

Red: 17

Green: 143

Blue: 255

Red: 255

Green: 212

Blue: 212

Red: 255

Green: 232

Blue: 167

Red: 191

Green: 191

Blue: 191

Red: 167

Green: 207

Blue: 157

Red: 176

Green: 218

Blue: 255

17

IV. Financial Overview

18

Strong Balance Sheet and Liquidity Position

Capitalization Strong Liquidity Position

1. Q2 2017 pro forma for Acquisition 2. Interest Coverage calculated as EBITDAX / Interest; Interest expense represents annualized Q2 2017 reported interest expense plus interest expense for $99 million of credit agreement borrowings used in the Acquisition 3. Credit metrics assume 100% equity treatment for the Series A Perpetual Convertible Preferred.

19

No Near Term Maturities

$0

$100

$200

$300

$400

$500

$600

$700

2017 2018 2019 2020 2021 2022 2023 2024 2025

$350MM 6.875% Senior Notes

$650MM Revolver

($ in millions) 6/30/2017

Liquidity

Borrowing Base $650

Cash $15

Revolver Borrowings ($146)

Letters of Credit (2)

Total Current Liquidity $517

($ in millions) 6/30/2017

Cash $15

WRD Revolving Credit Facility $146

6.875% Senior Notes 350

Total Debt $496

Series A Cum. Perpetual Convertible Preferred $435

Shareholders Equity 1,150

Financial & Operating Statistics

Q2'17 PF Annualized EBITDAX (1)

$265

Interest Expense (2)

30

Q2'17 PF Daily Production (Mboe/d) (1)

29.1

Credit Metrics (3)

Net Debt / Q2'17 PF Daily Production ($/Boe/d) $16,542

Net Debt / Q2'17 PF Annualized EBITDAX (1)

1.8x

Interest Coverage 9.0x

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 $435 million

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 31,294,964 fully converted shares based on a Conversion Price of $13.90 per share

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.

WRD intends to PIK the dividend

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 nominated two directors to the WRD Board

20

FY 2017 Guidance (as of May 11, 2017)

2017 Guidance (as of May 11, 2017)

Note: Updated guidance includes Acquisition impact beginning July 1, 2017. 1. 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. 2. Based on strip pricing as of May 11, 2017.

21

Guidance

Low High

Net Average Daily Production (Mboe/d)

Oil (% of Production)

Natural Gas (% of Production)

NGLs (% of Production)

Average Costs (per Boe)

Lease Operating Expense

Gathering, Processing, and Transportation

Taxes Other than Income

Cash General and Administrative(1)

Commodity Price Realizations (Unhedged)(2)

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)

85 - 105

$550 - $675

95% - 100%

95% - 100%

27% - 32%

9% - 11%

$3.25 - $3.75

$0.95 - $1.15

100 - 120

27 - 31

57% - 61%

29% - 33%

$2.00 - $2.25

$2.50 - $3.00

WildHorse Commodity Hedging Overview

All trading counterparties have investment grade credit ratings at both S&P and Moody’s

Current hedges include primarily costless, fixed price swaps and collars, as well as deferred premium puts

During Q2’17, hedged over 4 million barrels of oil covering 2018 and 2019 through swaps and deferred puts

During Q3’17, hedged ~ 4.6 million barrels of oil covering 2017 through 2020 at approximately $50 per barrel

1. Using the midpoint for collars and floors of puts. 2. Represents mid-point of guidance.

22

Hedge Summary

Q3-Q4 2017 2018 2019 2020

Crude Oil Hedge Contracts:

Total crude oil volumes hedged (Bbl) 3,599,787 6,859,584 4,537,693 342,620

Volumes Hedged (Bbl/d) 19,564 18,793 12,432 936

Total weighted-average price ($/Bbl) (1)

$52.58 $52.35 $52.64 $50.15

% of Expected Production (2)

83%

Natural Gas Hedge Contracts:

Total natural gas volumes hedged (MMBtu) 9,731,708 11,565,800 9,877,900 –

Volumes Hedged (MMBtu/d) 52,890 31,687 27,063 –

Total weighted-average price ($/MMBtu) (1)

$3.22 $3.03 $2.81 –

% of Expected Production (2)

84%

Total Hedge Contracts:

