FOCUSED. Creating value through operational excellence. EnerCom Oil & Gas Conference

Transcription

1 FOCUSED Creating value through operational excellence EnerCom Oil & Gas Conference August 20-21, 2018

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 are subject to decline over time and should not be regarded as reflective of sustained production levels.

3 Mboe/d Premier Pure-Play Eagle Ford Oil Producer Strong Investment Thesis Large Position in Eagle Ford Oil Window Emerging Austin Chalk Upside Proven Ability to Execute Advantaged Oil Price Realizations and Access to Premium Markets Premier Eagle Ford Acreage Position Eagle Ford Acreage (1) ~404,000 net acres >3,200 net locations Proved Reserves (12/31/17) (2) 386 MMboe 88% Liquids 73% Oil $3.2 Billion PV10 Q2 18 Daily Production 46.7 Mboe/d 72% Oil (3) Top-Tier Returns, Growth and Margins Abundant Service Capacity and Infrastructure Strong Financial Position with Low Leverage and Excellent Liquidity Peer Leading Eagle Ford Production Growth Positioned for Exceptional Long-Term Growth and Value Creation E (4) 1. Includes locations outside of CGA s 3P area and 71 gross (53 net) Austin Chalk locations. See Management Locations in the Appendix section of this presentation for more information. 2. Reserve data based on December 31, 2017 reserve report audited by Cawley, Gillespie & Associates ( CGA ) excluding the North Louisiana assets divested on March 29, Includes 0.2 Mboe/d of production from other East Texas properties and North Louisiana accruals that were divested in March and August E based on midpoint of guidance. 3

4 WRD Among Largest Eagle Ford Operators Operator Acreage Positions (1) Net Acreage Positions (1) Eagle Ford Shale Oil Wet Gas/Condensate Dry Gas (000s Acres) EOG Resources BP (2) WildHorse 404 Magnolia Sanchez Energy Chesapeake Apache 250 ConocoPhillips 213 SM Energy 165 Murphy Oil 147 NM OK AR Marathon 145 TX LA EP Energy Miles SilverBow Well-Located, Contiguous Eagle Ford Position Net acreage positions per Company Investor Presentations, Company Filings and published reports as of August Pending BHP acquisition announced on July 26,

5 Returns Focused Strategy Deliver Profitable Growth and Value Creation Prudently delineate large, contiguous acreage position Develop emerging Austin Chalk play and other zones Continue successful acquisition strategy at attractive costs Optimize Capital Efficiency Enhance completions and production techniques Leverage scale, pad drilling and other efficiencies Deliver step change in cost savings with infield sand mine Improve Leading Cash Margins Implement midstream projects to enhance netbacks Secure access to premium markets Utilize scale and competitive service market Maintain Financial Discipline Target conservative leverage profile and strong liquidity Fund growth primarily with internally generated cash flows Continue active commodity hedging program 5

6 Creating Value Through Results-Driven Execution 2018 Objectives Complete North Louisiana divestiture Recent Highlights Closed divestiture March 2018 Further delineate Eagle Ford position and evaluate Austin Chalk potential Deliver solid growth Maintain financial discipline and flexibility Initiate sand mine construction Add acreage through bolt-on acquisitions at attractive prices Prudent capital allocation Brought online 47 gross Eagle Ford wells across acreage position and 4 gross Austin Chalk wells in 1H 2018 Grew Q2 18 average production to 46.7 Mboe/d (72% oil), up 107% vs. Q2 17 Increased Q2 18 Adjusted EBITDAX to $161.5 million, a 208% increase over Q2 17 (1) Issued an additional $200 million of 6.875% senior unsecured notes in Q2 18 Increased borrowing base on the credit facility to $1.05 billion in April 2018 Sand mine construction underway Completed $19.0 million Lee County acquisition of approximately 17,500 net acres Industry-leading metrics at attractive valuations On Track to Meet or Exceed 2018 Objectives 1. See slide 26 in the Appendix for reconciliation of EBITDAX.. 6

7 Controlling Our Destiny Developing In-Field Sand Mine Overview In-Field Location Reduces Costs Annual capacity of ~2.0 MM tons WRD 2018 sand demand of ~1.2 MM tons >40 years of reserves at current pace Grain and mesh consistent with Gen 3 well design Permits received; planned in service by Q1 19 Significant Economic Benefits ` WRD Sand Mine WRD Acreage 58% reduction in sand costs with $400K - $600K savings per well (1) $65 - $75 million total capital investment with less than two-year payback Improves well IRR s by up to ~16% (2) Secures operational control Opportunity for third-party sales Expected Sand Mine Savings of $1.2-$1.8 Billion Over WRD Inventory 1. Sand cost reduction at the midpoint of estimated well cost savings. 2. Based on consensus pricing as of 8/1/18: $65.91 / $2.89 for 2018, $64.00 / $3.00 for 2019, $65.38 / $3.01 for 2020, $63.00 / $3.15 for 2021, $61.50 / $3.20 for 2022 and thereafter for WTI and Henry Hub, respectively. 7

