Company Presentation October 2, 2017

Transcription

1 Company Presentation October 2, 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: 61% in 2017E (4) and 83% in 2018E based on updated analyst estimates Outperforming Eagle Ford Type Curve: 41 Gen 3 wells averaging 101 boe/ft (5), 11% above our 91 boe/ft Eagle Ford type curve Conservative Balance Sheet: Net Debt / Q2 17 PF annualized EBITDAX of 1.8x (6) Attractive Hedging Profile: 75% of 2H 17 production hedged with additional hedges in Significant Management Ownership: Management team is highly aligned with shareholders Catalysts Ahead: Additional Gen 3 wells, testing Gen 4 design, further evaluation of the Austin Chalk, refracs and testing two Eagle Ford landing zones Premier Acreage Positions in the Eagle Ford and North Louisiana Total Company Net Acres (1) ~484,000 Proved Reserves (MMboe) (2) % Liquids 68% % Oil 59% Q Production (Mboe/d) 22.6 % Liquids 65% 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) 16.1 % Liquids 90% Drilling Locations: Gross 4,416 Net 2,651 Single-well IRR (3) 46% 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) ~99,000 Proved Reserves (Bcfe) (2) % Gas 98% Q Production (MMcfe/d) 39.1 % Gas 96% Drilling Locations: Gross 1,413 Net 648 Single-well IRR (3) 61% Attractive Valuation: Meaningful valuation discount to peers on 2017 and 2018 EV/EBITDAX 4 Note: Q daily production excludes assets acquired from Anadarko Petroleum Corporation and affiliates of KKR ( Acquisition ); drilling locations pro forma for Acquisition. 1. Includes acreage that WildHorse has the right to lease within the Terryville Complex. 2. Reserve data as of December 31, 2016; includes 22.9 MMBoe in PDP reserves from Acquisition (audited proved reserves not currently available). 12/31/16 reserve report audited by Cawley, Gillespie & Associates ( CGA ). 3. See slides 28 and 29 for assumptions embedded in WildHorse IRR calculations. IRR based on consensus Pricing as of 8/2/ E growth rates based on 2016 production pro forma for Clayton Williams acquisition. 5. Eagle Ford wells drilled and completed as of June 30, 2017, excluding six wells with not enough production data to estimate an EUR. 6. Q2 17 annualized EBITDAX pro forma for Acquisition.

5 Q and Recent Activity Highlights Increased average daily production by 55% to 22.6 Mboe/d for the second quarter 2017 compared to 14.6 Mboe/d for the second quarter 2016 Reported adjusted EBITDAX of $52.4 million for the second quarter 2017 compared to $21.7 million for the second quarter 2016 Closed financing of $435 million Series A Perpetual Convertible Preferred Stock Increased borrowing base on WRD s credit facility to $650 million from $450 million Continued Eagle Ford Gen 3 Outperformance 41 gross Gen 3 wells online averaging a 101 boe per foot EUR (1), which is 11% above the current 91 boe per foot type curve 10 gross wells online on the Clayton Williams acquisition acreage with the average of the wells exceeding a 91 boe per foot type curve Brought online 3 gross wells on acreage without assigned locations Brought online 6 gross wells adjacent to the Acquisition acreage with the average of the wells exceeding a 91 boe per foot type curve Successful Austin Chalk Well Strong Balance Sheet and Hedging Program Brought online first Austin Chalk well in Washington County, the Winkelmann #1H, at an IP-30 of 2,387 boe/d (26% oil, 38% natural gas, and 36% natural gas liquids) Given the success of this well, WRD plans further delineation and testing of its Austin Chalk position East Texas position includes 285,000 net acres with legacy Austin Chalk wells and an additional 100,000 net acres of undeveloped Austin Chalk Net debt / Q2 17 annualized EBITDAX of 1.8x (2) $517 million of liquidity at June 30, % of consensus 2H 17 production hedged (peer group at 54%) (3) 43% of consensus 2018 production hedged (peer group at 32%) (3) 6.5 MMboe of production hedged in Eagle Ford Acquisition Acquired ~111,000 net acres and 7.6 Mboe/d (Q4 16) of net production from Anadarko Petroleum and affiliates of KKR for $594 million Acquisition closed June 30, 2017 Post acquisition, WRD operates the second largest Eagle Ford position with ~385,000 net acres Acquisition added 711 net locations in the Eagle Ford 91 Boe/ft type curve area with attractive single-well IRRs of 46% (4) 5 1. Eagle Ford wells drilled and completed as of June 30, 2017, excluding six wells with not enough data to estimate an EUR. 2. Q2 17 annualized EBITDAX pro forma for Acquisition. 3. WRD hedging as of August 4, 2017; Peer group hedging based on most recently available public information. 4. See slide 28 for assumptions embedded in Eagle Ford IRR calculation. IRR based on Consensus Pricing as of 8/2/17: $51.16 / $3.16 for 2017, $54.90 / $3.14 for 2018, $58.00 / $3.05 for 2019, $62.50 / $3.24 for 2020, $66.50 / $3.40 for 2021 and thereafter for WTI and Henry Hub, respectively.

