Company Presentation March 2018

Transcription

1 Company Presentation March 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. Unless otherwise stated all information presented herein excludes the impact of the North Louisiana divestiture. 2

3 3 I. Company Overview

4 Premier E&P Company with Top Tier Returns, Growth and Margins Key Investor Considerations TOP TIER RETURNS, GROWTH AND MARGINS 78% growth in 2018 total production at guidance midpoint High realizations and low operating costs lead to superior cash margins PROVEN ABILITY TO EXECUTE Outperformance of Gen 3 Eagle Ford wells Increased the Eagle Ford type curve to an EUR of 95 Boe/ft from 91 Boe/ft Average of 98 wells, located throughout the acreage position, are outperforming the 95 Boe per foot public Eagle Ford type curve 20%+ efficiencies in drilling days and cash operating costs/boe achieved in 2017 POSITIONED FOR LONG TERM GROWTH Deep Eagle Ford inventory 3,154 net locations at the 95 Boe/ft type curve (1) Over 30 years of inventory at current pace Austin Chalk upside potential on ~100,000 net acres Infrastructure in place to support long-term growth FINANCIAL STRENGTH AND FLEXIBILITY Low leverage profile with no near term maturities Net Debt / Q4 17 Annualized EBITDAX (7) at 1.4x, expected to trend downward Liquidity of $589MM at year end 2017 MBoe/d Premier Acreage Position in the Eagle Ford (6) Eagle Ford Net Acres ~404,000 Proved Reserves (MMboe) (2) % Liquids 88% % Oil 73% PV10 of Proved Reserves ($MM) $3,209 Q4'17 Production (Mboe/d) 36.0 % Liquids 90% Drilling Locations (3) Gross 4,785 Net 3,207 (4) Development well IRR 57% Second largest Eagle Ford position in the industry Peer Leading Production Growth (5) Total Company (6) Net Acres (2) ~494,000 (2) Proved Reserves (MMboe) % Liquids 75% % Oil 62% PV10 of Proved Reserves ($MM) $3,539 Q Production (Mboe/d) 45.9 % Liquids 72% (3) Drilling Locations Gross 6,179 Net 3,849 North Louisiana Net Acres ~90,000 (2) Proved Reserves (Bcfe) % Liquids 2% % Gas 98% PV10 of Proved Reserves ($MM) $331 Q4'17 Production (MMcfe/d) 59.3 % Gas 96% Drilling Locations Gross 1,409 Net 642 (4) Development well IRR 74% E 4 1. Includes locations outside of CGA s 3P area. 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 ). 3. Includes 71 gross (53 net) Austin Chalk locations. 4. Based on consensus pricing as of 3/1/18: $60.00 / $3.06 for 2018, $60.00 / $3.05 for 2019, $62.00 / $3.13 for 2020, $61.75 / $3.19 for 2021, $57.00 / $3.22 for 2022 and thereafter for WTI and Henry Hub, respectively E based on midpoint of guidance. 6. Includes approximately 90,000 net acres in North Louisiana pending sale to a third party with an expected close date of March 30, See slide 35 in the appendix for reconciliation of EBITDAX..

