Company Presentation November 8, 2017

Transcription

1 Company Presentation November 8, 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 2 nd 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: 60% in 2017E (4) and 82% in 2018E based on updated analyst estimates Outperforming Eagle Ford Type Curve: 68 Gen 3 wells averaging 101 boe/ft (5), 11% above our 91 boe/ft Eagle Ford type curve Conservative Balance Sheet: Net Debt / Q3 17 annualized EBITDAX of 1.7x Attractive Hedging Profile: 85% of Q4 17 production hedged with additional hedges in Significant Management Ownership: Management team is highly aligned with shareholders Peer Leading ROCE & Debt-Adj. Growth at an Attractive Valuation: Top tier returns; Discount to peers on EV/EBITDAX Catalysts Ahead: Continued Eagle Ford development Completion design improvements Further evaluation of the Austin Chalk Testing two Eagle Ford landing zones Refracs Premier Acreage Positions in the Eagle Ford and North Louisiana Total Company Net Acres (1) ~483,000 Proved Reserves (MMboe) (2) % Liquids 68% % Oil 59% Q Production (Mboe/d) 36.6 % Liquids 75% Drilling Locations: Gross 5,829 Net 3,299 Eagle Ford Net Acres ~385,000 Proved Reserves (MMboe) (2) % Liquids % % Oil 81% Q Production (Mboe/d) 30.1 % Liquids 90% Drilling Locations: Gross 4,416 Net 2,651 Single-well IRR (3) 47% OK Second largest Eagle Ford position in the TX industry AR In and around the prolific Terryville Complex LA MS North Louisiana Net Acres (1) ~98,000 Proved Reserves (Bcfe) (2) % Gas 98% Q Production (MMcfe/d) 39.0 % Gas 96% Drilling Locations: Gross 1,413 Net 648 Single-well IRR (3) 63% 4 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 APC 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 10/18/ E growth rates based on 2016 production pro forma for Clayton Williams acquisition. 5. Eagle Ford wells drilled and completed as of September 30, 2017, excluding six wells with not enough production data to estimate an EUR.

5 Q and Recent Activity Highlights Consistent Success Across Eagle Ford Acreage Strong Balance Sheet and Hedging Program Increased average daily production by 161% to 36.6 Mboe/d for the third quarter 2017 Reported adjusted EBITDAX of $98.4 million for the third quarter 2017 Issued additional $150 million of 6.875% Senior Notes due 2025 Increased borrowing base on WRD s credit facility to $875 million from $612.5 million in October 2017 Experienced minimal downtime from Hurricane Harvey resulting in approximately 175 boe/d of shut in gross production during the third quarter 68 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 Brought online 3 additional wells outside of the Cawley, Gillespie & Associates ( CG&A ) and management s 3P area Drilled 10 gross wells on the recently acquired Anadarko/KKR acreage Gained efficiencies on drilling and completions with no increases in cycle times Achieved an average drilling time of 13.4 days from spud to rig release on all Eagle Ford rigs in the third quarter Continued successful testing of Eagle Ford refracs with two additional tests online in the third quarter of 2017 Net debt / Q3 17 annualized EBITDAX of 1.7x $722 million of liquidity at September 30, % of consensus Q4 17 production hedged (peer group at 60%) (2) 53% of consensus 2018 production hedged (peer group at 55%) (2) 7.7 MMBoe of production hedged in MMBbls of WTI-LLS basis hedged in Q Eagle Ford wells drilled and completed as of September 30, 2017, excluding six wells with not enough data to estimate an EUR. 2. WRD hedging as of November 7, 2017; Peer group hedging based on most recently available public information.