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 Austin Chalk in Burleson County; Buda, Woodbine, Georgetown and Pecan Gap across much of our Eagle Ford acreage Testing a stack/stagger development of the Upper and Lower Eagle Ford $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 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 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.

8 Leading Industry Metrics at a Compelling Valuation Enterprise Value / EBITDAX Production Growth EBITDAX Growth x 8.1x 100% 80% 83% 200% 160% 172% x 60% 61% 48% 120% 106% x 40% 20% 33% 80% 40% 64% 44% 0.0 EV/2017E EBITDAX WRD EV/2018E EBITDAX Peer Group 0% 2017E Growth Rate (1) WRD 2018E Growth Rate Peer Group 0% 2017E Growth Rate 2018E Growth Rate WRD Peer Group YE Net Debt / EBITDAX % Hedged Total Production (2) % Hedged Oil Production (2) x 2.7x 1.3x 2.2x 80% 40% 73% 54% 43% 32% 100% 80% 60% 40% 79% 59% 56% 31% 20% E WRD 2018E Peer Group 0% Rem WRD Peer Group 0% Rem WRD Peer Group 8 Note: Enterprise value based on closing stock price as of August 3, 2017; Peer group includes:cpe, CRZO, EGN, LPI, MTDR, OAS, PDCE, PE, QEP, RSPP, SM, SN, SRCI, WPX AND XOG. Based on FactSet consensus estimates as of August 3, E growth rates based on 2016 production pro forma for Clayton Williams acquisition. 2. Both WRD and peer group production based on consensus estimates as of August 3, WRD hedging as of August 4, 2017; Peer group hedging based on most recently available public information.

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% 75% 74% 71% 71% 65% 64% 62% 61% 60% 59% 58% 57% 55% 54% 53% 60% 45% 52% 49% 48% 45% 30% 15% 0% CLR WRD SM RSPP GPOR COG EOG OAS DVN EPE NFX APC WLL SWN WPX RRC ECR AR 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. Chart data as of May Source: Guggenheim Securities Equity Research. Guggenheim Research defines EBITDAX Margin as EBITDAX (Revenue, plus/minus realized hedging, minus LOE, minus production and ad valorem tax, minus gathering, processing and transportation expense, minus general and administrative expense (excluding non-cash compensation)) divided by revenue (including realized hedging). Chart data as of August 2017.