Total hedged production (Mboe) 5,221,738 8,787,217 6,184,010 342,620

Volumes Hedged (Boe/d) 28,379 24,075 16,942 936

Total weighted-average price ($/Boe) (1)

$42.25 $44.85 $43.12 $50.15

% of Expected Production (2)

75%

Investment Highlights

Attractive Acreage Position with Strong Returns

Extensive Inventory Supports Multi-Year Growth Story

Balanced Asset Portfolio with Significant Capital Allocation Optionality

Financial Strength and Flexibility

Experienced, Proven and Aligned Management Team

Red: 80

Green: 0

Blue: 0

Red: 0

Green: 60

Blue: 113

Red: 191

Green: 191

Blue: 191

Red: 128

Green: 205

Blue: 237

Red: 17

Green: 143

Blue: 255

Red: 255

Green: 212

Blue: 212

Red: 255

Green: 232

Blue: 167

Red: 191

Green: 191

Blue: 191

Red: 167

Green: 207

Blue: 157

Red: 176

Green: 218

Blue: 255

23

V. Appendix

24

Focused Strategy of Eagle Ford Acreage Growth and Consolidation

WildHorse continues to execute on proven strategy of organic leasing and targeted acquisitions to grow our high quality Eagle Ford acreage position to 385,000 net acres

Multiple Acquisitions – Sept. 2015(1)

Previous Position Lee

Burleson

Brazos

Washington

Lee

Organic Leasing / Acreage Swaps

1st CWEI Acquisition – June 2015

Previous Position 1st CWEI Acquisition

Burleson

Brazos

Washington

Lee

Previous Position

Organic Leasing / Swaps

Burleson

Brazos

Washington

Lee

2nd CWEI Acquisition – Dec 2015

Previous Position

2nd CWEI Acquisition

Burleson

Brazos

Washington

Lee

SM Acquisition – January 2015

Initial Position Washington

Burleson

Brazos

Washington

Lee

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

3rd CWEI Acquisition – Dec 2016

Comstock Acquisition – July 2015

Previous Position

Comstock Acquisition

Burleson

Brazos

Washington

Lee

Burleson

Brazos

Washington

Lee

Previous Position

3rd CWEI Acq.

APC / KKR – June 2017

Burleson

Brazos

Washington

Lee

Previous Position APC / KKR Acq.

0 20

Miles

25

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 of ~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 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

26

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 3/31/2017 based on Company Investor Presentations, Company Filings and published reports. 1. Purchase Price adjusted for production at $40,000 Boe/d. 2. SCOOP/STACK net location count is based on limited transaction comps given the lack of location disclosures in Anadarko Basin transactions. In addition, net locations may vary significantly across commodity mix windows and intervals.

$3,810 $5,899 $6,211

~$9,500

~$31,250

$0

$10,000

$20,000

$30,000

$40,000

WR

D E

F A

cqui

sitio

ns

Ven

ado

/ Exc

o

Haw

kwoo

d / H

alco

n

SCO

OP

/ ST

AC

K

Perm

ian

Bas

in

$2,103 $2,674 $3,230

~$7,000

~$27,000

$0

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

WR

D E

F A

cqui

sitio

ns

Ven

ado

/ Exc

o

Haw

kwoo

d / H

alco

n

SCO

OP

/ ST

AC

K

Perm

ian

Bas

in

Purchase Price / Total Acres PDP Adjusted Purchase

Price(1) / Total Acres

($ / acre) ($ / acre)

WRD has acquired 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 ~$1.8 million / net location and transactions in the SCOOP / STACK have averaged ~$1.0 million / net location

$420

$650

$944 ~$1,000

~$1,750

$0

$400

$800

$1,200

$1,600

$2,000

WR

D E

F A

cqui

sitio

ns

Haw

kwoo

d / H

alco

n

Ven

ado

/ Exc

o

SCO

OP

/ ST

AC

K

Perm

ian

Bas

in

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

($ 000's / location)