6 WRD Operates 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 528 WildHorse 385 Sanchez Energy 356 Chesapeake 270 BHP Billiton 252 ConocoPhillips 213 BP 190 Apache 180 SM Energy 167 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 7/31/

7 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 648 Net Locations 3,500 3,000 2,500 2,129 2, ,927 2,996 2, ,500 1,000 1,996 1,996 2,651 1,500 1,000 1,910 2,336 2,350 2, Eagle Ford EUR (91 Boe/ft) Eagle Ford Additional upside locations in: Eagle Ford Locations North Louisiana Locations Other RCT Other Total Locations North Louisiana ~130,000 Eagle Ford net acres with no locations assigned actively delineating (2) Austin Chalk, Buda, and Georgetown across much of our Eagle Ford acreage Testing a stack/stagger development of the Upper and Lower Eagle Ford $35.00 / $2.00 $45.00 / $2.50 $55.00 / $3.00 $65.00 / $3.50 Eagle Ford North Louisiana 7 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 CGA s proved, probable and possible reserves as of December 31, Accordingly, 1,599 of these locations are within management s 3P area and 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. 2. The ~130,000 net acres are located outside of CGA s and management s 3P reserve area and currently have no assigned locations.

8 CLR WRD SM RSPP GPOR COG EOG OAS DVN EPE NFX APC WLL SWN WPX RRC ECR AR CHK EBITDAX Margin Cash Margin ($/Boe) Top Tier Returns, Growth and Margins ROCE 25% 20% 15% 10% 5% 0% 2018E ROCE vs EV / EBITDAX (1) Debt-Adjusted Production Growth E (2) ROCE EV / EBITDAX ROCE EV/EBITDAX WRD 12.4% 4.1x Peer Avg. 5.7% 5.0x 9.0x 8.0x 7.0x 6.0x 5.0x 4.0x 3.0x 2.0x 1.0x 0.0x EV/EBITDAX Debt-Adjusted Production Growth 75% 60% 45% 30% 15% 0% Growth WRD 33% Peer Avg. 21% SRCI FANG WRD RSPP PE WPX LPI CNX PXD EGN CXO XEC CLR MTDR COG OAS EOG AR RRC OXY MRO 2017E EBITDAX Margin (3) Q3 17 Cash Margin vs % Oil Production (4) 80% 60% Margin WRD 74% Peer Avg. 59% $35 $30 $25 WRD 40% $20 $15 20% $10 $5 0% $0 0% 20% 40% 60% 80% 100% % Oil Production 8 1. Source: Simmons & Company equity research report. See slide 37 for ROCE calculation methodology. 2. 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. Chart data as of October 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 Other companies include: AREX, AXAS, BBG, CPE, CRC, CRK, CRZO, DNR, EPE, ESTE, GPOR, LPI, MTDR, OAS, PDCE, QEP, SM, SN, SRCI, SWN, WLL, XOG.

9 Leading Industry Metrics at a Compelling Valuation (WRD vs Peers Based on Consensus Estimates) Enterprise Value / EBITDAX (1) Production Growth EBITDAX Growth x 9.3x 4.1x 6.5x 100% 80% 60% 40% 20% 60% 47% 82% 30% 175% 140% 105% 70% 35% 153% 66% 99% 43% 0.0 EV/2017E EBITDAX WRD EV/2018E EBITDAX Peer Group 0% 2017E Growth Rate (2) WRD 2018E Growth Rate Peer Group 0% 2017E Growth Rate 2018E Growth Rate WRD Peer Group Net Debt / EBITDAX % Hedged Total Production (3) % Hedged Oil Production (3) x 1.7x 1.6x 2.2x 100% 75% 50% 25% 85% 60% 53% 55% 100% 80% 60% 40% 20% 86% 71% 67% 65% 0.0 Q3'17 Annualized WRD 2018E Peer Group 0% Q4' WRD Peer Group 0% Q4' WRD Peer Group 9 Note: Enterprise value based on closing stock price as of October 29, 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 November 7, E and 2018E EBITDAX, for both WRD and the peer group, are based on FactSet consensus estimates E growth rates based on 2016 production pro forma for Clayton Williams acquisition. 3. Both WRD and peer group production based on consensus estimates as of November 7, WRD hedging as of November 8, 2017; Peer group hedging based on most recently available public information.