10 10 II. Eagle Ford Overview

11 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 41 gross Gen 3 wells online averaging a 101 boe per foot EUR (1) Current Eagle Ford producing wells exist across entire ~800 square mile area 10 gross wells online on the Clayton Williams acquisition acreage with the average of the wells exceeding a 91 boe per foot type curve (2) Brought online 6 gross wells adjacent to the Acquisition acreage with the average of the wells exceeding a 91 boe per foot type curve Gen 3 Completions Outperforming Type Curve (6 Mo Cum) (4) Altimore #1H EUR: 126 Boe/Ft IP30 = 1,048 BOE/D (84% oil) 6,435 LL (3/31/2017) 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) Horizontal Well Activity (3) 100,000 80,000 60,000 40,000 Farmer s North #1H IP30 = 682 BOE/D (94% oil) 6,463 LL (6/18/17) Drilled on WRD acreage w/o assigned locations Winkelmann #1H (Austin Chalk) IP30 = 2,387 BOE/D (26% oil) 4,762 LL (6/3/17) WildHorse Cooper B #1H EUR: 107 Boe/Ft IP30 = 576 BOE/D (85% oil) 4,780 LL (2/22/17) Legacy EF HZ Well Mach A #2H EUR: 111 Boe/Ft IP30 = 607 BOE/D (64% oil) 6,672 LL (2/22/17) 0 20 Miles WRD Acreage with Locations Additional WRD Acreage (5) Belmont Stakes #1H EUR: 135 Boe/Ft IP30 = 740 BOE/D (65% oil) 5,831 LL (10/1/16) 20,000 IRR Sensitivity at Consensus Price Deck (6) Days Gen 3 Avg Boe Cum (41 wells) 91 Boe/ft Type Curve EUR (Boe / Ft) % 56% 70% 84% 100% 120% Eagle Ford wells drilled and completed as of June 30, 2017, excluding six wells with not enough data to estimate an EUR. 2. Excludes three wells with not enough data to estimate an EUR. 3. Data for WildHorse based on actual results reported by WildHorse management. The initial production rates represent the peak average of the IP rates for the applicable consecutive days of production; IP rates are not normalized for lateral length. Dates are first production. 4. The first day of the peak IP30 rate is considered day 1 of cumulative production. Data is normalized for 6,500 laterals, downtime, and irregular production. Excludes three wells with not enough production history. 5. Represents ~130,000 net acres with no locations assigned actively delineating. 6. See slide 28 for assumptions embedded in Eagle Ford IRR calculation. IRR based on Consensus Pricing as of 8/2/17: $51.16 / $3.16 for 2017, $54.90 / $3.14 for 2018, $58.00 / $3.05 for 2019, $62.50 / $3.24 for 2020, $66.50 / $3.40 for 2021 and thereafter for WTI and Henry Hub, respectively.

12 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 have not reached the limits 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 EUR Improvement EUR / Ft Oil Price (BOE) % $40.00 $45.00 $50.00 $55.00 $ % 19% 27% 37% 47% 59% % 25% 35% 46% 59% 72% % 32% 45% 59% 74% 93% % 41% 55% 72% 92% 114% % 49% 67% 88% 111% 140% % 60% 80% 105% 134% 172% Wells Completed Target Proppant (lbs/ft) 1. Eagle Ford wells drilled and completed as of June 30, 2017, excluding six wells with not enough data to estimate an EUR. 2. IRR sensitivities assume $3.00 Henry Hub for the life of the well. 12

13 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 ($7.14) 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 ($4.59) Permian Basin ($5.63) WRD Eagle Ford ($3.74) ($1.36) ($2.87) South Texas Eagle Ford U.S. Shale Basins WTI Cushing # Basin Differential 13 Source: Corporate Filings and Company Data. 1. Differentials based on average realized $/Bbl for the three months ended 6/30/17. Companies included in Permian: FANG, LPI, RSPP, CXO; Companies included in Eagle Ford: CRZO, SN; Companies included in DJ Basin: PDCE and SRC (XOG excluded due to timing of earning release); Companies included in Bakken: CLR, WLL; Companies included in SCOOP / STACK: NFX.

