East Texas Eagle Ford Acquisition May 2017

Transcription

1 East Texas Eagle Ford Acquisition May 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; ability to consummate pending acquisitions; 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. Please see Cautionary Statements and Additional Disclosures below for more information. Information in this presentation is accurate as of March 31, 2017, unless otherwise noted. 1

3 Acquisition Overview Transaction Summary On May 11, 2017, WRD announced a $625 million acquisition of ~111,000 net acres in,, Robertson, Milam, and counties from Anadarko Petroleum Corporation ( Anadarko or APC ) and affiliates of Kohlberg Kravis Roberts & Co. L.P. ( KKR ) $625 million acquisition consideration includes: $121 million revolving credit facility borrowings ~$69 million in common shares issued to KKR at closing, ~6.3 million shares $435 million in Series A Perpetual Convertible Preferred Stock issued at closing to The Carlyle Group, through its U.S. buyout fund Carlyle Partners VI Target closing date of June 30, 2017 with an effective date of January 1, 2017 Asset Highlights ~111,000 net acres with an average 8/8 th NRI of ~80% ~95% held-by-production 22.9 MMBoe proved developed producing (PDP) reserves (73% oil and 88% liquids) Pro forma Eagle Ford position of 385,000 net acres Expect to allocate a portion of our 2017 development program to higher working interest wells in and around the acquired acreage Single-well IRRs consistent with existing Gen 3 Eagle Ford wells Attractive 55% single-well IRR for 91 Boe/ft type curve (1) 949 net locations with 711 of the net locations in the Eagle Ford 91 Boe/ft type curve areas 4Q16 production of ~7.6 MBoe/d (~54% Eagle Ford) from 68 Eagle Ford, 299 Austin Chalk and 19 Buda/Georgetown operated wells Total WRD 1Q17 status quo production of 17.6 MBoe/d; pro forma total production of 25.2 MBoe/d (2) Legacy acquired wells were completed with Gen 1 style fracs utilizing, on average, ~1,100 lbs / ft of proppant Average EUR of 44 Boe/ft for existing Eagle Ford wells (less than half of the WRD 91 Boe/ft type curve) Significant future refrac opportunities High Oil Cut Milam 0 20 Miles Fayette Carbonate Rich Attractive Oil Gravity High Pore Pressure Asset Overview Robertson WildHorse Acquisition Geologic Criteria WRD Eagle Ford WRD APC / KKR Acquisition Austin APC / KKR Acquisition 2 1. See slide 14 for assumptions embedded in Eagle Ford IRR calculation. IRR based on Consensus Pricing as of 4/26/2017: $54.00 / $3.15 for 2017, $60.00 / $3.11 for 2018, $61.00 / $3.09 for 2019, $66.50 / $3.25 for 2020, $70.00 / $3.45 for 2021 and thereafter for WTI and Henry Hub, respectively. 2. WRD status quo Q reported production; announced acquisition adjustment based on Q production.