10 10 II. Eagle Ford Overview

11 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 Total of 68 gross Gen 3 Eagle Ford wells online are averaging a 101 boe per foot EUR (1) Current Eagle Ford producing wells exist across entire ~800 square mile area 29 gross wells online on the Clayton Williams acquisition acreage with the average of the wells exceeding a 91 boe per foot type curve (2) Drilled 10 gross wells on Anadarko/KKR acquisition acreage during the third quarter Hovorak EF Unit #1H EUR: 120 Boe/Ft IP30 = 926 BOE/D (91% oil) 6,470 LL (6/11/2017) Candace #1H EUR: 138 Boe/Ft IP30 = 1,081 BOE/D (88% oil) 7,481 LL (9/2/16) 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 EUR: 94 Boe/Ft IP30 = 682 BOE/D (94% oil) 6,463 LL (6/18/17) Drilled on WRD acreage w/o assigned locations Horizontal Well Activity (3) Altimore #1H EUR: 126 Boe/Ft IP30 = 1,048 BOE/D (84% oil) 6,435 LL (3/31/2017) Snap I #1H / Snap J #1H (6) EUR: 104 Boe/Ft IP30 = 683 BOE/D (82% oil) 6,784 LL (7/29/2017) Belmont Stakes #1H EUR: 135 Boe/Ft IP30 = 740 BOE/D (65% oil) 5,831 LL (10/1/16) Cooper B #1H EUR: 107 Boe/Ft IP30 = 576 BOE/D (85% oil) 4,780 LL (2/22/17) Bennett B #7H (Austin Chalk) IP30 = 509 BOE/D (32% oil) 4,444 LL (6/3/17) Brought online 5 gross wells outside of CGA s and management s 3P area Jurica #1H / Doughtie #1H (6) IP30 = 730 BOE/D (95% oil) 6,885 LL (9/21/17) Drilled on WRD acreage w/o assigned locations Mach A #2H EUR: 111 Boe/Ft IP30 = 607 BOE/D (64% oil) 6,672 LL (7/4/17) Tested 6 successful Eagle Ford refracs across the position Winkelmann #1H (Austin Chalk) IP30 = 2,387 BOE/D (26% oil) 4,762 LL (6/3/17) WildHorse Other Operators Legacy EF HZ Well WRD Acreage with Locations (4) Additional WRD Acreage (5) Fowler #1H (GeoSouthern) (Austin Chalk) IP30 = 1,991 BOE/D (9% oil) 5,104 LL (12/8/16) Eagle Ford wells drilled and completed as of September 30, 2017, excluding six wells with not enough data to estimate an EUR. 2. Excludes six 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 dark grey area represents ~255,000 net acres within CGA s and management s 3P reserve area. 5. The light grey area represents ~130,000 net acres outside of CGA s and management s 3P reserve area with no assigned locations. 6. Two well pads represented with average EURs, initial production rates, oil mix, and lateral lengths.

12 Cumulative Production (MBoe) IRR Gen 3 Design Coupled with Restricted Choke Management Has Increased EURs Gen 1 to Gen 3 Evolution Increased Intensity Has Improved EURs (EUR / 1,000 ft) (1) Gen 1 Gen 2 Gen 3 Gen 4 Period Q15 2Q15 4Q present Testing Proppant (lbs/ft) 1,500 2,600 3,700 4,000 5,000 Fluid Type Hybrid Gel Slickwater Slickwater Slickwater Stage Spacing Clusters per Stage MBoe ,500 2,600 3,700 Gen 1 Gen 2 Gen 3 Wells Completed Target Proppant (lbs/ft) Gen 3 Completions Outperforming Type Curve (12 Mo Cum) (2) IRR Sensitivity (3) % 80% 60% 91 Boe/ft 101 Boe/ft 110 Boe/ft Gen 3 Avg Boe Cumulative 91 Boe/ft Type Curve 40% Days 20% $45.00 $50.00 $55.00 $60.00 Oil Price Eagle Ford wells drilled and completed as of September 30, 2017, excluding six wells with not enough data to estimate an EUR. 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. Excludes six wells with not enough production history 3. IRR sensitivities assume $3.00 Henry Hub for the life of the well.

