Company Presentation June 2017

Transcription

1 Company Presentation June 2017

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 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

3 3 I. Company Overview

4 WRD Has Built a Premier Platform for Growth Key Investor Considerations Premier Acreage Positions in the Eagle Ford and North Louisiana 2 nd Largest Eagle Ford Position: Recently announced acquisition increases Eagle Ford position by 40% to ~385,000 net acres Robust Production Growth: 60% in 2017E and 83% in 2018E based on updated analyst estimates Deep Eagle Ford Inventory: ~2,000 net locations of 91 boe/ft EUR type curve (>20 years of inventory at current pace) Outperforming Eagle Ford Type Curve: >80% of Gen 3 wells are performing above our 91 boe/ft EUR type curve Total Company Net Acres (1) ~489,000 Proved Reserves (MMboe) (2) % Liquids 68% % Oil 59% OK Q PF Production (Mboe/d) 25.2 % Liquids 68% Drilling Locations: Gross 5,829 Net 3,299 Second largest Eagle Ford position in the TX industry AR In and around the prolific Terryville Complex MS Conservative Balance Sheet: Targeting YE 17 leverage of less than 2.0x Net Debt / EBITDAX Significant Management Ownership: Management team is highly aligned with shareholders Catalysts Ahead: Additional Gen 3 wells, Austin Chalk well results 2H 17, refracs and testing two Eagle Ford landing zones Attractive Valuation: Meaningful valuation discount to peers on 2017 and 2018 EV/EBITDAX Eagle Ford Net Acres (1) ~385,000 Proved Reserves (MMboe) (2) % Liquids 92% % Oil 81% Q PF Production (Mboe/d) 19.1 % Liquids 88% Drilling Locations: Gross 4,416 Net 2,651 Single-well IRR (3) ~55% LA North Louisiana Net Acres (1) ~104,000 Proved Reserves (Bcfe) (2) % Gas 98% Q Production (Mmcfe/d) 36.3 % Gas 95% Drilling Locations: Gross 1,413 Net 648 Single-well IRR (3) ~69% 4 Note: Q pro forma daily production based on WRD Q production plus Q production from announced acquisition; drilling locations pro forma for announced acquisition. 1. Pro forma acreage as of March 1, 2017; Includes pending acquisition of 111,044 net acres; 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 announced acquisition (audited proved reserves not currently available). 12/31/16 reserve report audited by Cawley, Gillespie & Associates ( CGA ). 3. See slides 33 and 34 for assumptions embedded in WildHorse IRR calculations. IRRs based on Consensus Pricing as of 4/26/2017: $54.00 / $3.15 for 2017, $60.00 / $3.11 for 2018, $61.00 / $3.09 for 2019, $66.50 / $3.25 for 2020, $70.00 / $3.45 for 2021 and thereafter for WTI and Henry Hub, respectively.

5 WRD Will Operate the Second Largest Eagle Ford Position Operator Acreage Positions (1) Net Acreage Positions (1) Eagle Ford Shale Oil Wet Gas/Condensate Dry Gas (000s Acres) EOG Resources 590 (2) WildHorse 274 Acq. 385 Sanchez Energy 335 Chesapeake 260 BHP Billiton 252 ConocoPhillips 213 BP 190 SM Energy 168 NM OK AR Murphy Oil TX LA Marathon 145 Miles Carrizo Net acreage positions per Company Investor Presentations, Company Filings and published reports as of 4/30/ WildHorse gives effect to announced acquisition.

6 Acquisition Further Extends Deep Inventory of Economic Locations Net Horizontal Locations by Area Inventory Breakevens (10% Pre-tax IRR) Net Locations (1) 3,500 3,000 2,500 2,000 Multiple decades of drilling inventory across Eagle Ford and North Louisiana based on net locations (1) , ,299 Net Locations Net Locations 3,500 3,000 2,500 2,129 2, ,927 2,996 2, , , , ,285 Eagle Ford EUR (91 Boe/ft) 1,996 Eagle Ford Additional upside locations in: Existing Eagle Ford Locations Acquisition Locations North Louisiana Locations 1,702 Other RCT Other Total Locations North Louisiana ~130,000 Eagle Ford net acres with no locations assigned under evaluation Austin Chalk in Burleson County; Buda, Woodbine, Georgetown and Pecan Gap across much of our Eagle Ford acreage Northern Louisiana Additional Cotton Valley intervals 1, ,573 1,587 1,587 1,199 $35.00 / $2.00 $45.00 / $2.50 $55.00 / $3.00 $65.00 / $3.50 Existing Eagle Ford Acquisition North Louisiana 6 1. As of May 11, 2017, we identified 3,299 net horizontal drilling locations, which includes 949 locations associated with our pending acquisition. 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, Accordingly, 1,599 of these locations do not have any reserves assigned to them which includes 949 locations associated with the pending 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.

7 WRD EF Acquisitions Hawkwood / Halcon Venado / Exco SCOOP / STACK Permian Basin WRD EF Acquisitions Venado / Exco Hawkwood / Halcon SCOOP / STACK Permian Basin WRD EF Acquisitions Venado / Exco Hawkwood / Halcon SCOOP / STACK Permian Basin WRD s Attractive Eagle Ford Acquisition Metrics Bolster Full Cycle Returns 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 ~$1.8 million / net location and transactions in the SCOOP / STACK have averaged ~$1.0 million / net location PDP Adjusted Purchase Price (1) / Net Locations (2) PDP Adjusted Purchase Price (1) / Total Acres Purchase Price / Total Acres ($ 000's / location) ($ / acre) ($ / acre) $2,000 ~$1,750 $30,000 ~$27,000 $40,000 $1,600 $25,000 $30,000 ~$31,250 $1,200 $944 ~$1,000 $20,000 $15,000 $20,000 $800 $400 $420 $650 $10,000 $5,000 $2,103 $2,674 $3,230 ~$7,000 $10,000 $3,810 $5,899 $6,211 ~$9,500 $0 $0 $0 7 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.