4 Compelling Rationale for Transformative Acquisition Largely undeveloped acreage contiguous to the existing Eagle Ford position Adds Significant Scale ~111,000 net acres in the Eagle Ford Increases total Eagle Ford acres by 40% Direct bolt-on helps mitigate planning issues around partially owned units Pro forma total WRD daily production of approximately 25.2 MBoe/d (1) High Quality Eagle Ford Inventory Liquidity Enhancing and Credit Neutral Midstream Infrastructure in Place Single-well IRRs consistent with existing Gen 3 Eagle Ford wells 711 net locations in the Eagle Ford 91 Boe/ft type curve area with attractive single-well IRRs of 55% (2) Average 8/8 ths NRI of ~80% Current Gen 3 wells outperforming the Eagle Ford type curve by ~11% Expect to allocate a portion of our 2017 development program to higher working interest wells in and around the acquired acreage Solid PDP base with acquired 4Q16 production of ~7.6 MBoe/d (89% liquids) Financing structure supports liquidity and ability to fund development plan; expected pro forma liquidity after giving effect to the acquisition but not any borrowing base increase of ~$620mm Net debt / Annualized EBITDAX (3) remains approximately 1.9x pro forma for the acquisition 62% of remaining 2017E pro forma production hedged at attractive prices (4) Pipeline infrastructure in place Takeaway capacity leads to low differentials Competitive advantage on water cost Additional Upside Second landing target in the Eagle Ford with potential downspacing opportunities adds significant upside Additional upside potential in other horizons: Austin Chalk, Georgetown, Buda, Pecan Gap and Woodbine Refrac potential on initial understimulated Eagle Ford wells with an average of 1,100 lbs / ft gel fracs 3 1. WRD status quo Q reported production; announced acquisition adjustment based on Q production. 2. WRD location count for acquisition based on 500 spacing and includes only net locations located in the 91 Boe/ft type curve area. See slide 14 for assumptions embedded in Eagle Ford IRR calculation. IRR based on Consensus Pricing as of 4/26/2017: $54.00 / $3.15 for 2017, $60.00 / $3.11 for 2018, $61.00 / $3.09 for 2019, $66.50 / $3.25 for 2020, $70.00 / $3.45 for 2021 and thereafter for WTI and Henry Hub, respectively. 3. See Net Debt and EBITDAX reconciliations on page 23 and 25. WRD status quo Q reported EBITDAX; announced acquisition adjustment based on Q EBITDAX. 4. Based on midpoint of updated FY 2017 guidance.

5 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 January st CWEI Acquisition June 2015 Comstock Acquisition July 2015 September 2015 (1) Formation Previous Position 1 st CWEI Acquisition Previous Position Comstock Acquisition Previous Position 2 nd CWEI Acquisition Dec 2015 Organic Leasing / Acreage Swaps 3 rd CWEI Acquisition Oct 2016 APC / KKR May 2017 Previous Position 2 nd CWEI Acquisition Previous Position Organic Leasing / Swaps Previous Position 3 rd CWEI Acq. Previous Position APC / KKR Acq Miles 1. Includes three acquisitions in County that occurred over ~12 months. 4

6 Announced Transaction Similar to Clayton Williams Combined acquisition price of ~$1.025 billion for 269,000 net acres or ~$2,100/net acre (1) Acquisition Comparison CWEI Acquisition Announced Acquisition Purchase Price $400 million $625 million Large Adjacent Acreage Position ~158,000 Net Acres ~111,000 Net Acres Production (2) ~3.9 MBoe/d ~7.6 MBoe/d Net Locations in 91 Boe/ft Type Curve Inventory (3) High Oil / Liquids Cut (2) 80% Oil / 87% Liquids 72% Oil / 89% Liquids Comparable Geologic Properties & Economics to WRD Eagle Ford Developed Midstream and Water Infrastructure Expands 91 Boe/ft Type Curve Inventory 5 1. Assuming $40,000 per flowing barrel for acquired PDP production. 2. Based on CWEI Q production and announced acquisition Q production. 3. WRD location counts based on 500 spacing and include only net locations located in the 91 Boe/ft type curve area.