13 Capacity and Optionality Around Midstream, Vendor Services, Water and Sand Infrastructure Significant Midstream and Vendor Infrastructure Optionality Around Takeaway Capacity Multiple vendors for all key services provides flexibility and ample capacity Limited long term contracts Secured dedicated freshwater supply from 28 ponds and an agreement with the Brazos River Authority ~ 178 million Bbls of fresh water rights per year (~355 wells per year) Diversified sand supply with multiple sand suppliers surrounding WRD s acreage position (including several in close proximity) Close proximity to market and well-developed midstream infrastructure Infield gathering and extensive market assets in place to ensure flow and downstream connectivity Diverse physical marketing portfolio with access to Gulf Coast refining markets Proximity to market minimizes transportation cost and related commitments while maximizing margins Multiple Vendors for Key Services NM TX OK AK LA Burleson Eaglebine Express (Sunoco) Houston, TX Freshwater Pond Service Category Current Vendors Available Drilling Pressure Pumping 4 6+ Coil Tubing 2 4+ Lee Proppant Cementing 2 4+ Washington Chemicals Fuel 4 6+ Ample Water Supply 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 ($6.05) DJ Basin Comparative Basin Differentials (1) Bakken SCOOP / STACK Q3 17 oil realizations at 100% of WTI are at the high end of WRD s guidance Crude oil premium between WTI and LLS widened at the end of Q3 17 ($5.03) Permian Basin ($4.24) WRD Eagle Ford WRD entered into LLS- WTI basis swaps covering Q to secure favorable pricing Potential upside to develop an integrated midstream system to service Eagle Ford assets ($2.01) South Texas Eagle Ford ($2.65) ($0.30) 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 9/30/17. Companies included in Permian: FANG, LPI, RSPP, CXO; Companies included in Eagle Ford: CRZO, SN; Companies included in DJ Basin: PDCE and SRCI (XOG excluded due to timing of earning release); Companies included in Bakken: CLR, WLL; Companies included in SCOOP / STACK: NFX.

15 Eagle Ford Wells Outperform Competing Basins and Peers on Cash Margin Cash Margin: WRD Eagle Ford vs. Competing Basins (1) (3Q 2017) $/Boe $55.00 $44.00 $33.00 $22.00 $48.20 $48.20 $48.20 $48.20 $48.20 $7.67 $11.66 $11.52 $0.49 $16.24 $16.48 $4.84 $1.95 $1.72 $5.29 $5.07 $3.12 $0.25 $2.31 $6.20 $3.53 $8.74 $2.45 $2.45 $1.77 $48.20 Q Average WTI Price Commodity Mix Differential LOE & GP&T $11.00 $33.25 $27.44 $22.74 $22.85 $20.95 Production & Ad Valorem Taxes Cash Margin $0.00 WRD Eagle Ford Permian Bakken DJ Basin Eagle Ford % Oil 75% 62% 62% 47% 47% 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 ~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 648 net (1,413 gross) locations in North Louisiana 493 net (946 gross) RCT drilling locations 127 net (410 gross) Weyerhaeuser drilling locations ~63% IRRs for RCT Upper Red (2) Q net production of 39.0 MMcfe/d 96% natural gas High realized pricing given proximity to Henry Hub Wholly-owned midstream subsidiary enhances single-well economics Currently operating one rig 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) 4,245 LL (7/30/16) Harrison 7-18H 2-well Pad (WRD) RESTRICTED CHOKE IP30 = 20.2 MMcfe/d (100% gas) 6,802 Avg LL (5/10/17) 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 29 for assumptions embedded in North Louisiana IRR calculations.

18 North Louisiana Wells Outperform Competing Basins and Peers on Cash Margin Cash Margin: WRD North Louisiana vs. Competing Basins (1) (Third Quarter 2017) $/Mcfe $3.50 $3.39 $3.00 $2.50 $3.07 $0.12 $0.29 $0.49 $0.44 $0.62 $3.04 $0.09 $0.46 $2.95 Q Average HHUB Price $2.00 $0.18 $0.71 $0.96 Commodity Mix Differential $1.50 $0.09 $0.14 $0.07 Gathering, Processing, & Transportation (2) $1.00 $2.00 LOE $0.50 $1.54 $1.33 Production & Ad Valorem Taxes Cash Margin $0.00 WRD NLA Diversified Gas Marcellus 18 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 $2.95 third 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.