5 2017 Year in Review: Best in Class Execution 2017 Highlights WRD delivered best in class execution in 2017 Built second largest Eagle Ford position in the industry with 404,000 net acres (1) 98 Eagle Ford Gen 3 wells online at an average EUR of 99 Boe/ft (2) and 82 Bo/ft (2) outperforming the 95 Boe/ft type curve Wells located throughout the entire acreage position Drilled three successful Austin Chalk wells, creating significant additional upside potential Strengthened balance sheet and liquidity position Issued $500 million of 6.875% senior unsecured notes Net Debt / Q4 17 Annualized EBITDAX at 1.4x and expected to trend downward Y-o-Y liquidity increased by $379 million to $589 million Robust and balanced hedge position with commodity price downside protection and upside potential through the use of put options Stock Price Outperformance in 2017 Net Production (Mboe/d) 14.3 $ Q4 16 Q4 17 Borrowing Base $875 Production Growth Net Oil Production (Mbo/d) 5.7 Leverage & Liquidity ($MM) Liquidity $ Q4 16 Q4 17 $605 $ % 120% 100% 80% WRD S&P E&P Index Best E&P Stock Performance of Full Year 2017 (3) 26% (10%) 36% Incremental Return YE 16 YE 17 YE 16 YE 17 Gen 3 Eagle Ford Wells Online Wells Online Eagle Ford Type Curve Boe/ft % 40% Jan-17 Mar-17 May-17 Jul-17 Aug-17 Oct-17 Dec Bo/ft Bo/ft YE 16 YE 17 YE 16 YE Includes approximately 17,000 net acres in Lee County, TX acquired on March 1, Eagle Ford wells drilled and completed including refracs as of December 31, 2017, excludes test wells and wells with insufficient production history to estimate an EUR. 3. Based on all E&P companies with an average market capitalization above $200 million in 2017.

6 2018 Catalysts for Growth and Value Creation Transition to Eagle Ford Pure Play Increased Eagle Ford Type Curve Reduction in D&C Costs In-Field Sand Mine Austin Chalk Upside Announced divestiture of the North Louisiana asset positions WRD as the premier Eagle Ford pure play Post divestiture, WRD has an oilier production profile with higher margin production Eagle Ford production was 36.0 Mboe/d (78% oil) in the fourth quarter 2017 (1) Improved balance sheet metrics and liquidity post North Louisiana divestiture Increased Eagle Ford acreage to ~404,000 net acres from ~263,000 net acres at year-end 2016 WRD increased the Eagle Ford type curve to 95 Boe/ft from 91 Boe/ft based on continued outperformance Oil type curve increased to 78 Bo/ft from 76 Bo/ft Plan to drill and complete 100 to 110 Eagle Ford and Austin Chalk wells in 2018 Active delineation program planned in the Eagle Ford and Austin Chalk Development of an in-field sand mine will reduce D&C costs by an estimated $400K-$600K per well (a 58% reduction in sand costs at the midpoint) with an expected start date by first quarter 2019 Sand mine gives WRD greater operational control and reduces volatility in sand costs Projected sand savings of $1.2 - $1.8 billion over ~3,000 net locations Sand mine contains over 40+ years of reserves Conservative location count of 53 net locations based on 1,500 spacing and ~15,000 net acres. WRD expects that an additional ~85,000 net acres have Austin Chalk development potential Conservative Washington County budget type curve of 341 Boe per foot (64% gas, 29% NGLs, and 7% oil) Brought online the Lillie Hohlt #1H in Washington County with at an IP-30 (1) of 2,604 Boe/d or 15.6 MMcfe/d (66% natural gas, 31% NGLs, and 3% oil) on a 4,815 lateral Brought online the Brollier AC #1H in Washington County with at an IP-30 (1) of 2,704 Boe/d or 16.2 MMcfe/d (61% natural gas, 30% NGLs, and 9% oil) on a 5,684 lateral 1. The initial production rates represent the peak average of the initial production rates for the applicable consecutive days of production. 6

7 North Louisiana Divestiture Transforms WRD into the Premier Eagle Ford Pure Play Summary Rationale On February 12, 2018, WRD announced the divestiture of North Louisiana properties to a third party for consideration of approximately $217 million Additionally, WRD could receive contingent payments of up to $35 million based on the number of wells spud on the North Louisiana assets over the next four years Closing date on or about March 30, 2018; Effective date: January 1, 2018 Asset Summary: ~90,000 net acres Year end proved 2017 reserves of Bcfe (41% proved developed / 98% natural gas) Q4 17 production of 59.3 MMcfe/d (96% natural gas) WRD becomes a pure play Eagle Ford E&P with a single basin focus Oilier Eagle Ford production profile Eagle Ford production generates higher margins Smoother production cadence with faster Eagle Ford cycle times Improved leverage and liquidity metrics Divestiture proceeds help fund the 2018 drilling program Divestiture Increases Proved Reserve Oil Mix from 62% to 73% Reserves More Oil-Weighted Post Divestiture North Louisiana 2% 98% Total Company 13% 25% Oil NGLs Gas 62% 15% Eagle Ford 12% 73% North Louisiana Total 68.7 MMboe Proved Reserves by Basin PD PUD Eagle Ford Total MMboe 7