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

8 WRD EF Acquisitions Hawkwood / Halcon Venado / Exco SCOOP / STACK Permian Basin WRD EF Acquisitions Venado / Exco Hawkwood / Halcon SCOOP / STACK Permian Basin WRD EF Acquisitions Venado / Exco Hawkwood / Halcon SCOOP / STACK Permian Basin WRD s Attractive Eagle Ford Acquisition Metrics Bolster Full Cycle Returns WRD has agreed to acquire Eagle Ford acreage at attractive economics per net location on a PDP-adjusted basis Over its last two major Eagle Ford acquisitions, WRD has averaged ~$420,000 / net location for 1,348 net locations Since 1/1/2016, acquisitions in the Permian Basin have averaged ~$1.8 million / net location and transactions in the SCOOP / STACK have averaged ~$1.0 million / net location PDP Adjusted Purchase Price (1) / Net Locations PDP Adjusted Purchase Price (1) / Total Acres Purchase Price / Total Acres ($ 000's / location) ($ / acre) ($ / acre) $2,000 ~$1,750 $30,000 ~$27,000 $40,000 $1,600 $25,000 $30,000 ~$31,250 $1,200 $944 ~$1,000 $20,000 $15,000 $20,000 $800 $400 $420 $650 $10,000 $5,000 $2,103 $2,674 $3,230 ~$7,000 $10,000 $3,810 $5,899 $6,211 ~$9,500 $0 $0 $0 7 Note: WRD location counts for APC / KKR and CWEI acquisitions based on 500 spacing and include only net locations located in the 91 Boe/ft type curve area. Permian and SCOOP / STACK represent average of transactions from 1/1/2016 to 3/31/2017 based on Company Investor Presentations, Company Filings and published reports. 1. Purchase Price adjusted for production at $40,000 Boe/d.

9 Eagle Ford Growth: Significant, High-Quality Scale Eagle Ford Net Acres Eagle Ford Net Locations 4Q16 Eagle Ford Daily Production (Net Acres in 000s) (Locations) (MBoe/d) ,000 2, , ,000 1, , , WRD EF Status Quo WRD EF Pro Forma 0 WRD EF Status Quo WRD EF Pro Forma 0 WRD EF Status Quo WRD EF Pro Forma 8

10 Cumulative Production (Boe) Recent Well Results Outperform and Delineate Extensive Acreage Position WRD Gen 3 wells continue to outperform 91 Boe/ft type curve across the acreage position >80% of Gen 3 wells drilled to date are performing above 91 Boe / ft type curve EUR Current Eagle Ford producing wells exist across entire ~800 square mile area Jackson #1H EUR: 110+ Boe/Ft IP30= 958 BOE/D (85% oil) 6,297 LL (3/27/2017) Horizontal Well Activity (1) 120,000 Gen 3 Completions Outperforming Type Curve (6 Mo Cum) (2) Altimore #1H EUR: 120+ Boe/Ft IP30 = 1,048 BOE/D (84% oil) 6,435 LL (3/31/2017) 100,000 80,000 Candace #1H EUR: 138 Boe/Ft IP30 = 1,081 BOE/D (88% oil) 7,481 LL (9/2/16) 60,000 40,000 20,000 Paul 134 Unit #2H EUR: 130+ Boe/Ft IP30 = 1,035 BOE/D (93% oil) 5,363 LL (3/8/17) Cooper B #1H EUR: 107 Boe/Ft IP30 = 576 BOE/D (85% oil) 4,780 LL (12/12/16) WildHorse Mach A #2H EUR: 111 Boe/Ft IP30 = 607 BOE/D (64% oil) 6,672 LL (2/22/17) 3 rd Party EF HZ Well Belmont Stakes #1H EUR: 135 Boe/Ft IP30 = 740 BOE/D (65% oil) 5,831 LL (10/1/16) 0 20 Miles WRD Acreage with Locations Additional WRD Acreage (3) Kentucky Derby #1H EUR: 100 Boe/Ft IP30 = 594 BOE/D (55% oil) 5,126 LL (10/1/16) Days Gen 3 Avg Boe Cum (23 wells) 91 Boe/ft Main Type Curve Type Curve Recent Candace Gen #1H 3 Well Results IRR Sensitivity at Consensus Price Deck (4) EUR (Boe / Ft) % 68% 84% 100% 121% 145% 9 1. Data for WildHorse based on actual results reported by WildHorse management. The initial production rates represent the peak average of the IP rates for the applicable consecutive days of production; IP rates are not normalized for lateral length. Dates are first production. 2. The first day of the peak IP30 rate is considered day 1 of cumulative production. Data is normalized for 6,500 laterals, downtime, and irregular production. 3. Represents ~130,000 net acres with no locations assigned under evaluation. 4. See slide 14 for assumptions embedded in Eagle Ford IRR calculation. IRR based on Consensus Pricing as of 4/26/2017: $54.00 / $3.15 for 2017, $60.00 / $3.11 for 2018, $61.00 / $3.09 for 2019, $66.50 / $3.25 for 2020, $70.00 / $3.45 for 2021 and thereafter for WTI and Henry Hub respectively.