19 19 IV. Financial Overview

20 Strong Balance Sheet and Liquidity Position Capitalization ($ in millions) 9/30/2017 Cash $5 WRD Revolving Credit Facility $ % Senior Notes (1) 500 Total Debt $658 Strong Liquidity Position ($ in millions) 9/30/2017 Liquidity Borrowing Base (5) $875 Cash $5 Revolver Borrowings ($158) Total Current Liquidity $722 Series A Cum. Perpetual Convertible Preferred (2) $442 No Near Term Maturities Shareholders Equity 1,135 $900 Financial & Operating Statistics $750 Q3'17 Annualized EBITDAX $394 Q3'17 PF Annualized Interest Expense (3) 40 Q3'17 Daily Production (Mboe/d) 36.6 Credit Metrics (4) Net Debt / Q3'17 Daily Production ($/Boe/d) $17,844 $600 $450 $300 $150 $875MM Borrowing Base (5) $500MM 6.875% Senior Notes Net Debt / Q3'17 Annualized EBITDAX 1.7x Interest Coverage 9.9x $ Excludes unamortized discount and unamortized debt issuance costs 2. Excludes costs incurred related to the issuance 3. Interest Coverage calculated as EBITDAX / Interest; Interest expense represents annualized Q3 17 interest expense pro forma for the additional $150MM of 6.875% senior notes issued on September 15, Credit metrics assume 100% equity treatment for the Series A Perpetual Convertible Preferred. 5. Borrowing base as of October 5, 2017

21 FY 2017 Guidance (as of May 11, 2017) 2017 Guidance (as of May 11, 2017) Net Average Daily Production (Mboe/d) Oil (% of Production) Natural Gas (% of Production) NGLs (% of Production) Guidance Low High % - 61% 29% - 33% 9% - 11% Average Costs (per Boe) Lease Operating Expense Gathering, Processing, and Transportation Taxes Other than Income Cash General and Administrative (1) $ $3.75 $ $1.15 $ $2.25 $ $3.00 Commodity Price Realizations (Unhedged) (2) Crude Oil Realized Price (% of WTI NYMEX) Natural Gas Realized Price (% of NYMEX to Henry Hub) NGL Realized Price (% of WTI NYMEX) 95% - 100% 95% - 100% 27% - 32% Drilling Program Wells Spud (Gross) Wells Completed (Gross) D&C Capital Expenditure ($MM) $550 - $ Note: Updated guidance includes Acquisition impact 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.

22 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 Q3 17 and Q4 17, hedged ~5.3 million barrels of oil covering 2017 through 2020 During Q3 17 and Q4 17, ~6.1 million barrels of WTI-LLS oil basis covering 2017 and 2018 Hedge Summary Q Crude Oil Hedge Contracts: Total crude oil volumes hedged (Bbl) 2,089,724 8,453,084 4,948,218 1,101,762 Volumes Hedged (Bbl/d) 22,714 23,159 13,557 3,010 Total weighted-average price ($/Bbl) (1) $52.54 $51.74 $52.47 $50.19 % of Expected Production (2) 94% Natural Gas Hedge Contracts: Total natural gas volumes hedged (MMBtu) 5,692,660 11,825,800 9,877,900 Volumes Hedged (MMBtu/d) 61,877 32,399 27,063 Total weighted-average price ($/MMBtu) (1) $3.25 $3.03 $2.81 % of Expected Production (2) 89% Total Hedge Contracts (Swaps, Collars, Puts): Total hedged production (Mboe) 3,038,501 10,424,051 6,594,535 1,101,762 Volumes Hedged (Boe/d) 33,027 28,559 18,067 3,010 Total weighted-average price ($/Boe) (1) $42.21 $45.39 $43.58 $50.19 % of Expected Production (2) 85% WTI-LLS Oil Basis Hedges Volumes hedged (Bbl) 1,843,600 3,728,700 Volumes Hedged (Bbl/d) 20,039 10,216 Weighted-average price ($/Bbl) $3.98 $ Using the midpoint for collars and floors of puts. 2. Represents mid-point of guidance.