8 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 404 Apache 288 Sanchez Energy 286 Chesapeake 270 BHP Billiton 241 ConocoPhillips 213 BP 190 SM Energy 165 Murphy Oil 147 NM OK AR Marathon 145 TX LA EP Energy Miles SilverBow Net acreage positions per Company Investor Presentations, Company Filings and published reports as of January 31,

9 Proved Reserves Tripled at Attractive Costs Reserves Overview 2017 Drilling Program Added $2.8 Billion in PV10 PV-10 (1) of proved reserves increased by 372% to $3.5 billion at year end 2017 from $750 million at year end % increase in proved reserves at year end 2017 Increased 3P reserves by 131% to 1,892 MMboe Drill-bit finding and development ( F&D ) costs excluding acquisitions and price revisions averaged $3.36 per Boe (2) $MM $4,000 $3,000 $2,000 $1,000 $1,440 $479 $791 $374 ($295) $3,539 Replaced 2,096% of estimated production in 2017 including performance revisions and excluding price revisions and acquisitions Proved reserve life of 41.2 years based on 2017 production and reserves $0 $750 YE 2016 Total Reserve Adds Acquisitions Performance Revisions Price Revisions Production YE 2017 Total 2017 Proved Reserve Additions Proved Reserves Breakout MMboe YE 2016 Total 163 Reserve Adds Acquisitions Performance Revisions 8 (11) Price Revisions 454 Production YE 2017 Total 2017 Proved Reserves 13% 25% 62% 2016 Proved Reserves 36% 7% 57% Oil NGLs Gas 2017 Proved Reserves Proved Reserves MMboe PD PUD 153 MMboe 9 Note: Reserve information based on year end 2017 and 2016 audited reserve reports by CGA including the North Louisiana asset. 1. See slides for additional disclosures related to WRD s PV-10 and 3P reserves. 2. See slide 38 for WRD s Finding and Development cost ( F&D) calculation.

10 Deep Inventory of Economic Locations at a Compelling Valuation Net Horizontal Locations by Area Significant Upside to Current Valuation (PV-10 $MM) (4) 4,500 4,000 3,500 Multiple decades of drilling inventory across Eagle Ford and North Louisiana based on net locations (1) 3,299 3, Best in class execution led to 17% growth in net locations (21% increase in Eagle Ford locations) 3,849 $12,000 $11,000 $10,000 $9,000 $8,000 POSS $4,792 Net Locations (1) 3,000 2,500 2,000 1,500 1, Eagle Ford Other 1,996 Eagle Ford (EUR 91 Boe/Ft) WRD YE 2016 Eagle Ford (2) (EUR 95 Boe/ft) Eagle Ford Locations North Louisiana Locations North Louisiana WRD YE 2017 $Millions $7,000 $6,000 $5,000 $4,000 $3,000 $2,000 $1,000 $0 Market Cap $1,722 Preferred Net Debt $786 (3) $450 POSS $3,621 PROB $1,767 PUD $2,108 PDP $1,431 Total Proved $3,539 PROB $2,309 PUD $2,939 PDP $1,702 Enterprise Value SEC Pricing Consensus Pricing Total Proved $4,641 YE 2017 Audited Reserves As of December 31, 2017 and pro-forma for the Lee County acquisition closed on March 1, 2018, we identified 3,849 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 3,849 estimated drilling locations, 557, 716 and 1,826 are associated with CGA s proved, probable and possible reserves as of December 31, Accordingly, 750 of these locations are within management s 3P area and do not have any reserves assigned to them. 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. The Lee County acquisition includes 110 net management locations. 2. Includes 53 Austin Chalk net locations not a part of the 95 Boe per foot type curve. 3. Assumes WRD closing share price of $17.03 as of 3/1/ See slides for additional disclosures related to WRD s PV-10 and 3P reserves.