14 Eagle Ford Wells Outperform Competing Basins and Peers on Cash Margin Cash Margin: WRD Eagle Ford vs. Competing Basins (1) (2Q 2017) $/Boe $55.00 $44.00 $33.00 $22.00 $48.15 $48.15 $48.15 $48.15 $48.15 $7.16 $10.99 $11.43 $1.36 $15.51 $3.99 $17.61 $3.28 $2.47 $6.36 $4.64 $1.55 $2.13 $6.28 $8.07 $4.58 $2.10 $2.53 $1.54 $2.54 $48.15 Q Average WTI Price Commodity Mix Differential LOE & GP&T $11.00 $33.17 $27.12 $21.54 $21.48 $21.34 Production & Ad Valorem Taxes Cash Margin $0.00 WRD Eagle Ford Permian Bakken Eagle Ford DJ Basin 14 Source: Company filings and investor presentations. Note: Assumes 6:1 gas to oil ratio. Commodity mix represents the difference between average WTI price and the weighted average commodity price per boe of the company s production (using Henry Hub for gas and assuming NGL pricing equal to 35% of WTI). Does not include G&A and other corporate level costs. 1. Companies included in Permian: CXO, FANG, LPI and RSPP; Companies included in Eagle Ford: CRZO and SN; Companies included in DJ Basin: PDCE and SRC (XOG excluded due to timing of earnings release); Companies included in Bakken: CLR and WLL.

15 15 III. North Louisiana Overview

16 North Louisiana Acreage Position Contiguous Position in the Prolific Terryville Field ~99,000 net acres across four areas in North Louisiana Ruston-Choudrant- Tremont ( RCT ) Field, Weyerhaeuser, Bear Creek and Athens Geologically analogous to RRC s Terryville Field Drilled 15 operated horizontal wells to date Management drilled 55 wells for MRD / RRC prior to turning over operation in January net (1,413 gross) locations in North Louisiana 493 net (946 gross) RCT drilling locations 127 net (410 gross) Weyerhaeuser drilling locations ~61% IRRs for RCT Upper Red (2) Q net production of 39.1 MMcfe/d 96% natural gas High realized pricing given proximity to Henry Hub Wholly-owned midstream subsidiary enhances single-well economics Currently operating two rigs 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.

17 North Louisiana Wells Outperform Competing Basins and Peers on Cash Margin Cash Margin: WRD North Louisiana vs. Competing Basins (1) (Second Quarter 2017) $/Mcfe $4.00 $3.50 $3.00 $3.30 $0.12 $0.32 $3.55 $0.41 $0.50 $3.19 $0.05 $0.31 $3.14 Q Average HHUB Price $2.50 $2.00 $1.50 $0.52 $0.25 $0.69 $0.09 $0.96 $0.14 $0.07 Commodity Mix Differential Gathering, Processing, & Transportation (2) $1.00 $0.50 $2.09 $1.87 $1.66 LOE Production & Ad Valorem Taxes Cash Margin $0.00 WRD NLA Diversified Gas Marcellus 17 Source: Company filings and investor presentations. Note: Assumes 6:1 gas to oil ratio. Commodity mix assumes NGLs at 35% of WTI. Due to commodity mix, company and basin Mcfe prices surpass the $3.14 second quarter 2017 average HHUB Price. Does not include G&A and other corporate level costs. 1. Companies included in Marcellus: RICE, EQT, AR, COG, RRC. Companies included in Diversified Gas: SWN, CHK. 2. Gathering, Processing, & Transportation fees exclude intercompany eliminations for non-wholly owned consolidated subsidiaries. 3. Includes GP&T expense.