11 Gen 3 Design Outperforms Legacy Eagle Ford Development Wells Well Name Operator Frac Gen Boe/Ft Candace 1H WRD Galaxy 1H APC 1 38 Bronco 3 Well Pad APC 1 33 Whitney Well Pad CWEI 1 59 Milam Robertson Well Name Operator Frac Gen Boe/Ft War Wagon 2 Well Pad APC 1 43 Misfits 2 Well Pad APC 1 36 Zemanek 2 Well Pad APC 1 71 Foxfire 2 Well Pad APC 1 42 Capps 2 Well Pad APC 1 78 Peters Well Pad CWEI <1 44 Abbot Well Pad CWEI <1 45 Well Name Operator Frac Gen Boe/Ft Altimore #1H WRD Jackson #1H WRD Well Name Operator Frac Gen Boe/Ft Paul 134 #2H WRD Spitfire 2 Well Pad APC <1 61 Victorick 2 Well Pad APC 1 96 Well Name Operator Frac Gen Boe/Ft Snap B 1H WRD Snap F 1H WRD 3 98 Elm 2 Well Pad APC <1 46 Yucca 2 Well Pad APC <1 62 Capstone 2 Well Pad APC 1 94 Boxwood 1H APC 1 62 Porter E #1H CWEI <1 29 Well Name Operator Frac Gen Boe/Ft Cooper B 1H WRD Mach A 2H WRD Well Name Operator Frac Gen Boe/Ft Belmont Stakes 1H WRD WRD Wells APC Wells CWEI Wells Kentucky Derby 1H WRD Sassafras 2 Well Pad APC Miles 10 Note: Gray shading denotes WildHorse completions. Less than Gen 1 completions represent proppant loads less than 1,000 lbs/ft; Gen 1 completions represent proppant loads between 1,000 and 1,800 lbs/ft; Gen 2 completions represent proppant loads between 1,800 and 3,000 lbs/ft; Gen 3 completions represent loads greater than 3,000 lbs/ft.

12 WildHorse Acreage Positioned in the Highly Productive, Liquids-Rich Eagle Ford Geology matters: Gas to oil ratio Clay content Oil gravity Pore pressure geopressure of ~0.75 Psi / Ft The Eagle Ford is a Cretaceous sediment where the formation s carbonate content can exceed 70% in WildHorse s position Gross Eagle Ford thickness ranges from over 100 to greater than 400 across the acreage position Thickness allows greater potential for stacked / staggered development opportunities in both the Eagle Ford and the Chalk Clay content increases in the Northeast portion of the play in and Madison counties Rich carbonate content and lower clay content allow more effective hydraulic fracturing 0 20 Miles Bastrop Top of Eagle Ford Structural Map Milam 0 20 Miles Milam Fayette Fayette Austin Oil Gravity Grimes Waller WRD Acreage APC / KKR Acquisition Grimes WRD Acreage APC / KKR Acquisition Shallow -6,000' -7,000' -8,000' -9,000' -10,000' -11,000' -12,000' -13,000' -14,000' Deep API Miles Milam Gross Thickness Isopach Map 0 20 Miles Bastrop Milam Fayette Austin Gas / Oil Ratio Fayette Grimes Waller WRD Acreage APC / KKR Acquisition Grimes WRD Acreage APC / KKR Acquisition Thick 500' 450' 400' 350' 300' 250' 200' 150' 100' Mcf / STB 10,000 Thin 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1, ' 11