11 Eagle Ford Type Curve Increased from 91 to 95 Boe/ft Eagle Ford Single Well Summary Type Well Assumptions 95 Boe/Ft Wellhead EUR (MBoe) 574 Oil EUR (Mbbl) 508 % Oil 89% Gas EUR (MMcf) 393 Sales EUR (MBoe) 620 Oil EUR (Mbbl) 508 Gas EUR(MMcf) 234 NGL EUR (Mbbl) 72 % Gas 6% % Oil 82% % NGL 12% % Liquids 94% GOR (Mcf/bbl) 0.77 Lateral Length (ft) 6,500 Shrinkage 60% Variable Water Cost ($/Water Bbl) $1.17 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' 116 Initial Decline (%) 77% B Factor 1.40 Terminal Decline (%) 6% (3) NPV 10 & IRR (2) D&C $5.9MM $6.1MM $6.5MM NPV10 ($MM) $6.6 $6.4 $6.0 IRR (%) 70% 66% 57% Mboe Cumulative IRR % 80% 60% 40% Type Curve (1) Months 95 Boe/ft Type Curve Gen 3 Average Boe IRR Sensitivity $5.9 D&C Capex (2) $6.1 D&C Capex (2) $6.5 D&C Capex 20% $50.00 $55.00 Oil Price $60.00 $ Eagle Ford wells drilled and completed as of December 31, 2017, excludes test wells and wells with insufficient production history to estimate an EUR. The first day of the peak IP30 rate is considered day 1 of cumulative production. Data is normalized for 6,500 laterals and downtime. 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. 3. IRR sensitivities based on consensus pricing as of 3/1/18: $60.00 / $3.06 for 2018, $60.00 / $3.05 for 2019, $62.00 / $3.13 for 2020, $61.75 / $3.19 for 2021, $57.00 / $3.22 for 2022 and thereafter for WTI and Henry Hub, respectively

12 WRD Projected to Have Industry Leading Metrics Debt Adjusted Production Growth 2017E-2018E (1) 2018E ROCE (2) 60% 15% 50% 40% 10% 30% 20% 5% 10% 0% 0% SRCI WRD CRZO LPI SN OAS WPX WLL QEP Debt Adjusted Cash Flow Growth 2018E (3) 2018E EBITDAX Margin (4) 120% 90% 100% 80% 60% 60% 40% 30% 20% 0% WRD CDEV JAG WPX PE XOG FANG SRCI CRZO CPE MRO CLR OAS XEC 0% WRD CLR RSPP SM OAS WPX EPE NFX WLL 12 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 38 for ROCE calculation methodology. 3. Source: Citi equity research. 4. 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).

13 WRD to Develop an In-Field Sand Mine Sand Mine Increases Well Returns and Provides Greater Operational Control Sand Mine Overview and Rationale Estimated cost of $65-$75MM for acquisition, evaluation, and construction Expected to be operational by the first quarter of 2019 Contains 85 million tons of sand or over 40 years of reserves Rationale Reserves contain fine grade 100 mesh and 40/70 sand, comparable to the product WRD currently sources from third parties Sand Savings: 58% reduction in sand costs on $/ton (1) Well Cost Savings: Estimated reduction of $400K-$600K per well Increased Returns: Incremental single well returns of up to 13% Short Payback Period: Capital investment recovered in less than two years upon completion based on the current pace of WRD s activity Greater Operational Control: WRD-owned sand supply mitigates transportation costs and reduces volatility in completion costs In-Field Location Significantly Reduces Transportation Costs ` WRD Sand Mine WRD Acreage (3) Returns Uplift from Sand Mine Savings 100% 80% 60% 57% Projected sand savings of $1.2 - $1.8 billion over ~3,000 net locations 66% 70% Sand Seams 40% 20% 0% $6.5MM D&C $6.1MM D&C ($400K Savings) $5.9MM D&C ($600K Savings) WRD Sand Mine Location At midpoint of estimated well cost savings. 2. Based on consensus pricing as of 3/1/18: $60.00 / $3.06 for 2018, $60.00 / $3.05 for 2019, $62.00 / $3.13 for 2020, $61.75 / $3.19 for 2021, $57.00 / $3.22 for 2022 and thereafter for WTI and Henry Hub, respectively 3. Map of sand seams sourced from Google Earth.