8 Leading Industry Metrics at a Compelling Valuation Enterprise Value / EBITDAX Production Growth x 8.9x 3.4x 5.9x 100% 80% 60% 40% 60% 43% 83% 34% % 0.0 EV/2017E EBITDAX WRD EV/2018E EBITDAX Peer Group 0% 2017E Growth Rate WRD 2018E Growth Rate Peer Group EBITDAX Growth Net Debt / EBITDAX 200% 160% 120% 80% 174% 70% 107% 53% x 2.5x 1.3x 1.9x 40% 0% 2017E Growth Rate WRD 2018E Growth Rate Peer Group 0.0 Debt/2017E EBITDAX WRD Debt/2018E EBITDAX Peer Group 8 Note: Enterprise value based on closing stock price as of May 24, 2017; Peer group includes:cpe, CRZO, EGN, LPI, MTDR, OAS, PDCE, PE, QEP, RSPP, SM, SN, SYRG, WPX AND XOG. Based on FactSet consensus estimates as of May 24, 2017 (WRD consensus excludes estimates that do not reflect the recently announced acquisition ).

9 Top Tier Debt-Adjusted Production Growth and EBITDAX Margin Debt-Adjusted Production Growth E (1) 90% 75% 60% 45% 30% 15% 0% (15%) (30%) 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%) SRCI RSPP FANG PE WRD LPI OAS WPX CXO PXD EGN MTDR CNX EOG CLR XEC COG AR APA RRC MRO CRZO OXY NFX HES CHK DVN WLL MUR QEP APC NBL SWN SM NOG 2017E EBITDAX Margin (2) 90% 75% 60% 45% 77% 76% 74% 73% 65% 65% 63% 62% 61% 60% 60% 59% 59% 54% 53% 50% 48% 47% 47% 30% 15% 0% CLR WRD RSPP SM GPOR EOG OAS COG APC WLL NFX EPE DVN RRC WPX SWN AR ECR CHK 9 1. Source: Raymond James Equity Research E 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. 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)

10 10 II. Eagle Ford Overview

11 Acquisition Overview Transaction Summary WRD agreed to acquire ~111,000 net acres and 7.6 Mboe/d of net production from Anadarko Petroleum Corporation ( Anadarko or APC ) and affiliates of Kohlberg Kravis Roberts & Co. L.P. ( KKR ). Target closing date for the acquisition is June 30, $625 million acquisition consideration includes: $121 million revolving credit facility borrowings ~$69 million in common shares issued to KKR at closing, ~6.3 million shares $435 million in Series A Perpetual Convertible Preferred Stock issued at closing to The Carlyle Group, through its U.S. buyout fund Carlyle Partners VI Milam Asset Overview Robertson Burleson Brazos Compelling Rationale for Transformative Acquisition HIGH QUALITY EAGLE FORD ACREAGE AND INVENTORY ~111,000 net acres in the Eagle Ford (40% increase in total Eagle Ford acres) 711 net locations in the Eagle Ford 91 Boe/ft type curve area with attractive single-well IRRs of 55% (1) Average 8/8 ths NRI of ~80% LIQUIDITY ENHANCING AND CREDIT NEUTRAL Expected pro forma liquidity after giving effect to the acquisition of ~$620mm (2) Net debt / Annualized EBITDAX (3) remains 1.9x pro forma for the acquisition MIDSTREAM INFRASTRUCTURE IN PLACE Pipeline infrastructure in place; takeaway capacity and advantaged location leads to low differentials ADDITIONAL UPSIDE Second landing target in the Eagle Ford with potential downspacing opportunities Refrac potential on understimulated Eagle Ford wells with average sand loadings of 1,100 lbs/ft Upside potential in other horizons: Austin Chalk, Georgetown, Buda, Pecan Gap and Woodbine Lee 0 20 Miles Fayette High Oil Cut Carbonate Rich Attractive Oil Gravity High Pore Pressure WildHorse Acquisition Geologic Criteria WRD Eagle Ford Washington WRD APC / KKR Acquisition Austin APC / KKR Acquisition See slide 33 for assumptions embedded in Eagle Ford IRR calculation. IRR based on Consensus Pricing as of 4/26/2017: $54.00 / $3.15 for 2017, $60.00 / $3.11 for 2018, $61.00 / $3.09 for 2019, $66.50 / $3.25 for 2020, $70.00 / $3.45 for 2021 and thereafter for WTI and Henry Hub, respectively. 2. Based on initial indications from its bank group, WRD expects an increase to its borrowing base of approximately $200 million for the announced acquisition adjustment 3. See Net Debt and EBITDAX reconciliations on page 39 and 42. WRD status quo Q reported EBITDAX; announced acquisition adjustment based on Q EBITDAX.