27

10

100

1,000

1 3 5 7 9 11 13 14 16 18 20 22 24

Boe/d

Month

91 Boe/ft Type Curve Gen 3 Average Boe

Type Well Assumptions

Wellhead EUR (MBoe) 555

Oil EUR (Mbbl) 497

% Oil 90%

Gas EUR (MMcf) 348

Sales EUR (MBoe) 594

Oil EUR (Mbbl) 497

Gas EUR(MMcf) 219

NGL EUR (Mbbl) 60

% Gas 6%

% Oil 84%

% NGL 10%

% Liquids 94%

GOR (Mcf/bbl) 0.70

Lateral Length (ft) 6,500

Shrinkage 63%

Variable Water Cost ($/Water Bbl) $0.90

Type Curve

30-day Oil IP (Bbl/d) 621

30-day Gas IP (Mcf/d) 434

30-day IP (Boe/d, 3-Stream) 741

30-day IP (Boe/d) per 1,000' 114

Initial Decline (%) 78%

B Factor 1.40

Terminal Decline (%) 6%

Summary

Net Drilling Locations 1,996

EUR / 1,000 Foot (MBoe) 91

D&C ($MM) $5.6

D&C / Foot $862

NPV10 ($MM) $5.0

IRR (%) 46%

1. Consensus Pricing as of 8/2/17: $51.16 / $3.16 for 2017, $54.90 / $3.14 for 2018, $58.00 / $3.05 for 2019, $62.50 / $3.24 for 2020, $66.50 / $3.40 for 2021 and thereafter for WTI and Henry Hub, respectively. 2. See slide 7 for further information regarding our drilling locations. 3. Eagle Ford wells drilled and completed as of June 30, 2017, excludes three wells with not enough production history. 4. IRR sensitivities assume $3.00 Henry Hub for the life of the well.

~2,000 Net Eagle Ford Locations with Highly Economic 91 Boe/ft Type Curve

91 Boe/ft Type Curve (3)

IRR Sensitivity(4)

Eagle Ford Single Well Summary

(1)

(2)

28

EUR / 1,000 Ft Oil Price

(MBOE) % $40.00 $45.00 $50.00 $55.00 $60.00

91 0% 19% 27% 37% 47% 59%

100 10% 25% 35% 46% 59% 72%

110 21% 32% 45% 59% 74% 93%

120 32% 41% 55% 72% 92% 114%

130 43% 49% 67% 88% 111% 140%

140 54% 60% 80% 105% 134% 172%

EU

R I

mpr

ovem

ent

Type Well Assumptions

Wellhead EUR (MMcfe) 14,592

Gas EUR (MMcf) 14,275

Oil EUR (Mbbl) 53

% Gas 98%

Sales EUR (MMcfe) 14,521

Gas EUR(MMcf) 14,204

Oil EUR (Mbbl) 53

% Gas 98%

% Oil 2%

Choke (MMcfd/1,000') 1.5

Flat Time (Days) 120

Oil Yield (bbl/MMcf) 3.7

Lateral Length (Ft) 7,500

Shrinkage 99.5%

BTU Factor 1,090

Type Curve

30-day Gas IP (Mcf/d) 11,250

30-day Oil IP (Bbl/d) 42

30-day IP (Mcfe/d) 11,500

30-day IP (Mcfe/d) per 1,000' 1,533

Initial Decline (%) 65%

B Factor 1.40

Terminal Decline (%) 5%

Summary

Net Drilling Locations 493

EUR / 1,000 Foot (Bcfe) 1.9

D&C ($MM) $8.4

D&C / Foot $1,120

NPV10 ($MM) $9.5

IRR (%) 61%

RCT Upper Red Type Curve Economics

RCT Upper Red Single Well Type Curve

IRR Sensitivity(2)

RCT Upper Red Single Well Summary

1. Consensus Pricing as of 8/2/17: $51.16 / $3.16 for 2017, $54.90 / $3.14 for 2018, $58.00 / $3.05 for 2019, $62.50 / $3.24 for 2020, $66.50 / $3.40 for 2021 and thereafter for WTI and Henry Hub, respectively. Excludes inter-company gathering fees to wholly-owned midstream system.

2. IRR sensitivities assume $50.00 WTI for the life of the well. 3. Representative wells include the Smelley 15-22 HC-1, Ates 18 7 HC-1, Spillers 18-7 HC-1 and Taylor 13-12 H-1. 4. See slide 7 for further information regarding our drilling locations.