18 18 IV. Financial Overview

19 Strong Balance Sheet and Liquidity Position Capitalization ($ in millions) 6/30/2017 Cash $15 WRD Revolving Credit Facility $ % Senior Notes 350 Total Debt $496 Strong Liquidity Position ($ in millions) 6/30/2017 Liquidity Borrowing Base $650 Cash $15 Revolver Borrowings ($146) Letters of Credit (2) Total Current Liquidity $517 Series A Cum. Perpetual Convertible Preferred $435 Shareholders Equity 1,150 Financial & Operating Statistics Q2'17 PF Annualized EBITDAX (1) $265 Interest Expense (2) 30 Q2'17 PF Daily Production (Mboe/d) (1) 29.1 Credit Metrics (3) Net Debt / Q2'17 PF Daily Production ($/Boe/d) $16,542 Net Debt / Q2'17 PF Annualized EBITDAX (1) 1.8x Interest Coverage 9.0x $700 $600 $500 $400 $300 $200 $100 $0 No Near Term Maturities $650MM Revolver $350MM 6.875% Senior Notes Q pro forma for Acquisition 2. Interest Coverage calculated as EBITDAX / Interest; Interest expense represents annualized Q reported interest expense plus interest expense for $99 million of credit agreement borrowings used in the Acquisition 3. Credit metrics assume 100% equity treatment for the Series A Perpetual Convertible Preferred.

20 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 20

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 Q2 17, hedged over 4 million barrels of oil covering 2018 and 2019 through swaps and deferred puts During Q3 17, hedged ~ 4.6 million barrels of oil covering 2017 through 2020 at approximately $50 per barrel Hedge Summary Q3-Q Crude Oil Hedge Contracts: Total crude oil volumes hedged (Bbl) 3,599,787 6,859,584 4,537, ,620 Volumes Hedged (Bbl/d) 19,564 18,793 12, Total weighted-average price ($/Bbl) (1) $52.58 $52.35 $52.64 $50.15 % of Expected Production (2) 83% Natural Gas Hedge Contracts: Total natural gas volumes hedged (MMBtu) 9,731,708 11,565,800 9,877,900 Volumes Hedged (MMBtu/d) 52,890 31,687 27,063 Total weighted-average price ($/MMBtu) (1) $3.22 $3.03 $2.81 % of Expected Production (2) 84% Total Hedge Contracts: Total hedged production (Mboe) 5,221,738 8,787,217 6,184, ,620 Volumes Hedged (Boe/d) 28,379 24,075 16, Total weighted-average price ($/Boe) (1) $42.25 $44.85 $43.12 $50.15 % of Expected Production (2) 75% 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 ~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) $5.0 IRR (%) 46% EUR Improvement Boe/d 1, Boe/ft Type Curve (3) Month EUR / 1,000 Ft 91 Boe/ft Type Curve Gen 3 Average Boe IRR Sensitivity (4) Oil Price (MBOE) % $40.00 $45.00 $50.00 $55.00 $ % 19% 27% 37% 47% 59% % 25% 35% 46% 59% 72% % 32% 45% 59% 74% 93% % 41% 55% 72% 92% 114% % 49% 67% 88% 111% 140% % 60% 80% 105% 134% 172% Consensus Pricing as of 8/2/17: $51.16 / $3.16 for 2017, $54.90 / $3.14 for 2018, $58.00 / $3.05 for 2019, $62.50 / $3.24 for 2020, $66.50 / $3.40 for 2021 and thereafter for WTI and Henry Hub, respectively. 2. See slide 7 for further information regarding our drilling locations. 3. Eagle Ford wells drilled and completed as of June 30, 2017, excludes three wells with not enough production history. 4. IRR sensitivities assume $3.00 Henry Hub for the life of the well.