12 Cumulative Production (Boe) Recent Well Results Outperform and Delineate Extensive Acreage Position WRD Gen 3 wells continue to outperform 91 Boe/ft type curve across the acreage position >80% of Gen 3 wells drilled to date are performing above 91 Boe / ft type curve EUR Current Eagle Ford producing wells exist across entire ~800 square mile area Jackson #1H EUR: 110+ Boe/Ft IP30= 958 BOE/D (85% oil) 6,297 LL (3/27/2017) Horizontal Well Activity (1) 120,000 Gen 3 Completions Outperforming Type Curve (6 Mo Cum) (2) Altimore #1H EUR: 120+ Boe/Ft IP30 = 1,048 BOE/D (84% oil) 6,435 LL (3/31/2017) 100,000 80,000 Candace #1H EUR: 138 Boe/Ft IP30 = 1,081 BOE/D (88% oil) 7,481 LL (9/2/16) 60,000 40,000 20,000 Paul 134 Unit #2H EUR: 130+ Boe/Ft IP30 = 1,035 BOE/D (93% oil) 5,363 LL (3/8/17) Cooper B #1H EUR: 107 Boe/Ft IP30 = 576 BOE/D (85% oil) 4,780 LL (12/12/16) WildHorse Mach A #2H EUR: 111 Boe/Ft IP30 = 607 BOE/D (64% oil) 6,672 LL (2/22/17) 3 rd Party EF HZ Well Belmont Stakes #1H EUR: 135 Boe/Ft IP30 = 740 BOE/D (65% oil) 5,831 LL (10/1/16) 0 20 Miles WRD Acreage with Locations Additional WRD Acreage (3) Kentucky Derby #1H EUR: 100 Boe/Ft IP30 = 594 BOE/D (55% oil) 5,126 LL (10/1/16) Days Gen 3 Avg Boe Cum (23 wells) 91 Burleson Boe/ft Main Type Curve Type Curve Recent Candace Gen #1H3 Well Results IRR Sensitivity at Consensus Price Deck (4) EUR (Boe / Ft) % 68% 84% 100% 121% 145% 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. 2. 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. 3. Represents ~130,000 net acres with no locations assigned under evaluation. 4. See slide 33 for assumptions embedded in Eagle Ford IRR calculation. IRR based on Consensus Pricing as of 4/26/2017: $54.00 / $3.15 for 2017, $60.00 / $3.11 for 2018, $61.00 / $3.09 for 2019, $66.50 / $3.25 for 2020, $70.00 / $3.45 for 2021 and thereafter for WTI and Henry Hub respectively.

13 Completion Evolution Has Led to Superior Well Performance and Increased Returns WRD Eagle Ford Completion Design Evolution Gen 3 completion designs coupled with restricted choke management have increased EURs Currently testing Gen 4 finding the limit of completion optimization Generation 1 Generation 2 Generation 3 Generation 4 Period Q15 2Q15 4Q 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 Clusters per Stage Increased Intensity Has Improved EURs (EUR / 1,000 ft) (1) IRR Sensitivity (2) MBoe ,500 2,600 3,700 Gen 1 Gen 2 Gen 3 Wells Completed Target Proppant (lbs/ft) EUR Improvement EUR / 1,000 Ft Oil Price (MBOE) % $45.00 $50.00 $55.00 $60.00 $ % 27% 37% 47% 59% 71% % 35% 46% 59% 72% 89% % 45% 59% 74% 93% 113% % 55% 72% 92% 114% 140% % 67% 88% 111% 140% 175% % 80% 105% 134% 172% 212% 1. Includes all Eagle Ford wells drilled and completed as of March 31, 2017 excluding the Altimore and Jackson wells. 2. IRR sensitivities assume $3.00 Henry Hub for the life of the well. 13

14 Proximity to Gulf Coast Leads to Advantaged Oil Pricing 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 ($7.51) DJ Basin Comparative Basin Differentials (1) Bakken SCOOP / STACK Sufficient pipeline take-away capacity decreases risk of midstream bottleneck Potential upside to develop an integrated midstream system to service Eagle Ford assets ($6.82) Permian Basin ($5.84) WRD Eagle Ford Oil currently trucked but infrastructure in place to pipe ($2.86) ($1.90) ($3.49) South Texas Eagle Ford U.S. Shale Basins WTI Cushing # Basin Differential 14 Source: Corporate Filings and Company Data. 1. Differentials based on average realized $/Bbl for the three months ended 3/31/17. Companies included in Permian: FANG, LPI, RSPP, CXO; Companies included in Eagle Ford: CRZO, SN; Companies included in DJ Basin: PDCE, SYRG, XOG; Companies included in Bakken: CLR, WLL; Companies included in SCOOP / STACK: NFX.

15 Eagle Ford Wells Outperform Competing Basins and Peers on Cash Margin Cash Margin: WRD Eagle Ford vs. Competing Basins (1) (1Q 2017) $/Boe $60.00 $40.00 $20.00 $51.81 $51.81 $51.81 $51.81 $51.81 $8.54 $11.64 $12.12 $2.09 $19.50 $17.04 $4.90 $2.52 $2.95 $4.79 $5.66 $2.29 $2.49 $6.17 $3.72 $2.58 $3.11 $7.89 $1.65 $1.80 $33.33 $30.37 $25.28 $23.84 $22.79 $51.81 Q Average WTI Price Commodity Mix Differential LOE (incl. Gathering Fees) Production & Ad Valorem Taxes Cash Margin $0.00 WRD Eagle Ford Permian Bakken DJ Basin Eagle Ford 15 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, SRC and XOG; Companies included in Bakken: CLR and WLL.