13 Buda Target Zone Austin Chalk Consistent Geology Across WRD s Eagle Ford Position A County County A Paul 134 #2H Offset Well Eagle Ford Shale A A 12

14 Acquisition Further Extends Deep Inventory of Economic Locations Net Horizontal Locations by Area Inventory Breakevens (10% Pre-tax IRR) Net Locations (1) 3,500 3,000 2,500 2,000 Multiple decades of drilling inventory across Eagle Ford and North Louisiana based on net locations (1) , ,299 Net Locations Net Locations 3,500 3,000 2,500 2,129 2, ,927 2,996 2, , , , ,285 Eagle Ford EUR (91 Boe/ft) 1,996 Eagle Ford Additional upside locations in: Existing Eagle Ford Locations Acquisition Locations North Louisiana Locations 1,702 Other RCT Other Total Locations North Louisiana ~130,000 Eagle Ford net acres with no locations assigned under evaluation Austin Chalk in County; Buda, Woodbine, Georgetown and Pecan Gap across much of our Eagle Ford acreage Northern Louisiana Additional Cotton Valley intervals 1, ,573 1,587 1,587 1,199 $35.00 / $2.00 $45.00 / $2.50 $55.00 / $3.00 $65.00 / $3.50 Existing Eagle Ford Acquisition North Louisiana As of May 11, 2017, we identified 3,299 net horizontal drilling locations, which includes 949 locations associated with our pending acquisition. The locations were specifically identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic and engineering data. We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other operators across our acreage, combined with our interpretation of available geologic and engineering data. The drilling locations on which we actually drill will depend on the availability of capital, regulatory approval, commodity prices, costs, actual drilling results and other factors. Of our 3,299 estimated drilling locations, 201, 342 and 1,156 are associated with proved, probable and possible reserves as of December 31, Accordingly, 1,599 of these locations do not have any reserves assigned to them which includes 949 locations associated with the pending acquisition. There are no assurances that these locations will perform like we expect. All of our assumptions with respect to our drilling locations, including estimated ultimate recoveries, expected costs to drill and complete, internal rates of return and economic break-even prices are speculative in nature and may prove to be inaccurate.

15 EUR Improvement ~2,000 Net Locations with Highly Economic 91 Boe/ft Type Curve Eagle Ford Single Well Summary Type Well Assumptions Wellhead EUR (MBoe) 555 Oil EUR (Mbbl) 497 % Oil 90% Gas EUR (MMcf) 348 Sales EUR (MBoe) 594 Oil EUR (Mbbl) 497 Gas EUR(MMcf) 219 NGL EUR (Mbbl) 60 % Gas 6% % Oil 84% % NGL 10% % Liquids 94% GOR (Mcf/bbl) 0.70 Lateral Length (ft) 6,500 Shrinkage 63% Variable Water Cost ($/Water Bbl) $0.90 Type Curve 30-day Oil IP (Bbl/d) day Gas IP (Mcf/d) day IP (Boe/d, 3-Stream) day IP (Boe/d) per 1,000' 114 Initial Decline (%) 78% B Factor 1.40 Terminal Decline (%) 6% Summary(1) Net Drilling Locations (2) 1,996 EUR / 1,000 Foot (MBoe) 91 D&C ($MM) $5.6 D&C / Foot $862 NPV10 ($MM) $5.9 IRR (%) 55% Boe/d 1, Boe/ft Type Curve (with all 23 Gen 3 well results) Month 91 Boe/ft Type Curve Gen 3 Average Boe IRR Sensitivity (3) EUR / 1,000 Ft Oil Price (MBoe) % $45.00 $50.00 $55.00 $60.00 $ % 27% 37% 47% 59% 71% % 35% 46% 59% 72% 89% % 45% 59% 74% 93% 113% % 55% 72% 92% 114% 140% % 67% 88% 111% 140% 175% % 80% 105% 134% 172% 212% Consensus Pricing as of 4/26/2017: $54.00 / $3.15 for 2017, $60.00 / $3.11 for 2018, $61.00 / $3.09 for 2019, $66.50 / $3.25 for 2020, $70.00 / $3.45 for 2021 and thereafter for WTI and Henry Hub, respectively. 2. See slide 13 for further information regarding our drilling locations. 3. IRR sensitivities assume $3.00 Henry Hub for the life of the well.