29 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) $9.5 IRR (%) 61% 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 8/2/17: $51.16 / $3.16 for 2017, $54.90 / $3.14 for 2018, $58.00 / $3.05 for 2019, $62.50 / $3.24 for 2020, $66.50 / $3.40 for 2021 and thereafter for WTI and Henry Hub, respectively. Excludes inter-company gathering fees to wholly-owned midstream system. 2. IRR sensitivities assume $50.00 WTI for the life of the well. 3. Representative wells include the Smelley 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 Ownership Chart NGP and Management (1) The Carlyle Group $435MM Series A Perpetual Convertible Preferred Stock KKR Public Stockholders 56.3% (2) 23.6% (2) 4.2% (2) 15.9% (2) Company Shares Breakout Total Common Shares Outstanding 101,135,300 Current Float 26,623,652 Market Capitalization (3) $1,695 Fully Diluted Equity Ownership Pro Forma (2) % Shares Series A Perpetual Convertible Preferred (Carlyle) 23.6% 31,294,964 KKR 4.2% 5,518,125 NGP + Management 56.3% 74,511,648 Public 15.9% 21,105,527 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 $435mm Series A Perpetual Convertible Preferred Stock. 3. As of August 4, 2017; Includes $435mm Series A Perpetual Convertible Preferred Stock. 30

31 Crude Oil Hedge Summary Oil Hedge Summary Q3-Q Crude Oil Hedge Contracts: Swap contracts: Volume (MBbl) 2,357 6,237 4, Volume (Bbl/d) 12,807 17,087 11, Weighted-average fixed price $51.29 $52.55 $52.91 $50.15 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) 6,603 1,638 1,125 Weighted-average floor price $55.00 $50.00 $50.00 Weighted-average put premium ($4.77) ($5.95) ($5.95) Total Crude Oil Hedge Contracts: Total crude oil volumes hedged (MBbl) 3,600 6,860 4, Total crude oil volumes hedged (Bbl/d) 19,564 18,793 12, Total Weighted-Average Price Total weighted-average price (excluding puts) (1) $51.34 $52.57 $52.91 $50.15 Total weighted-average price (including puts) (1) $52.58 $52.35 $52.64 $ Using the midpoint for collars. 31

32 Natural Gas Hedge Summary Gas Hedge Summary Q3-Q Gas Hedge Contracts: Swap contracts: Volume (BBtu) 4,001 11,566 9,878 Volume (MMBtu/d) 21,742 31,687 27,063 Weighted-average fixed price $3.12 $3.03 $2.81 Collar contracts: Volume (BBtu) 2,760 Volume (MMBtu/d) 15,000 Weighted-average floor price $3.00 Weighted-average ceiling price $3.36 Put options (bought): Volume (BBtu) 2,971 Volume (MMBtu/d) 16,148 Weighted-average floor price $3.40 Weighted-average put premium ($0.37) Total Gas Hedge Contracts: Total gas volumes hedged (BBtu) 9,732 11,566 9,878 Total gas volumes hedged (MMBtu/d) 52,890 31,687 27,063 Total Weighted-Average Price Total weighted-average price (excluding puts) (1) $3.14 $3.03 $2.81 Total weighted-average price (including puts) (1) $3.22 $3.03 $ Using the midpoint for collars. 32

33 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 second quarter of 2017 and 2016 EBITDAX to the most comparable measure calculated in accordance with GAAP: For the Three Months Ended June 30, (Amounts in $000s) Net Income (loss) $ 26,366 $ (18,281) Add (Deduct): Interest expense, net 6,633 1,781 Income tax (benefit) expense 15, Depreciation, depletion and amortization 33,229 19,923 Exploration expense 11, (Gain) loss on derivative instruments (46,116) 15,610 Cash settlements received / (paid) on commodity derivatives 2,076 2,525 Stock-based compensation 1,308 - Acquisition related costs 2, Debt extinguishment costs - - Initial public offering costs - - Non-cash liability amortization - (103) Adjusted EBITDAX $ 52,392 $ 21,718 33

34 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. 34

35 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. 35

36 Cautionary Statements and Additional Disclosures Cash General and Administrative Expenses per Boe Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-gaap measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. Calculation of Net Debt Net Debt is a supplemental non-gaap financial measure that is used by external users of WRD s financial statements. We define Net Debt as total debt minus cash and cash equivalents. We believe Net Debt is useful to investors because it provides readers with a more meaningful measure of our outstanding indebtedness. However, this measure is provided in addition to, not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP. 36