16 16 III. North Louisiana Overview

17 North Louisiana Acreage Position Contiguous Position in the Prolific Terryville Field 103,722 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 13 operated horizontal wells to date Management drilled 55 wells for MRD / RRC prior to turning over operation in January net (1,413 gross) locations in North Louisiana 493 net (946 gross) RCT drilling locations 127 net (410 gross) Weyerhaeuser drilling locations ~69% IRRs for RCT Upper Red (2) Q net production of 36.3 MMcfe/d 95% natural gas High realized pricing given proximity to Henry Hub Wholly-owned midstream subsidiary enhances single-well economics Currently operating two rigs Bellevue Timber 16-9 HC-1 (MRD) IP30 = 36.4 MMCFE/D (79% gas) 6,481 LL (4/29/15) DL Sanford 18-7 HC 1 (MRD) IP30 = 31.1 MMCFE/D (79% gas) 7,010 LL (8/9/14) Davison 16-9 HC 2 (MRD) IP30 = 27.3 MMCFE/D (78% gas) 6,116 LL (12/15/14) Dowling HC 1 (MRD) IP30 = 29.4 MMCFE/D (81% gas) 6,624 LL (6/23/14) Dowling HC 2 (MRD) IP30 = 31.9 MMCFE/D (81% gas) 6,624 LL (7/21/14) Lewis HC #2 (MRD) IP30 = 26.5 MMCFE/D (85% gas) 7,752 LL (6/4/15) Dowling HC-1 (MRD) IP30 = 33.7 MMCFE/D (81% gas) 7,620 LL (6/6/15) TL McCrary HC-2 (MRD) IP30 = 24.6 MMCFE/D (81% gas) 7,010 LL (6/22/14) Werner HC-2 (MRD) IP30 = 28.4 MMCFE/D (82% gas) 8,300 LL (2/28/14) Temple 8-5 HC-3 (MRD) IP30 = 27.4 MMCF/D (85% gas) 7,401 LL (4/18/15) Claiborne Athens Bienville Bear Creek Horizontal Well Activity (1) Athens RRC Terryville Field Low Decline PDP Base with Horizontal Development Upside Horizontal Development Focus Area RCT Weyerhaeuser Jackson Lincoln WildHorse Acreage RRC Terryville Field WildHorse Wells RRC Wells RRC Expansion Wells RRC Permit Fault Line Weyerhaeuser Union Ouachita Wright HC 3 (MRD) IP30 = 30.4 MMCFE/D (83% gas) 6,606 LL (12/30/13) Colvin Estate 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) Harrison 7 6 HC-1 (Nadel/WRD) IP24hr 15.3 MMcfe/d (98% gas; Flowing back) 4,245 LL (7/30/16) Williams 11-12H (Nadel & Gussman) IP30 = 14.0 MMCFE/D (95% gas) 4,419 LL (5/20/15) 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 H-1 (WRD) IP30 = 21.8 MMCFE/D (98% gas) 6,796 LL (12/11/14) Smelley 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) Source: Company data and estimates, MRD Investor Presentation, Louisiana Department of Natural Resources, and IHS Enerdeq. 2. See slide 34 for assumptions embedded in North Louisiana IRR calculations.

18 RRC Extension Well Update Positive Initial Results Support Step Out Value Based on drilling and analyzing early data from extension wells, analyses of existing producing fields and more than 50 vertical tests, Range reported that Lower Cotton Valley sands in this portion of the basin are consistent Range announced results from three wells drilled on the north, east and west sides of the Vernon Field, all of which encountered significant amounts of gas in multiple zones across the Upper and Lower Red intervals Wells to the east and west each logged pay in three Upper and Lower Red zones with estimated ~400 Bcf per square mile, 2.5x that of Terryville Based on managed cumulative production and lateral length, both wells appear to have a normalized gas EUR in line with Terryville Upper and Lower Red wells Each well has cumulative production to date of approximately one Bcfe; as a result, Range plans to offset each well with another horizontal well Terryville A A Bienville Claiborne WildHorse Acreage RRC Acreage RRC Extension Wells RRC Permit Driscoll Completed in the Upper Red Upper Red GIP: 210 Bcf / sq. mile Lower Red GIP: 188 Bcf / sq. mile Initial Flowing Pressure: 6,500 psi 24hr Prod Rate (Constrained): 12.4 mmcf/d Lateral Length: 5,050 feet Cum. Production: 660 Mmcf (79 days) A Jackson Lincoln RCT Union Completed in the Lower Red Upper Red GIP: 153 Bcf / sq. mile Lower Red GIP: 263 Bcf / sq. mile Initial Flowing Pressure: 6,700 psi 24hr Prod Rate (Constrained): 23.3 mmcf/d Lateral Length: 4,250 feet Cum. Production: 641 Mmcf (67 days) Ouachita A Vertical Well Rates IP: 2.33 MMcf/d No LCV Test IP: 2.61 MMcf/d IP: 9.34 MMcf/d IP: 1.0 MMcf/d IP: MMcf/d IP: 1.32 MMcf/d IP: 2.55 MMcf/d IP: 5.18 MMcf/d IP: 3.93 MMcf/d IP: 2.8 MMcf/d Upper Red Lower Red 18 Source: RRC January 27, 2017 and April 24, 2017 press releases, RRC October 25 th, 2016 investor presentation, press release, and earnings call. Note: Gray boxes represent vertical well test rates. Red sections indicate thickness of LCV interval.

19 North Louisiana Wells Outperform Competing Basins and Peers on Cash Margin Cash Margin: WRD North Louisiana vs. Competing Basins (1) (First Quarter 2017) $/Mcfe $4.00 $3.77 $3.50 $3.00 $3.44 $0.13 $0.05 $0.23 $0.45 $0.36 $3.37 $0.06 $0.12 $3.31 Q Average HHUB Price $2.50 $2.00 $0.56 $0.25 $0.68 $0.10 $0.98 $0.14 $0.08 Commodity Mix Differential $1.50 Gathering, Processing, & Transportation (2) $1.00 $0.50 $2.22 $2.17 $1.99 LOE Production & Ad Valorem Taxes Cash Margin $0.00 WRD NLA Diversified Gas Marcellus 19 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 $3.31 first 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.