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

17 WRD Perpetual Convertible Preferred Equity Summary Issuer WildHorse Resource Development Corporation (NYSE: WRD) Purchaser The Carlyle Group, through its U.S. buyout fund Carlyle Partners VI Size $435 million Date of Original Issue Closing date in conjunction with the acquisition closing; target of June 30, 2017 Security Series A Perpetual Convertible Preferred Stock Maturity Perpetual Conversion Premium / Price Conversion Price of $13.90 per share based on a 20% premium to WRD s 30-day VWAP per share; WRD s 30-day VWAP represents $11.58 per share as of May 10, 2017 Total Conversion Shares 31,298,154 fully converted shares based on a Conversion Price of $13.90 per share Dividend Conversion Rights 6.0% annually payable quarterly in arrears in-kind by addition to the liquidation preference, cash or a combination thereof at WRD s sole election. WRD intends to PIK the dividend After 2.5 years if the stock price is equal to or greater than 130% of the Conversion Price, or $18.07, for 25 consecutive trading days dividends terminate permanently Issuer: After four years, if the stock price is equal to or greater than 140% of the Conversion Price, or $19.46, for 20 consecutive trading days Holder: At Conversion Price of $13.90 after one year Financial Covenants No financial covenants Ranking / Capital Structure Mezzanine equity; junior to all indebtedness and senior to common stock Voting Rights / Governance Will vote on an as converted basis; The Carlyle Group to elect two directors to the WRD Board 16

18 Updated FY 2017 Guidance; Pro Forma for Acquisition Expect to allocate a portion of our 2017 development program to higher working interest wells in and around the acquired acreage Updated Guidance reflects ~1 MBoe/d in outperformance and ~3 MBoe/d for acquisition (expected production for July Dec 2017) 2017 Guidance Prior Guidance Updated Guidance Low High Low High Net Average Daily Production (MBoe/d) Oil (% of Production) 52% - 56% 57% - 61% Natural Gas (% of Production) 35% - 38% 29% - 33% NGLs (% of Production) 8% - 10% 9% - 11% Average Costs (per Boe) Lease Operating Expense $ $3.25 $ $3.75 Gathering, Processing, and Transportation $ $1.15 $ $1.15 Taxes Other than Income $ $2.25 $ $2.25 (1) Cash General and Administrative $ $3.25 $ $3.00 (2) Commodity Price Realizations (Unhedged) Crude Oil Realized Price (% of WTI NYMEX) 95% - 100% 95% - 100% Natural Gas Realized Price (% of NYMEX to Henry Hub) 95% - 100% 95% - 100% NGL Realized Price (% of WTI NYMEX) 22% - 27% 27% - 32% Drilling Program Wells Spud (Gross) Wells Completed (Gross) D&C Capital Expenditure ($MM) $450 - $600 $550 - $ Note: Guidance as of May 11, Updated guidance includes announced acquisition results beginning July 1, Excludes non-cash compensation charges associated with grants under our LTIP and incentive units issued to certain of our officers and employees. WRD does not guide to anticipated average non-cash general and administrative costs. Please see cautionary language under Cautionary Statements and Additional Disclosures for additional disclosures because such compensation charges are based in part on the price of our common stock and are too speculative to predict. 2. Based on strip pricing as of May 11, 2017.