8 Midstream, Vendor Services, Water and Infrastructure Overview Significant Midstream & Vendor Infrastructure Multiple vendors with limited long-term contracts for key services provides flexibility and ample capacity Dedicated freshwater supplies from Brazos River Authority and area sources with ~370 MMbbls of freshwater rights per year Close proximity to Gulf Coast refining market and well-developed midstream takeaway Pipeline access ensures flow and downstream connectivity Infrastructure minimizes transportation costs while maximizing margins Multiple Vendors for Key Services Service Category Current Vendors Available Drilling Pressure Pumping 2 6+ Coil Tubing 2 6+ Proppant Cementing 2 4+ Chemicals Fuel 4 6+ Optionality Around Takeaway Capacity Ample Water Supply Freshwater Pond Significant Optionality Supports Long-Term Development Program Lee Milam Burleson Brazos Washington 8

9 Visible Takeaway Capacity at Premium Pricing Current Status: ~100% WTI Realization (1) Substantially all WRD oil production on pipeline to Gulf Coast and sold at LLS premium pricing Significant options for delivery points Q2 18 netback ~$3.50/bbl deduct to LLS (100% WTI) Unlimited capacity via trucking barrels directly to Houston (~125 miles) at ~$6.00/bbl (2) deduct to LLS LLS / WTI basis largely tied to transportation, providing natural hedge to increased trucking costs Close proximity to Gulf Coast minimizes transport costs and maximizes margins NM TX Significant Takeaway Optionality OK AR LA Falls City, TX Rosanky, TX Smiley, TX Hearne, TX Cuero, TX Bryan, TX Houston, TX Future Enhancements to Netback Corpus Christi, TX Pipeline Trucking Route 2H 18 announcement expected regarding midstream proposals received that further enhance netbacks Infield oil and produced water gathering system will reduce infield trucking charges in near-term Long-haul pipeline will further improve premium pricing and provide additional flow assurance Keeping barrel neat will provide further uplift to pricing Takeaway Option Pipeline Receipt Point Proximity to Field (Miles) Destination Eaglebine Express Hearne, TX 31 Houston Bridgetex (Magellan) Bryan, TX 35 Houston Flint Hills (Koch) Rosanky, TX 72 Corpus Long-Haul Trucking Houston, TX 125 Houston Kinder Morgan Cuero, TX 126 Houston Kinder Morgan Smiley, TX 130 Houston Harvest System Falls City, TX 160 Corpus Unlimited capacity through long-haul trucking and additional commerical options in close proximity to field Takeaway Optionality Preserves WRD Pricing Advantage 1. Q oil realization 100% of WTI. 2. Based on current market conditions and contract rates for trucking and market center liquidity. 9

10 WRD Eagle Ford Has Advantaged Oil Pricing Gulf Coast Offers Superior Realizations Q2 18 Comparative Basin Differentials (2) Advantaged pricing due to proximity to Gulf Coast and superior markets WRD receives premium LLS pricing minus transportation costs and quality adjustment WRD Premium to: Permian $6.98 DJ $6.31 Bakken $6.22 ($5.90) DJ Basin Bakken Realized 102% of WTI 1H 18 STACK $5.05 ($5.99) 2018 WTI oil realization guidance midpoint is 100% LLS basis swaps for ~54% of 2H 18 oil volumes SCOOP/STACK $10.00 Advantaged LLS Premium (1) WTI-Midland WTI-LLS Permian Basin ($6.66) ($4.73) WRD Eagle Ford $6.00 $2.00 $0.32 $(2.00) ($1.60) $(6.00) ~125 miles $(10.00) $(14.00) $(18.00) South Texas Eagle Ford U.S. Shale Basins WTI Cushing # Basin Differential Eagle Ford Premium Pricing Expected to Continue Source: Corporate Filings and Company Data. 1. Chart represents monthly price averages. CME as of July 26, Differentials based on average realized $/Bbl for the three months ended 6/30/18. Companies included in Permian: EGN, CPE, CXO; Companies included in Eagle Ford: CRZO, SN; Companies included in DJ Basin: SRCI, PDCE, XOG; Companies included in Bakken: WLL, CLR; Companies included in SCOOP / STACK: NFX. 10