20 20 IV. Financial Overview

21 Acquisition Structure and Financing Overview Key Transaction Details $625 million acquisition consideration: $121 million revolving credit facility borrowings $69 million in common shares issued to KKR (~6.3 million shares) $435 million in Series A Perpetual Convertible Preferred Stock issued at closing to The Carlyle Group, through its U.S. buyout fund Carlyle Partners VI Expected $200 million increase in the revolving credit facility s borrowing base to occur with closing Sources and Uses ($ in millions) Sources RBL Borrowing $121 Common Shares to KKR 69 Preferred Equity 435 Total Sources $625 Uses Purchase Price $625 Total Uses $625 Pro Forma Capitalization 3/31/2017 Acquisition Pro Forma ($ in millions) Status Quo Adj. Acq. Cash $93 - $93 WRD Revolving Credit Facility - $121 $ % Senior Notes Total Debt $350 $121 $471 Series A Perpetual Convertible Preferred - $435 $435 Equity Issued to KKR Stockholders Equity 1, ,130 Financial & Operating Statistics Annualized EBITDAX (1) $138 $63 $202 Interest Expense (2) (3) Latest Daily Production (Mboe/d) Liquidity Borrowing Base $450 $200 $650 Cash $93-93 Revolver Borrowings - (121) (121) Letters of Credit (1) - (1) Total Current Liquidity $543 $79 $622 Credit Metrics (4) Net Debt / Latest Daily Production ($ / Boe/d) $14,583 $14,998 Net Debt / Annualized EBITDAX (1) 1.9x 1.9x (2) Interest Coverage 5.7x 7.1x WRD status quo Q reported EBITDAX; announced acquisition adjustment based on Q EBITDAX. 2. Interest Coverage calculated as EBITDAX / Interest; assumes status quo interest expense based on 6.875% notes and pro forma adjustment assumes 3.52% rate on revolver borrowings. 3. WRD status quo Q reported production; announced acquisition adjustment based on Q production. 4. Credit metrics assume 100% equity treatment for the Series A Perpetual Convertible Preferred.

22 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 Closing date in conjunction with the acquisition closing; target of 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 Conversion Rights 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 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 Will vote on an as converted basis; The Carlyle Group to elect two directors to the WRD Board 22

23 Updated FY 2017 Guidance; Pro Forma for Acquisition Expect to allocate a portion of our 2017 development program to higher working interest wells in and around the acquired acreage Updated Guidance reflects ~1 MBoe/d in outperformance and ~3 MBoe/d for acquisition (expected production for July Dec 2017) 2017 Guidance Prior Guidance Updated Guidance Low High Low High Net Average Daily Production (MBoe/d) Oil (% of Production) 52% - 56% 57% - 61% Natural Gas (% of Production) 35% - 38% 29% - 33% NGLs (% of Production) 8% - 10% 9% - 11% Average Costs (per Boe) Lease Operating Expense $ $3.25 $ $3.75 Gathering, Processing, and Transportation $ $1.15 $ $1.15 Taxes Other than Income $ $2.25 $ $2.25 (1) Cash General and Administrative $ $3.25 $ $3.00 (2) Commodity Price Realizations (Unhedged) Crude Oil Realized Price (% of WTI NYMEX) 95% - 100% 95% - 100% Natural Gas Realized Price (% of NYMEX to Henry Hub) 95% - 100% 95% - 100% NGL Realized Price (% of WTI NYMEX) 22% - 27% 27% - 32% Drilling Program Wells Spud (Gross) Wells Completed (Gross) D&C Capital Expenditure ($MM) $450 - $600 $550 - $ Note: Guidance as of May 11, Updated guidance includes announced acquisition results beginning July 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.

24 WildHorse Commodity Hedging Overview Pro Forma for Acquisition WildHorse s commodity risk management policy provides for hedging estimated production from total proved reserves Proactive policy reduces WildHorse s exposure to movements in commodity prices and provides stability to cash flows 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 Hedge Summary as of May 25, 2017 Q2-Q Crude Oil Hedge Contracts: Total crude oil volumes hedged (Bbl) 3,277,054 5,646,109 3,695,148 Volumes Hedged (Bbl/d) 11,917 15,469 10,124 Total weighted-average price ($/Bbl) (1) $53.64 $52.95 $53.38 % of Expected Production (2) 60% - - Natural Gas Hedge Contracts: Total natural gas volumes hedged (MMBtu) 13,581,895 11,565,800 9,877,900 Volumes Hedged (MMBtu/d) 49,389 31,687 27,063 Total weighted-average price ($/MMBtu) (1) $3.09 $3.03 $2.81 % of Expected Production (2) 86% - - Total Hedge Contracts: Total hedged production (Mboe) 5,540,703 7,573,742 5,341,465 Volumes Hedged (Boe/d) 20,148 20,750 14,634 Total weighted-average price ($/Boe) (1) $39.29 $44.10 $42.13 % of Expected Production (2) 62% Using the midpoint for collars and floors of puts. 2. Represents mid-point of updated guidance.