19 WildHorse Commodity Hedging Overview Pro Forma for Acquisition WildHorse s commodity risk management policy provides for hedging estimated production from total proved reserves Proactive policy reduces WildHorse s exposure to movements in commodity prices and provides stability to cash flows All trading counterparties have investment grade credit ratings at both S&P and Moody s Current hedges include primarily costless, fixed price swaps and collars, as well as deferred premium puts Hedge Summary as of May 11, 2017 Remaining 2017 (1) Crude Oil Hedge Contracts: Total crude oil volumes hedged (Bbl) 3,277,054 4,450,409 2,874,098 Volumes hedged (Bbl/d) 11,917 12,193 7,874 (2) Total weighted-average price ($/Bbl) $52.71 $53.61 $54.19 (3) % of 2017 Expected Production 60% - - Natural Gas Hedge Contracts Total natural gas volumes hedged (MMBtu) 13,581,895 11,565,800 9,877,900 Volumes hedged (MMBtu/d) 49,389 31,687 27,063 (2) Total weighted-average price ($/MMBtu) (3) $3.09 $3.03 $2.81 % of 2017 Expected Production 86% - - Total Hedge Contracts Total hedged production (MBoe) 5,540,703 6,378,042 4,520,415 Volumes hedged (Boe/d) (2) 20,148 17,474 12,385 Total weighted-average price ($/Boe) $38.74 $42.90 $40.60 (3) % of 2017 Expected Production 62% Remaining 2017 represents April 1 through December 31, Using the midpoint for collars and floors of puts. 3. FY17 represents mid-point of updated guidance.

20 Key Acquisition Benefits for WildHorse P Acquisition Increases WRD s Highly Contiguous Eagle Ford Acreage Position by ~40% P Positions WRD as 2nd Largest Eagle Ford Operator with ~385,000 Pro Forma Net Acres P P P Significant Development Potential and Running Room with 2,651 Pro Forma Eagle Ford Net Locations Attractive Geology with High Oil Cut, Carbonate Rich, Attractive Oil Gravity and High Pore Pressure Financing Structure Protects Balance Sheet, Includes Significant Hedging and Maintains Target Leverage at <2.0x 19

21 WRD Has Built a Premier Platform for Growth Premier Acreage Positions in the East Texas Eagle Ford and North Louisiana Over-Pressured Cotton Valley Total Company Net Acres (1) ~489,000 Proved Reserves (MMBoe)(2) % Liquids 68% % Oil 59% Q PF Production (Mboe/d) 25.2 % Liquids 68% Drilling Locations: Gross 5,829 Net 3,299 OK AR In and around the prolific Terryville Complex MS Eagle Ford Net Acres (1) ~385,000 Proved Reserves (MMBoe)(2) % Liquids 92% % Oil 81% Q PF Production (Mboe/d) 19.1 % Liquids 88% Drilling Locations: Gross 4,416 Net 2,651 Single-well IRR (3) ~55% TX Second largest Eagle Ford position in the industry LA North Louisiana Net Acres (1) ~104,000 (2) Proved Reserves (Bcfe) % Gas 98% Q Production (Mmcfe/d) 36.3 % Gas 95% Drilling Locations: Gross 1,413 Net 648 Single-well IRR (3) ~69% 20 Note: Q pro forma daily production based on WRD Q production plus Q production from announced acquisition; drilling locations pro forma for announced acquisition. 1. Pro forma acreage as of March 1, 2017; Includes pending acquisition of 111,044 net acres; Includes acreage that WildHorse has the right to lease within the Terryville Complex. 2. Reserve data as of December 31, 2016; includes 22.9 MMBoe in PDP reserves from announced acquisition (audited proved reserves not currently available). 3P Reserve Report audited by Cawley, Gillespie & Associates ( CGA ). 3. See slide 14 for assumptions embedded in WildHorse IRR calculations. Eagle Ford IRR based on Main type curve. IRRs based on Consensus Pricing as of 4/26/2017: $54.00 / $3.15 for 2017, $60.00 / $3.11 for 2018, $61.00 / $3.09 for 2019, $66.50 / $3.25 for 2020, $70.00 / $3.45 for 2021 and thereafter for WTI and Henry Hub, respectively.