11 $/Boe $70.00 $60.00 $50.00 $40.00 $30.00 Cash Margin: WRD Eagle Ford vs. Competing Basins (1) (Q2 18) $68.20 $67.88 $67.88 $67.88 $67.88 $13.47 $1.20 $2.76 $2.96 $17.09 $19.10 $4.38 $5.92 $3.01 $4.97 $6.63 $3.39 $23.94 $25.60 $0.96 $8.75 $2.53 $6.01 $3.89 $3.17 $67.88 Q Avg. WTI Price Commodity Mix Differential LOE & GP&T $20.00 $47.49 $37.48 $33.79 $31.70 $29.21 Production & Ad Valorem Taxes Cash Margin $10.00 $0.00 WRD Eagle Ford Permian Bakken Eagle Ford DJ Basin % Oil 72% 62% 61% 43% 47% WRD Eagle Ford Delivers Superior Cash Margins 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: EGN, CPE, CXO; Companies included in Bakken: WLL, CLR; Companies included in Eagle Ford: CRZO and SN; Companies included in DJ Basin: SRCI, PDCE, XOG. 11

12 Large Eagle Ford Position Reflects Opportunistic Consolidation Strategy SM Energy January st CWEI and Comstock June/July 2015 Multiple Acquisitions Sept 2015 (1) 2 nd CWEI December 2015 Initial Position Washington Previous Position WTI at $47.27 Brazos 1 st CWEI and WTI at $50.90 Brazos CRK Acquisitions Previous Position Lee Previous Position Brazos WTI at $ nd CWEI Acquisition Brazos WTI at $37.23 Burleson Burleson Burleson Burleson Lee Lee Lee Lee Washington Washington Washington Washington Organic Leasing / Acreage Swaps 3 rd CWEI December 2016 APC / KKR June 2017 Enervest March 2018 Previous Position Organic Leasing / Swaps WTI at $43.19 Brazos Previous Position 3 rd CWEI Acq. Previous Position Previous Position Brazos WTI at $52.01 WTI at $45.17 Brazos WTI at $62.76 Brazos APC / KKR Acq. Lee County Acq. Burleson Burleson Burleson Burleson Lee Lee Lee Lee Washington Washington Washington Washington 0 20 Miles WRD acquired Eagle Ford position at attractive average per net acre pricing and at low WTI pricing Low Acquisition Cost + Solid Well Economics = Strong Full-Cycle-Returns 1. Includes three acquisitions in Lee County that occurred over ~12 months. 12

13 Delineation Results Continue to be Excellent Eagle Ford producing wells exist across entire ~800 square mile area Ascari B #1H EUR: 110 Boe/Ft IP30 = 711 Boe/d (91% oil) 7,038 LL (12/20/2017) Horizontal Well Activity (1) Wilde EF 1H / Teal EF 1H (4) EUR: 91 Boe/Ft IP30 = 602 Boe/d (93% oil) 6,513 LL (10/20/2017) 145 Gen 3 Eagle Ford wells online ~100,000 net acres prospective for the Austin Chalk Use refracs to cost effectively delineate position with Gen 3 completion design Position includes upside potential on ~94,000 net acres outside of CGA s 3P area without assigned locations (~23% of total WRD acreage) CGA audited locations increased significantly year-over year Candace #1H EUR: 181 Boe/Ft IP30 = 1,081 Boe/d (88% oil) 7,481 LL (9/2/16) Hovorak EF Unit #1H EUR: 124 Boe/Ft IP30 = 926 Boe/d (91% oil) 6,470 LL (6/11/2017) Chmelar South #1H EUR: 149 Boe/Ft IP30 = 1,011 Boe/d (92% oil) 6,915 LL (5/22/17) Goodnight #3H EUR: 121 Boe/Ft IP30 = 724 Boe/d (93% oil) 5,833 LL (5/28/17) Balcar Unit #1(Refrac) IP30 uplift: 370 Boe/d (92% oil) 4,973 LL (3/18/2018) Gold 107 #1(Refrac) IP30 uplift: 388 Boe/d (88% oil) 5,711 LL (9/6/2017) Fritsche 109 #1(Refrac) IP30 uplift: 481 Boe/d (88% oil) 5,387 LL (1/1/2018) Brollier AC #1H (Austin Chalk) EUR: 686 IP30 = 3,030 Boe/d (8% oil) 5,684 LL (1/18/18) Winkelmann #1H (Austin Chalk) EUR: 429 IP30 = 2,387 Boe/d (26% oil) 4,762 LL (6/3/17) WRD Acreage with Locations (2) Additional WRD Acreage (3) Morgan #1H/ Brodnax #1H (4) (Austin Chalk) IP30: 2,483 Boe/d (1% oil) 5,311 LL (3/7/2018) WildHorse Gen 3 wells Legacy Eagle Ford wells Lillie Hohlt #1H (Austin Chalk) EUR:495 IP30 = 2,604 Boe/d (3% oil) 4,815 LL (11/19/17) WRD Sand Mine Irene #1H /Inez #1H/Lero #1H (4) IP30 = 788 Boe/d (89% oil) 6,404 LL (3/22/2018) Altimore #1H EUR: 126 Boe/Ft IP30 = 1,048 Boe/d (84% oil) 6,435 LL (3/31/2017) Dusek A #1H EUR: 130 Boe/Ft IP30 = 890 Boe/d (91% oil) 7,438 LL (11/22/2017) Belmont Stakes #1H EUR: 115 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) JRG C 1H (Austin Chalk) IP30 = 747 Boe/d (12% oil) 5,843 LL (3/31/18) BCMT A #1H EUR: 121 Boe/Ft IP30 = 533 Boe/d (69% oil) 6,878 LL (7/4/17) Less Than 5% of WRD Inventory Developed - Significant Running Room 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. WildHorse Gen 3 wells as of June 30, 2018 as well as highlighted refracs. EUR rates for wells as of 12/31/2017 are based on reserve data audited by CGA. 2. The dark grey area represents ~310,000 net acres within CGA s and management s 3P reserve area. 3. The light grey area represents ~94,000 net acres outside of CGA s and management s 3P reserve area with no assigned locations. 4. Two well pads represented with average EURs, initial production rates, oil mix, and lateral lengths. 13