25 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 25

26 26 V. Appendix

27 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 SM Acquisition January st CWEI Acquisition June 2015 Comstock Acquisition July 2015 Multiple Acquisitions Sept (1) Initial Position Washington Brazos Previous Position 1 st CWEI Acquisition Brazos Previous Position Comstock Acquisition Brazos Previous Position Lee Brazos Burleson Burleson Burleson Burleson Lee Lee Lee Lee Washington Washington Washington Washington 2 nd CWEI Acquisition Dec 2015 Organic Leasing / Acreage Swaps 3 rd CWEI Acquisition Oct 2016 APC / KKR May 2017 Previous Position 2 nd CWEI Acquisition Brazos Previous Position Organic Leasing / Swaps Brazos Previous Position 3 rd CWEI Acq. Brazos Previous Position APC / KKR Acq. Brazos Burleson Burleson Burleson Burleson Lee Lee Lee Lee Washington Washington Washington Washington 0 20 Miles 1. Includes three acquisitions in Lee County that occurred over ~12 months. 27

28 WildHorse Acreage Positioned in the Highly Productive, Liquids-Rich Eagle Ford 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 0 20 Miles Bastrop Top of Eagle Ford Structural Map Lee Milam 0 20 Miles Milam Lee Fayette Burleson Burleson Fayette Washington Austin Oil Gravity Brazos Grimes Waller WRD Acreage APC / KKR Acquisition Brazos Washington Grimes WRD Acreage APC / KKR Acquisition Shallow -6,000' -7,000' -8,000' -9,000' -10,000' -11,000' -12,000' -13,000' -14,000' Deep API Miles Milam Gross Thickness Isopach Map Lee 0 20 Miles Bastrop Milam Lee Burleson Fayette Washington Austin Gas / Oil Ratio Burleson Fayette Brazos Grimes Waller WRD Acreage APC / KKR Acquisition Brazos Washington Grimes WRD Acreage APC / KKR Acquisition Thick 500' 450' 400' 350' 300' 250' 200' 150' 100' Mcf / STB 10,000 Thin 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1, ' 28

29 Gen 3 Design Outperforms Legacy Eagle Ford Development Wells Well Name Operator Frac Gen Boe/Ft Candace 1H WRD Galaxy 1H APC 1 38 Bronco 3 Well Pad APC 1 33 Whitney Well Pad CWEI 1 59 Milam Robertson Well Name Operator Frac Gen Boe/Ft War Wagon 2 Well Pad APC 1 43 Misfits 2 Well Pad APC 1 36 Zemanek 2 Well Pad APC 1 71 Foxfire 2 Well Pad APC 1 42 Capps 2 Well Pad APC 1 78 Peters Well Pad CWEI <1 44 Abbot Well Pad CWEI <1 45 Brazos Well Name Operator Frac Gen Boe/Ft Altimore #1H WRD Jackson #1H WRD Well Name Operator Frac Gen Boe/Ft Paul 134 #2H WRD Spitfire 2 Well Pad APC <1 61 Victorick 2 Well Pad APC 1 96 Burleson Well Name Operator Frac Gen Boe/Ft Snap B 1H WRD Snap F 1H WRD 3 98 Elm 2 Well Pad APC <1 46 Yucca 2 Well Pad APC <1 62 Capstone 2 Well Pad APC 1 94 Boxwood 1H APC 1 62 Porter E #1H CWEI <1 29 Well Name Operator Frac Gen Boe/Ft Cooper B 1H WRD Mach A 2H WRD Well Name Operator Frac Gen Boe/Ft Belmont Stakes 1H WRD Lee Washington WRD Wells APC Wells CWEI Wells Kentucky Derby 1H WRD Sassafras 2 Well Pad APC Miles 29 Note: Gray shading denotes WildHorse completions. Less than Gen 1 completions represent proppant loads less than 1,000 lbs/ft; Gen 1 completions represent proppant loads between 1,000 and 1,800 lbs/ft; Gen 2 completions represent proppant loads between 1,800 and 3,000 lbs/ft; Gen 3 completions represent loads greater than 3,000 lbs/ft.

30 Water Cut and Infrastructure Enhances Premier Returns in Eagle Ford Low Cost Access to Fresh Water Enhances Premier Returns Secured dedicated freshwater supply from freshwater ponds and an agreement with the Brazos River Authority Capacity to complete ~510 wells per year with no bottlenecks D&C water costs are some of the lowest across U.S. shale basins Potential to develop fresh water pipeline system to further reduce costs across the field Freshwater Pond Lee Milam 0 20 Miles Fayette Dedicated Freshwater Supply Ponds Robertson Burleson Washington Brazos WRD APC / KKR Austin Acquisition WildHorse Eagle Ford Saltwater Disposal Costs Low water cut and saltwater disposal costs leads to reduced LOE Saltwater disposal costs have continued to rise across competing basins WildHorse Eagle Ford water disposal costs are best in class: Cumulative saltwater disposal costs over the life of well for 91 BOE/ft type curve are ~ $115,000 per well Bbls/d Water WildHorse Eagle Ford water disposal cost of $1.05/bbl is significantly lower than competing basins 25% water cut at month 6 Salt Water Basin Disposal Costs ($/Bbl) (1) WRD Eagle Ford $1.05 Permian $ $4.00 S. Texas Eagle Ford $ $3.50 Bakken $ $ $- Month 1 Month 8 Month 15 Month 22 Month 29 Month 36 Bbls/d Water Cumulative Disposal Water Cost Cost $70,000 $60,000 $50,000 $40,000 $30,000 $20,000 $10, Salt Water Disposal cost data per EIA report Trends in U.S. Oil and Natural Gas Upstream Costs, March,