22 21 Appendix

23 WRD Ownership Chart Pro Forma Acquisition Closing NGP and Management (1) The Carlyle Group $435MM Series A Perpetual Convertible Preferred Stock KKR Public Stockholders 55.4% (2) 23.8% (2) 4.8% (2) 16.1% (2) Company Shares Breakout Status Quo Pro Forma Total Common Shares Outstanding 93,987, ,248,440 Shares Issued at IPO 29,797,100 29,797,100 Current Float 19,797,100 26,057,999 Market Capitalization ($MM) (3) $1,066 $1,572 Fully Diluted Equity Ownership Status Quo Pro Forma Series A Perpetual Convertible Preferred (Carlyle) 0.0% 23.8% KKR 6.2% 4.8% NGP + Management 72.7% 55.4% Public 21.1% 16.1% WildHorse Resource Development Corporation NYSE: WRD 100% Operating Subsidiaries NGP and Management includes WHR Holdings, LLC; Esquisto Holdings, LLC; WHE AcqCo Holdings, LLC; NGP XI US Holdings, LP and Management. 2. Fully diluted equity ownership percentages. Pro Forma for announced acquisition and preferred issuance at closing. 3. As of May 10, 2017; Status Quo excludes convertible preferred shares and Pro Forma includes $435mm Series A Perpetual Convertible Preferred Stock.

24 Reconciliation of Adjusted EBITDAX This presentation and accompanying schedules include the non-gaap financial measure Adjusted EBITDAX. The accompanying schedule provides a reconciliation of the non-gaap financial measure to its most directly comparable financial measure calculated and presented in accordance with GAAP. WRD's non-gaap financial measures should not be considered as alternatives to GAAP measures such as Net Income, operating income, net cash flows provided by operating activities or any other measure of financial performance calculated and presented in accordance with GAAP. WRD's non-gaap financial measures may not be comparable to similarly-titled measures of other companies because they may not calculate such measures in the same manner as WRD does. Adjusted EBITDAX is a non-gaap financial measure. We evaluate performance based on Adjusted EBITDAX. Adjusted EBITDAX is defined as net income (loss), plus interest expense; debt extinguishment costs; income tax expense; depreciation, depletion and amortization; impairment of goodwill and long-lived properties; accretion of asset retirement obligations; losses on commodity derivative contracts and cash settlements received; losses on sale of properties; stock-based compensation; incentive-based compensation expenses; exploration costs; provision for environmental remediation; transaction related costs; IPO related expenses; and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and cash settlements paid; gains on sale of assets and other non-routine items. The following table presents WRD s first quarters of 2017 and 2016 EBITDAX to the most comparable measure calculated in accordance with GAAP: For the Three Months Ended March 31, (Amounts in $000s) Net Income (loss) $ 20,252 $ (14,216) Add (Deduct): Interest expense, net 5,571 1,972 Income tax (benefit) expense 11, Depreciation, depletion an amortization 26,443 22,063 Exploration expense 1,615 7,443 (Gain) loss on derivative instruments (31,291) (3,246) Cash settlements received / (paid) on commodity derivatives (983) 3,373 Stock-based compensation Acquisition related costs Debt extinguishment costs (11) 358 Initial public offering costs Non-cash liability amortization - (183) Adjusted EBITDAX $ 34,572 $ 17,703 23

25 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. 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. Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. 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 pending 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. 24

26 Cautionary Statements and Additional Disclosures (Cont d) Cash General and Administrative Expenses per Boe WRD s presentation of cash general and administrative ( G&A ) expenses per Boe is a non-gaap measure. WRD defines cash G&A per Boe as total G&A determined in accordance with accounting principles generally accepted in the United States of America ( GAAP ) less non-cash equity compensation expenses, expressed on a per-boe basis. WRD reports and provides guidance on cash G&A per Boe because it believes 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 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. 25