14 WRD Eagle Ford Acreage Has Attractive Reservoir Properties Geology Overview Gross Lower Eagle Ford thickness ranges from 50 to 100 across the acreage position Eagle Ford Maturity Window Geosteering focusing on the high resistivity, carbonate-rich Lower Eagle Ford Positioned in the Lower Eagle Ford trend of high net-to-gross pay Strategically located in the black to volatile oil maturity window Eagle Ford Pay Structure and API Gravity Feet Feet High-Quality Acreage Position Yielding Attractive Wells/Returns 14

15 IRR (%) IRR (%) NGL NGL Gas Gas Oil Oil WRD Well Economics Eagle Ford Type Curve Austin Chalk Type Curve IP-30 (Bbl/d) 621 Oil EUR (MBbl) 508 IP-30 (Bbl/d) 126 Oil EUR (MBbl) 123 IP-30 (Mcf/d) 480 Gas EUR (MMcf) 234 IP-30 (Mcf/d) 6,740 Gas EUR (MMcf) 6,548 IP-30 (Boe/d) 56 NGL EUR (Mboe) 72 IP-30 (boe/d) 505 NGL EUR (MBoe) Stream EUR (Mboe) Stream EUR (Mboe) 1,705 % Oil 82% % Oil 7% Well Cost ($MM) $5.9 $6.1 $6.5 Well Cost ($MM) $7.2 $7.4 $7.8 NPV 10 ($MM) IRR (%) (1) $7.5 $7.3 $6.9 84% 76% 68% NPV 10 ($MM) IRR (%) (1) $5.2 $5.0 $4.6 41% 39% 35% Eagle Ford Economics Washington Co. Austin Chalk Economics 160% 140% (2) (2) $5.9MM D&C $6.1MM D&C $6.5MM D&C 80% (2) (2) $7.2MM D&C $7.4MM D&C $7.8MM D&C 120% 60% 100% 80% 60% 40% EUR 620 Mboe Lateral Length 6,500 40% EUR 1,705 Mboe Lateral Length 5,000 20% $50.00 $55.00 $60.00 $65.00 $70.00 $75.00 $ % $50.00 $55.00 $60.00 $65.00 $70.00 $75.00 $80.00 WTI Oil Price WTI Oil Price Strong Type Curves With Superior Returns 1. IRR sensitivities based on WTI and Henry Hub consensus pricing as of 8/1/18: $65.91 / $2.89 for 2018, $64.00 / $3.00 for 2019, $65.38 / $3.01 for 2020, $63.00 / $3.15 for 2021, $61.50 / $3.20 for 2022 and thereafter 2. D&C costs based on WRD sand mine estimated savings of $400,000 to $600,000 per well at well costs of $5.9 and $6.1 million per well. 15