Restricted Rate

1

10

100

1,000

10,000

1

10

1 3 5 7 9 11 13 14 16 18 20 22 24

MMcfe/d

Month Type Curve Type Curve Cum Average of Representative Wells(3)

(1)

Cumulative Production (Bcfe)

(4)

Gas Price

$2.00 $2.50 $3.00 $3.50 $4.00

0% 15% 31% 52% 78% 112%

5% 18% 35% 58% 89% 126%

10% 20% 40% 66% 100% 142%

15% 23% 44% 74% 111% 159%

20% 26% 50% 82% 124% 178%EU

R I

mpr

ovem

ent

Red: 80

Green: 0

Blue: 0

Red: 0

Green: 60

Blue: 113

Red: 191

Green: 191

Blue: 191

Red: 128

Green: 205

Blue: 237

Red: 17

Green: 143

Blue: 255

Red: 255

Green: 212

Blue: 212

Red: 255

Green: 232

Blue: 167

Red: 191

Green: 191

Blue: 191

Red: 167

Green: 207

Blue: 157

Red: 176

Green: 218

Blue: 255

29

NGP and Management(1)

WildHorse Resource Development Corporation

NYSE: WRD

Operating Subsidiaries

56.3%(2) 23.6%(2) 4.2%(2) 15.9%(2)

100%

Public Stockholders

Red: 255

Green: 212

Blue: 212

Red: 255

Green: 232

Blue: 167

Red: 191

Green: 191

Blue: 191

Red: 167

Green: 207

Blue: 157

Red: 176

Green: 218

Blue: 255

Red: 80

Green: 0

Blue: 0

Red: 0

Green: 60

Blue: 113

Red: 191

Green: 191

Blue: 191

Red: 128

Green: 205

Blue: 237

Red: 17

Green: 143

Blue: 255

The Carlyle Group $435MM 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 and Management. 2. Pro Forma for impact of $435mm Series A Perpetual Convertible Preferred Stock. 3. As of August 4, 2017; Includes $435mm Series A Perpetual Convertible Preferred Stock.

30

Company Shares Breakout

Total Common Shares Outstanding 101,135,300

Current Float 26,623,652

Market Capitalization (3)

$1,695

Fully Diluted Equity Ownership

Pro Forma (2)

% Shares

Series A Perpetual Convertible Preferred (Carlyle) 23.6% 31,294,964

KKR 4.2% 5,518,125

NGP + Management 56.3% 74,511,648

Public 15.9% 21,105,527

Crude Oil Hedge Summary

Red: 80

Green: 0

Blue: 0

Red: 0

Green: 60

Blue: 113

Red: 191

Green: 191

Blue: 191

Red: 128

Green: 205

Blue: 237

Red: 17

Green: 143

Blue: 255

Red: 255

Green: 212

Blue: 212

Red: 255

Green: 232

Blue: 167

Red: 191

Green: 191

Blue: 191

Red: 167

Green: 207

Blue: 157

Red: 176

Green: 218

Blue: 255

1. Using the midpoint for collars.

31

Oil Hedge Summary

Q3-Q4 2017 2018 2019 2020

Crude Oil Hedge Contracts:

Swap contracts:

Volume (MBbl) 2,357 6,237 4,127 343

Volume (Bbl/d) 12,807 17,087 11,307 936

Weighted-average fixed price $51.29 $52.55 $52.91 $50.15

Collar contracts:

Volume (MBbl) 28 25 – –

Volume (Bbl/d) 153 69 – –

Weighted-average floor price $50.00 $50.00 – –

Weighted-average ceiling price $62.10 $62.10 – –

Put options (bought):

Volume (MBbl) 1,215 598 411 –

Volume (Bbl/d) 6,603 1,638 1,125 –

Weighted-average floor price $55.00 $50.00 $50.00 –

Weighted-average put premium ($4.77) ($5.95) ($5.95) –

Total Crude Oil Hedge Contracts:

Total crude oil volumes hedged (MBbl) 3,600 6,860 4,538 343

Total crude oil volumes hedged (Bbl/d) 19,564 18,793 12,432 936

Total Weighted-Average Price

Total weighted-average price (excluding puts) (1)

$51.34 $52.57 $52.91 $50.15

Total weighted-average price (including puts) (1)