14 Capacity and Optionality Around Midstream, Vendor Services, Water and Infrastructure Significant Midstream and Vendor Infrastructure Optionality Around Takeaway Capacity Multiple vendors for all key services provides flexibility and ample capacity Limited long term contracts Secured dedicated freshwater supply from 28 ponds and an agreement with the Brazos River Authority ~ 178 million Bbls of fresh water rights per year (~355 wells per year) Diversified sand supply with multiple sand suppliers in close proximity Developing in-field company sand mine online by first quarter 2019 Negotiated sand contracts to secure prices in 2018 Close proximity to market and well-developed midstream infrastructure In-field gathering and extensive market assets in place to ensure flow and downstream connectivity Diverse physical marketing portfolio with access to Gulf Coast refining markets Proximity to market minimizes transportation cost and related commitments while maximizing margins Multiple Vendors for Key Services NM TX OK AK LA Milam Eaglebine Express (Sunoco) Brazos WRD HQ Houston, TX Service Category Current Vendors Available Drilling Pressure Pumping 4 6+ Coil Tubing 2 4+ Proppant Cementing 2 4+ Chemicals Fuel 4 6+ Lee Burleson Washington Freshwater Pond Ample Water Supply 14

15 WildHorse Operated In-Field Sand Mine Offers Significant Savings Current and Development Well D&C Costs ($MM) $7.0 $6.0 $5.6 $0.6 $0.4 ($0.1) $6.5 ($0.4 - $0.6) $5.9 - $6.1 $5.0 $4.0 $3.0 $2.0 $1.0 $ Target Development Well Service Cost Inflation Sand Transportation Increase Negotiated Sand Contracts 2018 Budget Well Sand Mine Savings Future Target Development Well 15