23 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 23

24 24 V. Appendix

25 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 Dec 2016 APC / KKR June 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. 25

26 WildHorse Acreage Positioned in the Highly Productive, Liquids-Rich Eagle Ford Geology matters: Gas to oil ratio Top of Eagle Ford Structural Map Gross Thickness Isopach Map 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 Milam Burleson Lee Bastrop Fayette Brazos Grimes Washington Waller Austin Oil Gravity Milam Brazos Grimes Burleson Lee Washington Fayette WRD Acreage WRD Acreage Shallow -6,000' -7,000' -8,000' -9,000' -10,000' -11,000' -12,000' -13,000' -14,000' Deep API Milam Lee Milam Lee Bastrop Grimes Brazos Burleson Washington Waller Austin Fayette Gas / Oil Ratio Brazos Grimes Burleson Washington Fayette WRD Acreage WRD Acreage 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, ' 26

27 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 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 ~$1.0 million / net location PDP Adjusted Purchase Price (1) / Net Locations (2) PDP Adjusted Purchase Price (1) / Total Acres Purchase Price / Total Acres ($ 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 27 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.

28 IRR ~2,000 Net Eagle Ford 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) $5.1 IRR (%) 47% Boe/d 1, % 80% 60% 40% 20% 91 Boe/ft Type Curve (3) Month 91 Boe/ft Type Curve Gen 3 Average Boe IRR Sensitivity (4) 91 Boe/ft 101 Boe/ft 110 Boe/ft $45.00 $50.00 Oil Price $55.00 $ Consensus Pricing as of 10/18/17: $51.05 / $3.24 for 2017, $52.25 / $3.21 for 2018, $57.50 / $3.03 for 2019, $61.00 / $3.24 for 2020, $65.00 / $3.35 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 September 30, 2017, excludes four wells with not enough production history. 4. IRR sensitivities assume $3.00 Henry Hub for the life of the well.

29 IRR 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) $9.6 IRR (%) 63% RCT Upper Red Single Well Type Curve MMcfe/d Cumulative Production (Bcfe) Restricted Rate 10, , Month Type Curve Type Curve Cum Average of Representative Wells IRR Sensitivity (2) 180% Type Curve 5% Improvement 10% Improvement 140% 100% 60% 20% $2.50 $3.00 Gas Price $3.50 $4.00 (3) Consensus Pricing as of 10/18/17: $51.05 / $3.24 for 2017, $52.25 / $3.21 for 2018, $57.50 / $3.03 for 2019, $61.00 / $3.24 for 2020, $65.00 / $3.35 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 7 for further information regarding our drilling locations.

30 WRD Perpetual Convertible Preferred Equity Summary Issuer WildHorse Resource Development Corporation (NYSE: WRD) Purchaser The Carlyle Group, through its U.S. buyout fund Carlyle Partners VI Size $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 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 Votes on an as converted basis; The Carlyle Group nominated two directors to the WRD Board 30

31 WRD Ownership Chart NGP and Management (1) The Carlyle Group $442MM Series A Perpetual Convertible Preferred Stock KKR Public Stockholders 56.1% (2) 23.9% (2) 4.2% (2) 15.9% (2) Company Shares Breakout Total Common Shares Outstanding 101,171,233 Current Float 26,623,652 Market Capitalization (3) $1,832 Fully Diluted Equity Ownership Pro Forma (2) % Shares Series A Perpetual Convertible Preferred (Carlyle) 23.9% 31,764,245 KKR 4.2% 5,518,125 NGP + Management 56.1% 74,547,581 Public 15.9% 21,105,527 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. Pro Forma for impact of $442mm Series A Perpetual Convertible Preferred Stock. 3. As of November 7, 2017; Includes $442mm Series A Perpetual Convertible Preferred Stock. 31