31 RCT The Extension of the Terryville Complex RCT acreage is located in close proximity to top performing Terryville Complex and is an extension to the southeast along the northern fault line Well logs show the reservoir is consistent across the acreage Well design evolution: Generation 1 one cluster, fracture penetrates water bearing zone Generation 2 two clusters yields better fracture containment within the target zone Generation 3 three clusters with restricted choke program for flowback, further containment within target zone and reduces water yields and operating costs Well Design Case Study: Pruitt (Gen 1) vs. Smelley (Gen 2) Pruitt and Smelley wells are direct offsets and well logs confirm similar reservoir quality Well results suggest Pruitt production is drawing from the water-bearing Pink zone, while Smelley production is contained within the Upper Red 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; Flowing back) 4,245 LL (7/30/16) Pruitt HC-1 (WRD) IP MMcfe/d (98% gas) 9,102 LL (12/17/15) Smelley HC-1 (WRD) IP30 = 17.0 MMcfe/d (97% gas) 8,410 LL (6/28/15) Taylor H-1 (WRD) IP30 = 21.8 MMcfe/d (98% gas) 6,796 LL (12/11/14) Taylor H-2 (WRD) IP30 = 8.6 MMcfe/d (98% gas) 4,594 LL (11/2/15) Claiborne Bienville Water-Bearing Zone Lincoln Jackson Union Ouachita Lincoln Generation 1 One Cluster per Stage Jackson 3 Williams 11-12H (Nadel & Gussman) IP30 = 14.0 MMcfe/d (95% gas) 4,419 LL (5/20/15) Union Ouachita WRD Completion Generation 1 2 Generation 2 Two Clusters per Stage 3 Water-Bearing Zone Ates 18 7 HC-1 (WRD) IP30 = 16.0 MMcfe/d (98% gas) 6,705 LL (9/7/15) Rounsaville HC-1 (WRD) IP MMcfe/d (99% gas) 4,633 LL (4/23/15) Pipes HC-1 (WRD) IP MMcfe/d (97% gas) 8,221 LL (1/16/15) Surline HC-1 (WRD) IP MMcfe/d (98% gas) 7,210 LL (5/23/15) Spillers 18-7 HC-1 (WRD) IP30 = 19.4 MMcfe/d (98% gas) 8,884 LL (3/26/15) Weyerhaeuser RCT RRC Terryville WildHorse Wells Fault Line 31

32 Lower Red Upper Red WildHorse Position is a Direct Offset to RRC Terryville Field Terryville Field RCT Terryville Complex A A B B Regional reservoir continuity Consistent drilling targets Stacked horizontal targets 20 + miles A A RCT Weyerhaeuser RRC Terryville Fault Line Lincoln B B Union Jackson Ouachita Source: Company data. 32

33 ~2,000 Net Locations with Highly Economic 91 Boe/ft Type Curve Eagle Ford Single Well Summary 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) $0.90 Type Curve 30-day Oil IP (Bbl/d) day Gas IP (Mcf/d) day IP (Boe/d, 3-Stream) day IP (Boe/d) per 1,000' 114 Initial Decline (%) 78% B Factor 1.40 Terminal Decline (%) 6% Summary(1) Net Drilling Locations (2) 1,996 EUR / 1,000 Foot (MBoe) 91 D&C ($MM) $5.6 D&C / Foot $862 NPV10 ($MM) $5.9 IRR (%) 55% Boe/d 1, EUR Improvement 91 Boe/ft Type Curve (with all 23 Gen 3 well results) Month 91 Boe/ft Type Curve Gen 3 Average Boe IRR Sensitivity (3) EUR / 1,000 Ft Oil Price (MBoe) % $45.00 $50.00 $55.00 $60.00 $ % 27% 37% 47% 59% 71% % 35% 46% 59% 72% 89% % 45% 59% 74% 93% 113% % 55% 72% 92% 114% 140% % 67% 88% 111% 140% 175% % 80% 105% 134% 172% 212% Consensus Pricing as of 4/26/2017: $54.00 / $3.15 for 2017, $60.00 / $3.11 for 2018, $61.00 / $3.09 for 2019, $66.50 / $3.25 for 2020, $70.00 / $3.45 for 2021 and thereafter for WTI and Henry Hub, respectively. 2. See slide 6 for further information regarding our drilling locations. 3. IRR sensitivities assume $3.00 Henry Hub for the life of the well.

34 RCT Upper Red Type Curve Economics RCT Upper Red Single Well Summary 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, day Oil IP (Bbl/d) day IP (Mcfe/d) 11, day IP (Mcfe/d) per 1,000' 1,533 Initial Decline (%) 65% B Factor 1.40 Terminal Decline (%) 5% Summary(1) Net Drilling Locations(4) 493 EUR / 1,000 Foot (Bcfe) 1.9 D&C ($MM) $8.4 D&C / Foot $1,120 NPV10 ($MM) $9.8 IRR (%) 69% MMcfe/d 10 1 EUR Improvement Restricted Rate RCT Upper Red Single Well Type Curve IRR Sensitivity (2) Cumulative Production (Bcfe) 10, Month Type Curve Type Curve Cum Average of Representative Wells (3) Gas Price 1,000 $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% Consensus Pricing as of 4/26/2017: $54.00 / $3.15 for 2017, $60.00 / $3.11 for 2018, $61.00 / $3.09 for 2019, $66.50 / $3.25 for 2020, $70.00 / $3.45 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 HC-1, Ates 18 7 HC-1, Spillers 18-7 HC-1 and Taylor H See slide 6 for further information regarding our drilling locations.