16 Well Results Continue to Outperform and Delineate Acreage Position WRD Gen 3 wells continue to outperform 95 Boe/ft type curve across the acreage position Ascari B #1H EUR: 110 Boe/Ft IP30 = 711 Boe/d (91% oil) 7,038 LL (12/20/2017) Horizontal Well Activity (2) Wilde EF 1H / Teal EF 1H (5) EUR: 91 Boe/Ft IP30 = 602 Boe/d (93% oil) 6,513 LL (10/20/2017) Total of 98 gross Gen 3 Eagle Ford wells online are averaging a 99 Boe per foot EUR (1) Candace #1H EUR: 181 Boe/Ft IP30 = 1,081 Boe/d (88% oil) 7,481 LL (9/2/16) Altimore #1H EUR: 126 Boe/Ft IP30 = 1,048 Boe/d (84% oil) 6,435 LL (3/31/2017) Current Eagle Ford producing wells exist across entire ~800 square mile area Hovorak EF Unit #1H EUR: 124 Boe/Ft IP30 = 926 Boe/d (91% oil) 6,470 LL (6/11/2017) Snap I #1H / Snap J #1H (5) EUR: 103 Boe/Ft IP30 = 683 Boe/d (82% oil) 6,784 LL (7/29/2017) Drilled 95 gross (93.0 net) wells and completed 82 gross (81.0 net) Eagle Ford wells for full year 2017 with 30 gross (29.4 net) wells online in Q4 17 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) 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) Completed 3 gross (3.0 net) Austin Chalk wells for full year 2017 including 1 gross (1.0 net) well in Q4 17 Brought online 7 wells in 2017 outside of CG&A s 3P reserve area based on the year-end 2016 reserve report Jurica #1H / Doughtie #1H (5) EUR: 96 Boe/Ft IP30 = 730 Boe/d (95% oil) 6,885 LL (9/21/17) Fritsche 109 #1(Refrac) IP30 uplift: 481 Boe/d (88% oil) 5,387 LL (1/1/2018) Gold 107 #1 (Refrac) IP30 uplift:388 Boe/d (95% oil) 5,711 LL (9/6/2017) Winkelmann #1H (Austin Chalk) EUR: 400+ Boe/ft IP30 = 2,387 Boe/d (26% oil) 4,762 LL (6/3/17) Brollier AC #1H (Austin Chalk) IP30 = 2,704 Boe/d (9% oil) 5,684 LL (1/18/18) Lillie Hohlt #1H (Austin Chalk) IP30 = 2,604 Boe/d (3% oil) 4,815 LL (11/19/17) Cooper B #1H EUR: 107 Boe/Ft IP30 = 576 Boe/d (85% oil) 4,780 LL (2/22/17) BCMT A #1H EUR: 121 Boe/Ft IP30 = 533 Boe/d (69% oil) 6,878 LL (7/4/17) WRD Acreage with Locations (3) Additional WRD Acreage (4) WildHorse Gen 3 wells Legacy Eagle Ford wells Eagle Ford wells drilled and completed including refracs as of December 31, 2017, excludes test wells and wells with insufficient production history to estimate an EUR. 2. 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. 3. The dark grey area represents ~310,000 net acres within CGA s and management s 3P reserve area. 4. The light grey area represents ~94,000 net acres outside of CGA s and management s 3P reserve area with no assigned locations. 5. Two well pads represented with average EURs, initial production rates, oil mix, and lateral lengths.

17 Washington County Austin Chalk Budget Type Curve (5,000 lateral) 3,500 3,000 EUR: 341 Boe Per Foot 7% 29% 2,500 64% Barrels of Oil Equivalent Per Day 2,000 1,500 1,000 Oil NGLs Gas 500 Washington County Austin Chalk Budget Type Curve Winkelmann #1H Lillie Hohlt #1H Brollier AC 1H Days Additional type curve details: Current Austin Chalk location count of 53 based on ~15,000 net acres in Washington County WRD expects that an additional ~85,000 net acres have development potential Peak IP-30 of 1,755 Boe/d (7% oil, 29% NGLs, 64% gas) (1) IRR of 34% at consensus pricing based on a current well costs of $7.8 million per well (2) IRR of 39% and 37% at consensus pricing based on estimated well costs of $7.2 to $7.4 million per well upon completion of WRD s in-field sand mine (2) The initial production rates represent the peak average of the initial production rates for the applicable consecutive days of production. 2. IRR sensitivities based on consensus pricing as of 3/1/18: $60.00 / $3.06 for 2018, $60.00 / $3.05 for 2019, $62.00 / $3.13 for 2020, $61.75 / $3.19 for 2021, $57.00 / $3.22 for 2022 and thereafter for WTI and Henry Hub, respectively.

18 Proximity to Gulf Coast Leads to Advantaged Oil Pricing Comparative Basin Differentials (1) WRD receives LLS pricing minus transportation costs Regional location provides lower operating costs and better realized pricing due to proximity to demand centers for oil, natural gas and NGLs Q4 17 Comparative Basin Differentials (1) ($4.25) Bakken Low basis differentials along the Gulf Coast represent competitive advantage when compared to other plays WRD realized 105% of WTI during Q4 17 Entered into LLS-WTI basis swaps for 2018 to secure favorable pricing ($5.36) DJ Basin SCOOP / STACK Potential upside to develop an integrated midstream system to service Eagle Ford assets Q4 17 Peer Leading Oil Differentials (2) Permian Basin ($4.27) 5% 0% 5% 4% 4% 2% 0% 0% ($3.91) WRD Eagle Ford (5%) (10%) (2%) (2%) (3%) (3%) (5%) (7%) (7%) (7%) (7%) (8%) (10%) (10%) ($1.18) $2.66 (15%) (20%) (25%) (13%) (23%) South Texas Eagle Ford U.S. Shale Basins WTI Cushing # Basin Differential 18 Source: Corporate Filings and Company Data. 1. Differentials based on average realized $/Bbl for the three months ended 12/31/17. Companies included in Permian: FANG, LPI, RSPP, CXO; Companies included in Eagle Ford: CRZO, SN; Companies included in DJ Basin: PDCE and SRCI (XOG excluded due to timing of earning release); Companies included in Bakken: CLR, WLL; Companies included in SCOOP / STACK: NFX. 2. Based on Guggenheim equity research.