16 MMboe Eagle Ford 2017 Proved Reserve Growth Reserves Overview PV-10 (1) of proved reserves increased by 412% to $3.2 billion at YE % increase in proved reserves at YE 2017 Increased 3P reserves by 193% to 1,450 MMboe Eagle Ford drill-bit F&D costs averaged $3.28/Boe (2) Replaced 2,498% of estimated Eagle Ford production in 2017 Proved reserve life of ~45 years 2017 Proved Reserves 15% 12% 73% 2016 Proved Reserves 7% 10% Proved Reserves Breakout 83% Oil NGLs Gas 2017 Proved Reserves Proved Reserves 79 PD PUD 2017 Proved Reserve Additions Added $2.6 Billion in PV10 in (11) (21) $4,000 $3,000 $791 $374 ($295) ($207) $3, $2,000 $ $1,000 $626 $1, YE 2016 Total Reserve Adds Acquisitions Performance Revisions Price Revisions Production North Louisiana Adjustment YE 2017 Total $0 YE 2016 Total Reserve Adds Acquisitions Performance Revisions Price Revisions Production North Louisiana Adjustment (3) (3) YE 2017 Total Significant Year-over-Year Reserves Growth Note: Reserve information based on year end 2017 and 2016 audited reserve reports by CGA excluding the North Louisiana assets divested on March 29, See slides for additional disclosures related to WRD s PV-10 and 3P reserves. 2. See slide 29 for WRD s Finding and Development cost ( F&D) calculation. 3. Pro-forma for the impact of the North Louisiana divestiture on reserve adds, performance revisions, and price revisions at the year 2017 CGA reserve report. 16

17 $MM Strong Balance Sheet and Liquidity Position Financial Highlights Ample liquidity of over $800 million in cash and undrawn capacity on the revolving credit facility Leverage ratios below 2.0x on an annualized and LTM basis Nearest maturities in 2021 and Senior Notes in 2025 Proactive hedging strategy focused on minimizing downside and cost effectively maximizing upside Credit Metrics (3) Capitalization & Liquidity 6/30/ $MM WRD Revolving Credit Facility Drawn $249 (1) 6.875% Senior Notes $700 Total Debt $949 Series A Cum. Perpetual Convertible Preferred $450 Shareholder's Equity $1,019 Borrowing Base Availability $801 Cash $19 Total Liquidity $820 (2) No Near-Term Maturities Net Debt / 2Q18 Annualized EBITDAX - 1.4x $1,200 $1,050 Net Debt / LTM EBITDAX - 1.7x Interest Coverage x Targeting leverage ratios < 2.0x $900 $750 $600 $450 $300 $1,050 MM Borrowing Base $700 MM (1) 6.875% Senior Notes $150 $ Maintaining Disciplined Financial Strategy 1. Excludes unamortized net discount and unamortized debt issuance costs. 2. Liquidation preference. 3. Credit metrics assume 100% equity treatment for the Series A Perpetual Convertible Preferred. 17

18 Industry-Leading Metrics at an Attractive Valuation 60% Debt Adjusted Production Growth 17-18E (1) 15% 2018E ROCE (2) 50% 40% 30% Peer avg 27% 10% Peer avg 7% 20% 5% 10% 0% 0% SRCI WRD CRZO LPI SN OAS WPX WLL QEP 2019 Enterprise Value / EBITDAX (3) Price to Net Asset Value (4) 8.0x 120% 7.0x 6.0x 5.0x Peer avg 5.5x 100% 80% Peer avg 82% 4.0x 60% 3.0x 2.0x 1.0x 0.0x CRZO SRCI WRD OAS XEC WPX SN QEP CPE PE FANG 40% 20% 0% WRD Delivering Top-Tier Results at Attractive Valuations Note: Peer groups vary as a result of sourcing data from several different equity research firms cited below. 1. Source: Raymond James equity research. 2. Source: Simmons & Company equity research report. See slide 29 for ROCE calculation methodology. 3. Source: Simmons & Company equity research at $65 WTI oil unhedged pricing 4. Source: Citigroup equity research 18