$52.58 $52.35 $52.64 $50.15

Natural Gas Hedge Summary

Red: 80

Green: 0

Blue: 0

Red: 0

Green: 60

Blue: 113

Red: 191

Green: 191

Blue: 191

Red: 128

Green: 205

Blue: 237

Red: 17

Green: 143

Blue: 255

Red: 255

Green: 212

Blue: 212

Red: 255

Green: 232

Blue: 167

Red: 191

Green: 191

Blue: 191

Red: 167

Green: 207

Blue: 157

Red: 176

Green: 218

Blue: 255

1. Using the midpoint for collars.

32

Gas Hedge Summary

Q3-Q4 2017 2018 2019

Gas Hedge Contracts:

Swap contracts:

Volume (BBtu) 4,001 11,566 9,878

Volume (MMBtu/d) 21,742 31,687 27,063

Weighted-average fixed price $3.12 $3.03 $2.81

Collar contracts:

Volume (BBtu) 2,760 – –

Volume (MMBtu/d) 15,000 – –

Weighted-average floor price $3.00 – –

Weighted-average ceiling price $3.36 – –

Put options (bought):

Volume (BBtu) 2,971 – –

Volume (MMBtu/d) 16,148 – –

Weighted-average floor price $3.40 – –

Weighted-average put premium ($0.37) – –

Total Gas Hedge Contracts:

Total gas volumes hedged (BBtu) 9,732 11,566 9,878

Total gas volumes hedged (MMBtu/d) 52,890 31,687 27,063

Total Weighted-Average Price

Total weighted-average price (excluding puts) (1)

$3.14 $3.03 $2.81

Total weighted-average price (including puts) (1)

$3.22 $3.03 $2.81

Reconciliation of Adjusted EBITDAX

Red: 80

Green: 0

Blue: 0

Red: 0

Green: 60

Blue: 113

Red: 191

Green: 191

Blue: 191

Red: 128

Green: 205

Blue: 237

Red: 17

Green: 143

Blue: 255

Red: 255

Green: 212

Blue: 212

Red: 255

Green: 232

Blue: 167

Red: 191

Green: 191

Blue: 191

Red: 167

Green: 207

Blue: 157

Red: 176

Green: 218

Blue: 255

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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; provision for environmental remediation; transaction related costs; IPO related expenses; 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 second quarter of 2017 and 2016 EBITDAX to the most comparable measure calculated in accordance with GAAP:

For the Three Months

Ended June 30,

(Amounts in $000s) 2017 2016

Net Income (loss) 26,366$ (18,281)$

Add (Deduct):

Interest expense, net 6,633 1,781

Income tax (benefit) expense 15,193 111

Depreciation, depletion and amortization 33,229 19,923

Exploration expense 11,504 80

(Gain) loss on derivative instruments (46,116) 15,610

Cash settlements received / (paid) on commodity derivatives 2,076 2,525

Stock-based compensation 1,308 -

Acquisition related costs 2,199 72

Debt extinguishment costs - -

Initial public offering costs - -

Non-cash liability amortization - (103)

Adjusted EBITDAX 52,392$ 21,718$

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 $42.75 per Bbl and $2.48 per MMBtu; $43.12 per Bbl and $2.24 per MMBtu; and $50.28 per Bbl and $2.59 MMBtu was based on the unweighted average of the first-day-of-the-month prices for each of the twelve months preceding December 2016, June 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. The following table provides a reconciliation of PV-10 of WRD’s proved reserves to the Standardized Measure of discounted future net cash flows at December 31, 2016, 2015 and 2014: 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, 2016 have been prepared by WildHorse’s internal reserve engineers and audited by Cawley, Gillespie & Associates, Inc. (“CGA”), WildHorse’s independent reserve engineers.

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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 of 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 net horizontal drilling locations in this press release in the proved, probable, and possible categories as audited by CG&A as well as 1,599 drilling locations that have been identified by WRD’s management including 949 locations associated with the Acquisition. 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 those 3,299 net horizontal drilling locations, 1,700 lie within the geographic areas to which proved, probable and possible reserves are attributed. The remaining 1,599 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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Cautionary Statements and Additional Disclosures

Cash General and Administrative Expenses per Boe Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-GAAP measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed 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 other 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.

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