32 Crude Oil Hedge Summary Q Crude Oil Hedge Contracts: Swap contracts: Volume (MBbl) 1,303 6,834 4,538 1,102 Volume (Bbl/d) 14,159 18,725 12,432 3,010 Weighted-average fixed price $51.04 $52.31 $52.69 $50.19 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) 773 1, Volume (Bbl/d) 8,407 4,366 1,125 Weighted-average floor price $55.00 $49.23 $50.00 Weighted-average put premium ($4.77) ($4.61) ($5.95) Total Crude Oil Hedge Contracts (Swaps, Collars, Puts): Total crude oil volumes hedged (MBbl) 2,090 8,453 4,948 1,102 Total crude oil volumes hedged (Bbl/d) 22,714 23,159 13,557 3,010 Total Weighted-Average Price Total weighted-average price (excluding puts) (1) $51.09 $52.32 $52.69 $50.19 Total weighted-average price (including puts) (1) $52.54 $51.74 $52.47 $50.19 WTI-LLS Oil Basis Hedges Volumes hedged (Bbl) 1,843,600 3,728,700 Volumes Hedged (Bbl/d) 20,039 10,216 Weighted-average price ($/Bbl) $3.98 $ Using the midpoint for collars. 32

33 Natural Gas Hedge Summary Q Gas Hedge Contracts: Swap contracts: Volume (BBtu) 1,910 11,826 9,878 Volume (MMBtu/d) 20,757 32,399 27,063 Weighted-average fixed price $3.10 $3.03 $2.81 Collar contracts: Volume (BBtu) 1,380 Volume (MMBtu/d) 15,000 Weighted-average floor price $3.00 Weighted-average ceiling price $3.36 Put options (bought): Volume (BBtu) 2,403 Volume (MMBtu/d) 26,120 Weighted-average floor price $3.40 Weighted-average put premium ($0.37) Total Gas Hedge Contracts: Total gas volumes hedged (BBtu) 5,693 11,826 9,878 Total gas volumes hedged (MMBtu/d) 61,877 32,399 27,063 Total Weighted-Average Price Total weighted-average price (excluding puts) (1) $3.13 $3.03 $2.81 Total weighted-average price (including puts) (1) $3.25 $3.03 $ Using the midpoint for collars. 33

34 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 third quarter of 2017 and 2016 EBITDAX to the most comparable measure calculated in accordance with GAAP: For the Three Months Ended September 30, (Amounts in $000s) Net Income (Loss) $ (10,804) $ 3,057 Add (Deduct): Interest expense, net 8,749 1,856 Income tax (benefit) expense (5,646) 200 Depreciation, depletion and amortization 51,843 19,418 Exploration expense 4,749 1,453 (Gain) loss on derivative instruments 40,288 (3,670) Cash settlements received / (paid) on commodity derivatives 5, Stock-based compensation 2,414 - Acquisition related costs Initial public offering costs - 1,182 Non-cash liability amortization - - Adjusted EBITDAX $ 98,393 $ 23,717 34

35 Cautionary Statements and Additional Disclosures This presentation has been prepared by WildHorse and includes market data and other statistical information from sources believed by WildHorse to be reliable, including independent industry publications, government publications or other published independent sources. Some data is also based on WildHorse s good faith estimates, which are derived from its review of internal sources as well as the independent sources described herein. Although WildHorse believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy and completeness. PV-10 and 3P Reserves PV-10 is a non-gaap financial measure and represents the period-end present value of estimated future cash inflows from WRD s natural gas and crude oil reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using SEC pricing assumptions in effect at the end of the period. SEC pricing for oil and natural gas of $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. 35

36 Cautionary Statements and Additional Disclosures WRD has provided summations of its proved, probable and possible reserves and summations of its PV-10 for its proved, probable and possible reserves in this presentation. The SEC strictly prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. Investors should be cautioned that estimates of PV-10 of probable reserves, as well as the underlying volumetric estimates, are inherently more uncertain 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. 36