19 Full Year 2018 Guidance (as of February 12, 2018) FY 2018 Guidance Net Average Daily Production (Mboe/d) Oil (Mbbls/d) Natural Gas (MMcf/d) NGLs (Mbbls/d) 5 7 Low High Average Costs (per Boe) Lease Operating Expense ($2.90) ($3.40) Gathering, Processing, and Transportation (1) ($1.10) ($1.40) Cash General and Administrative (2) ($2.00) ($2.50) Taxes Other than Income (% of oil & gas revenue) 5.0% 6.0% Commodity Price Realizations (Unhedged) (3) Crude Oil Realized Price (% of WTI NYMEX) 98% 102% Natural Gas Realized Price (% of NYMEX to Henry Hub) (1) 90% 94% NGL Realized Price (% of WTI NYMEX) (1) 33% 37% Drilling Program Wells Spud (Gross) Wells Completed (Gross) D&C Capital Expenditure ($MM) Sand Mine Capital Expenditure ($MM) Targeting Another Year of Solid Growth 1. The guidance above is based on the prior accounting convention before the implementation of the new FASB revenue recognition standard (ASC 606, Revenue from Contracts with Customers), effective as of January 1, After the implementation date, approximately two-thirds of GP&T expense is expected to be recognized as a deduction from revenue while the remainder is expected to be recognized as a GP&T expense line item. See slide 30 for a reconciliation of GP&T in the first quarter 2018 to the prior accounting convention from the new FASB standard. See the MD&A section of WRD s 10-Q filing to be filed on or before August 9, 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. 3. Based on strip pricing as of February 9,

20 WildHorse Commodity Hedging Overview Highlights Hedge Summary (2) Disciplined and balanced commodity hedging strategy Proactive policy reduces WRD s exposure to movements in commodity prices and provides stability to cash flow Hedged ~75% of expected 2H 18 oil production (1) 52% of expected 2H 18 oil production provides upside potential to higher commodity prices through the use of put options (1) Hedges in place help secure WRD s peer leading cash margins Attractive WTI-LLS oil basis hedges lock in a premium basis differential Hedging supports capital program and delineation activity Q3 - Q Crude Oil Hedge Contracts: Swap contracts: Volume (Mbbl) 2,959 6,652 4,512 Volume (Bbl/d) 16,079 18,226 12,327 Weighted-average fixed price $52.36 $54.45 $53.49 Put options (bought): Volume (Mbbl) 1,656 1,750 Volume (Bbl/d) 9,002 4,794 Weighted-average floor price $50.04 $53.83 Weighted-average put premium ($3.64) ($5.43) Total Crude Oil Hedge Contracts (Swaps, Puts): Total crude oil volumes hedged (Mbbl) 4,615 8,402 4,512 Total crude oil volumes hedged (Bbl/d) 25,081 23,020 12,327 Expected oil production hedged (1) 75% Total Weighted-average price $51.53 $54.32 $53.49 WTI-LLS Oil Basis Hedges Volumes hedged (Mbbl) 3,339 Volumes hedged (Bbl/d) 18,148 Expected oil basis production hedged (1) 54% Weighted-average price ($/Bbl) $3.02 Total Natural Gas Hedge Contracts (Swaps): Swap contracts: Volumes hedged (BBtu) 4,724 6,425 4,846 Volumes hedged (MMbtu/d) 25,672 17,603 13,240 Expected natural gas production hedged (1) 86% Weighted-average price ($/MMbtu) $2.79 $2.79 $2.76 Total Hedge Contracts Volumes hedged (Mboe) 5,402 9,473 5,319 Volumes hedged (Boe/d) 29,360 25,953 14,534 Expected total production hedged (1) 65% Weighted-average price ($/Boe) $44.43 $48.49 $45.79 Minimizes Commodity Downside While Maintaining Upside Potential 1. Represents mid-point of fiscal year 2018 guidance. 2. Hedges as of 8/7/18. 20

21 Premier Eagle Ford Pure-Play Oil Producer Large Position in Eagle Ford Oil Window Proven Ability to Execute Advantaged Oil Price Differentials & Access to Markets Top-Tier Returns, Growth and Margins Abundant Service Capacity and Infrastructure Strong Financial Position Well Positioned to Deliver Exceptional Shareholder Returns 21

22 APPENDIX

23 WRD Ownership Chart NGP and Management (1) The Carlyle Group $450MM Series A Perpetual Convertible Preferred Stock Public Stockholders 46.8% (2) 24.1% (2) 29.1% (2) Company Shares Breakout Total Common Shares Outstanding 102,007,516 Total Common Shares Fully Diluted for Carlyle Conversion 134,409,575 (3) Market Capitalization $2,984 WildHorse Resource Development Corporation NYSE: WRD Fully Diluted Equity Ownership Pro Forma (2) % Shares Series A Perpetual Convertible Preferred 24.1% 32,402,059 NGP + Management 46.8% 62,923,019 Public 29.1% 39,084, % Operating Subsidiaries 1. NGP and Management includes WHR Holdings, LLC; Esquisto Holdings, LLC; WHE AcqCo Holdings, LLC; NGP XI US Holdings, LP, and Management shares. 2. Based on common shares outstanding and Series A Perpetual Convertible Preferred Stock as of 6/30/ As of August 1, 2018 assuming share price of $22.20 per share; Includes Series A Perpetual Convertible Preferred Stock fully diluted and common shares outstanding as of 6/30/18. 23