35 WRD Ownership Chart Pro Forma Announced Acquisition Closing NGP and Management (1) The Carlyle Group $435MM Series A Perpetual Convertible Preferred Stock KKR Public Stockholders 55.4% (2) 23.8% (2) 4.8% (2) 16.1% (2) Company Shares Breakout Status Quo PF APC Acq. Total Common Shares Outstanding 93,987, ,248,440 Shares Issued at IPO 29,797,100 29,797,100 Current Float 19,797,100 26,057,999 Market Capitalization (3) $1,302 $1,823 Fully Diluted Equity Ownership PF APC Acq. Pro Forma (2) Series A Perpetual Convertible Preferred (Carlyle) 0.0% 23.8% KKR 6.2% 4.8% NGP + Management 72.7% 55.4% Public 21.1% 16.1% WildHorse Resource Development Corporation NYSE: WRD 100% Operating Subsidiaries 1. NGP and Management includes WHR Holdings, LLC; Esquisto Holdings, LLC; WHE AcqCo Holdings, LLC; NGP XI US Holdings, LP and Management. 2. Fully diluted equity ownership percentages. Pro Forma for announced acquisition and preferred stock and common stock issuance at closing. 3. As of May 23, 2017; Status Quo excludes convertible preferred shares and Pro Forma includes $435mm Series A Perpetual Convertible Preferred Stock. 35

36 Crude Oil Hedge Summary Oil Hedge Summary Q2-Q Crude Oil Hedge Contracts: Swap contracts: Volume (MBbl) 1,908 5,023 3,285 Volume (Bbl/d) 6,939 13,762 8,999 Weighted-average fixed price $52.64 $53.29 $53.80 Collar contracts: Volume (MBbl) Volume (Bbl/d) Weighted-average floor price $50.00 $50.00 Weighted-average ceiling price $62.10 $62.10 Put options (bought): Volume (MBbl) 1, Volume (Bbl/d) 4,818 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) 3,277 5,646 3,695 Total crude oil volumes hedged (Bbl/d) 11,917 15,469 10,124 Total Weighted-Average Price Total weighted-average price (excluding puts) (1) $52.71 $53.30 $53.80 Total weighted-average price (including puts) (1) $53.64 $52.95 $ Using the midpoint for collars. 36

37 Natural Gas Hedge Summary Gas Hedge Summary Q2-Q Gas Hedge Contracts: Swap contracts: Volume (BBtu) 6,346 11,566 9,878 Volume (MMBtu/d) 23,076 31,687 27,063 Weighted-average fixed price $3.13 $3.03 $2.81 Collar contracts: Volume (BBtu) 4,140 Volume (MMBtu/d) 15,055 Weighted-average floor price $2.62 Weighted-average ceiling price $2.94 Put options (bought): Volume (BBtu) 3,096 Volume (MMBtu/d) 11,258 Weighted-average floor price $3.40 Weighted-average put premium ($0.37) Total Gas Hedge Contracts: Total gas volumes hedged (BBtu) 13,582 11,566 9,878 Total gas volumes hedged (MMBtu/d) 49,389 31,687 27,063 Total Weighted-Average Price Total weighted-average price (excluding puts) (1) $2.99 $3.03 $2.81 Total weighted-average price (including puts) (1) $3.09 $3.03 $ Using the midpoint for collars. 37

38 December 31, 2016 June 30, 2016 WildHorse Resource Development CG&A Reserve Detail (Excludes APC acquisition) Oil Natural Gas NGLs Total % Gas PV-10 (MBbl) (MMcf) (MBbl) (MBoe) (%) ($M) PDP 18, ,530 3,674 44,878 51% $361,189 PDNP 743 9, ,392 65% $18,565 PUD 68, ,222 7, ,235 28% $370,233 Total Proved 87, ,103 10, ,505 36% $749,988 Probable 105, ,551 10, ,202 23% $366,727 2P Reserves 192, ,654 21, ,707 29% $1,116,715 Possible 237,364 1,540,204 22, ,213 50% $847,809 3P Reserves 430,298 2,068,858 43, ,920 42% $1,964,524 Oil Natural Gas NGLs Total % Gas PV-10 (MBbl) (MMcf) (MBbl) (MBoe) (%) ($M) PDP 9, ,087 2,600 34,260 65% $228,981 PDNP 8 7, ,330 99% $2,751 PUD 40, ,746 4,976 71,819 37% $197,938 Total Proved 49, ,764 7, ,409 47% $429,671 Probable 61, ,398 7, ,627 32% $266,839 2P Reserves 110, ,163 15, ,035 39% $696, Based on SEC pricing of $43.12 per barrel and $2.24 per mmbtu as of June 30, 2016, and $42.75 per barrel and $2.48 per mmbtu as of December 31, Audited locations does not include management locations. 2. See slide 46 for cautionary statements and additional disclosures regarding 3P reserves

39 Reconciliation of Adjusted EBITDAX 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 first quarters of 2017 and 2016 EBITDAX to the most comparable measure calculated in accordance with GAAP: For the Three Months Ended March 31, (Amounts in $000s) Net Income (loss) $ 20,252 $ (14,216) Add (Deduct): Interest expense, net 5,571 1,972 Income tax (benefit) expense 11, Depreciation, depletion an amortization 26,443 22,063 Exploration expense 1,615 7,443 Impairment of proved oil and gas properties - - (Gain) loss on derivative instruments (31,291) (3,246) Cash settlements received / (paid) on commodity derivatives (983) 3,373 Stock-based compensation Acquisition related costs (Gain) loss on sale properties - - Debt extinguishment costs (11) 358 Initial public offering costs Non-cash liability amortization - (183) Adjusted EBITDAX $ 34,572 $ 17,703 39

40 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. 40