24 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 $450.4 million liquidation preference (as of July 31, 2018) Date of Original Issue June 30, 2017 Security Series A Perpetual Convertible Preferred Stock Maturity Perpetual Conversion Premium / Price Total Conversion Shares Dividend Conversion Rights Conversion Price of $13.90 per share based on a 20% premium to WRD s 30-day VWAP per share as of May ,402,059 fully converted shares based on a Conversion Price of $13.90 per share (as of July 31, 2018) 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 After December 31, 2019, 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 June 30, 2021, 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 per share after June 30, 2018 Financial Covenants No financial covenants Ranking / Capital Structure Voting Rights / Governance Mezzanine equity; junior to all indebtedness and senior to common stock Votes on an as converted basis; Two WRD board members represent The Carlyle Group 24

25 WRD CG&A Reserve Detail (1) December 31, 2017 (2) December 31, 2016 (2) Oil Natural Gas NGLs Total % Oil PV-10 (MBbl) (MMcf) (MBbl) (MBoe) (%) ($M) PDP 61,393 57,720 12,093 83,106 74% $1,232,999 PDNP 3, ,221 96% $31,448 PUD 217, ,019 44, ,312 73% $1,944,346 Total Proved 281, ,194 57, ,640 73% $3,208,793 Y-O-Y Growth 225% 523% 448% 268% 412% Probable 270, ,450 54, ,024 73% $1,674,217 2P Reserves 552, , , ,664 73% Y-O-Y Growth 188% 549% 425% 233% Possible 547, ,080 87, ,367 79% $3,039,475 3P Reserves(3) 1,099, , ,346 1,450,031 76% Y-O-Y Growth 160% 454% 360% 193% Oil Natural Gas NGLs Total Oil PV-10 (MBbl) (MMcf) (MBbl) (MBoe) (%) ($M) PDP 18,099 19,206 3,220 24,520 74% $289,013 PDNP % $15,058 PUD 67,887 25,594 7,109 79,262 86% $322,328 Total Proved 86,720 45,124 10, ,660 83% $626,398 Probable 104,874 38,844 10, ,138 86% $316,608 2P Reserves 191,594 83,968 21, ,798 84% Possible 231,933 79,736 22, ,371 87% $662,892 (3) 3P Reserves 423, ,704 43, ,169 86% 1. Based on SEC pricing of $51.34 per barrel and $2.98 per mmbtu as of December 31, 2017, and $42.75 per barrel and $2.48 per mmbtu as of December 31, Pro-forma for the North Louisiana divestiture closed on March 29, See slides for cautionary statements and additional disclosures regarding PV-10 and 3P reserves. 25

26 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; transaction related costs; IPO related expenses; the North Louisiana settlement, 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 EBITDAX for the last twelve months ended June 30, 2018 and the three months ended June 30, 2018 and 2017 reconciled to the most comparable measure calculated in accordance with GAAP: For the Three Months For the Twelve Months Ended June 30, Ended June 30, (Amounts in $000s) Net Income (Loss) $ (14,094) $ 26,366 $ (126,606) Add (Deduct): Interest expense, net 14,002 6,633 47,039 Income tax (benefit) expense (9,356) 15,193 (113,166) Depreciation, depletion and amortization 70,694 33, ,155 Exploration expense 4,369 11,504 29,869 (Gain) loss on derivative instruments 110,805 (46,116) 284,065 Cash settlements received / (paid) on commodity derivatives (29,508) 2,076 (49,630) Stock-based compensation 3,835 1,308 11,832 Incentive unit compensation 13,776-13,776 Acquisition related costs 129 2,199 2,038 Impairment of NLA Disposal Group ,274 Gain on sale of North Louisiana disposal group (3,167) - (3,167) North Louisiana Settlement - - 7,000 Debt Extinguishment costs Adjusted EBITDAX $ 161,485 $ 52,392 $ 556,479 26

27 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 $51.34 per Bbl and $2.98 per MMBtu; $42.75 per Bbl and $2.48 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 2017, December 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. WRD includes a full reconciliation of proved PV-10 as of December 31, 2017 to standardized measure in its Form 10-K for the year ended December 31, In addition, the following table provides a reconciliation of the PV-10 of our Eagle Ford proved reserves to the Standardized measure of discounted future net cash flow for the period presented: 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, 2017 have been prepared by WildHorse s internal reserve engineers and audited by Cawley, Gillespie & Associates, Inc. ( CGA ), WildHorse s independent reserve engineers. 27

28 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 a total of 3,207 net horizontal drilling locations in this presentation in the proved, probable, and possible categories as audited by CG&A, WRD s third party engineers, as well as locations that have been identified by WRD s management. 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 WRD s 3,207 net horizontal drilling locations, 2,761 lie within the geographic areas to which proved, probable and possible reserves are attributed by CG&A. The remaining 446 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. Net Locations CG&A Management Total Dec. 31, 2017 Locations (1) Locations Locations Eagle Ford 2, ,154 Austin Chalk Total Locations 2, , Includes 110 net locations from the Lee County, TX acquisition which closed on March 1,

29 Cautionary Statements and Additional Disclosures Cash General and Administrative Expenses Our presentation of cash general and administrative ("G&A") expenses is a non-gaap measure. We define cash G&A as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, and we may express it 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. Calculation of Return on Capital Employed ( ROCE ) Simmons Equity Research calculates ROCE (on a pre-tax basis) as adjusted Earnings Before Interest and Taxes ( EBIT ) divided by adjusted capital employed. Adjusted EBIT excludes impairments, unrealized hedging, exploration expense, dry hole expense, asset retirement obligations ( ARO ) and any gains or losses on divestitures (if included in revenues). Adjusted capital employed equals adjusted equity plus debt, preferred stock and minority interest. Adjusted equity utilizes 2009 shareholder s equity and adds the following items on a rolling basis: impairments, unrealized hedging, exploration expense, dry hole expense and ARO expense. Drill-Bit Finding and Development ( F&D ) Cost Calculation Drill-bit F&D cost is an indicator used to assist in the evaluation of the historical cost of adding proved reserves on a per Boe basis. Consistent with industry practice, future capital cost to develop proved undeveloped reserves are not included in costs incurred. Drill-bit F&D costs are calculated as D&C capital expenditures, including facilities and capital workovers, divided by reserve additions from extensions, discoveries, additions and performance revisions. Cost incurred ($'s in millions): Eagle Ford North Louisiana Total WRD 2017 D&C capex including facilities $701.7 $86.1 $787.8 and capital workovers Reserve additions (Mboe): Extensions, discoveries and additions Performance revisions Total additions Total Drill-bit F&D costs ($/boe) $3.28 $4.20 $

30 Cautionary Statements and Additional Disclosures GP&T Revenue Recognition Reconciliation Second Quarter 2018 The table below reconciles gathering, processing and transportation ( GP&T ) expense to the reporting convention prior to the implementation of the new FASB revenue recognition standard on January 1, 2018 (ASC 606, Revenue from Contracts with Customers). For additional information on the GP&T reconciliation and the new revenue recognition standard, see the Management s Discussion & Analysis section of WRD s 10-Q filing to be filed on or before August 9, Prior Reporting Variance New FASB Revenue Recognition Standard Guidance (prior reporting} Revenues: Gas revenue $9,540 ($1,434) $8,106 NGL revenue $12,193 ($2,525) $9,668 Other Income $304 ($57) $247 Natural gas price realization (% of Henry Hub) 86% -13% 73% 90% - 94% NGL price realization (% of WTI) 33% -7% 26% 33% - 37% Operating expenses: Lease operating expenses $12,395 ($307) $12,088 GP&T expense $4,022 ($3,546) $476 Depreciation, depletion, and amortization $70,849 ($155) $70,694 Other operating (income) expense $282 ($171) $111 GP&T per boe $0.95 ($0.84) $0.11 $ $

31 WildHorse Company Tear Sheet Profile WildHorse Resource Development Corporation is an independent oil and natural gas company focused on the acquisition, exploration, development and production of oil, natural gas and NGL properties, primarily in the Eagle Ford Shale and Austin Chalk in East Texas Symbol: Exchange: Shares OS: Headquarters: WRD NYSE 102,005,515 at July 31, Katy Freeway, Suite 400 Houston, Texas Investors Investor Relations: Contact: Pearce Hammond, CFA Vice President, Investor Relations (713) Vedran Vuk Director, Investor Relations (713) Transfer Agent: EQ Shareowner Services P.O. Box St. Paul, MN (800)