19 Eagle Ford Wells Outperform Competing Basins and Peers on Cash Margin Cash Margin: WRD Eagle Ford vs. Competing Basins (1) (4Q 2017) $/Boe $55.00 $57.21 $7.71 $55.40 $55.40 $55.61 $55.40 $55.40 Q Average WTI Price $44.00 $4.16 $2.67 $13.34 $13.40 $17.81 $18.69 $3.04 $2.78 Commodity Mix $33.00 $22.00 $42.67 $5.06 $5.82 $2.62 $2.98 $8.31 $1.78 $3.41 $4.75 $2.56 Differential LOE & GP&T $11.00 $31.35 $30.42 $27.70 $25.99 Production & Ad Valorem Taxes Cash Margin $0.00 WRD Eagle Ford Permian Bakken Eagle Ford DJ Basin % Oil 78% 63% 61% 43% 47% 19 Source: Company filings and investor presentations. Note: Assumes 6:1 gas to oil ratio. Commodity mix represents the difference between average WTI price and the weighted average commodity price per Boe of the company s production (using Henry Hub for gas and assuming NGL pricing equal to 35% of WTI). Does not include G&A and other corporate level costs. 1. Companies included in Permian: CXO, FANG, LPI and RSPP; Companies included in Eagle Ford: CRZO and SN; Companies included in DJ Basin: PDCE, SRC and XOG; Companies included in Bakken: CLR and WLL.

20 20 II. Financial Overview

21 Strong Balance Sheet and Liquidity Position at 12/31/17 Capitalization Strong Liquidity Position ($ in millions) 12/31/2017 Cash $0 WRD Revolving Credit Facility $ % Senior Notes (1) $500 Total Debt $786 ($ in millions) 12/31/2017 Liquidity Borrowing Base $875 Cash $0 Revolver Borrowings ($286) Total Current Liquidity $589 Series A Cum. Perpetual Convertible Preferred (2) $450 Shareholders Equity 1,145 Financial & Operating Statistics Q4'17 Annualized EBITDAX $552 Q4'17 Annualized Interest Expense $44 Q4'17 Daily Production (Mboe/d) 45.9 Credit Metrics (3) Net Debt / Q4'17 Daily Production ($/Boe/d) $17,129 Net Debt / Q4'17 Annualized EBITDAX 1.4x Interest Coverage 12.6x $900 $750 $600 $450 $300 $150 $0 $875MM Borrowing Base No Near Term Maturities $500MM 6.875% Senior Notes Excludes unamortized discount and unamortized debt issuance costs. 2. Excludes costs incurred related to the issuance and pro-forma for the Series A Perpetual Convertible Preferred dividend payment on 1/31/ Credit metrics assume 100% equity treatment for the Series A Perpetual Convertible Preferred.

22 FY 2018 Guidance (as of February 12, 2018) 2018 Guidance Net Average Daily Production (Mboe/d) Oil (Mbbls/d) Natural Gas (MMcf/d) NGLs (Mbbls/d) FY 2018 Guidance Pro-Forma FY 2018 Guidance North Louisiana Divestiture (3) Low High Low High Average Costs (per Boe) Lease Operating Expense Gathering, Processing, and Transportation Cash General and Administrative (1) Taxes Other than Income (% of oil & gas revenue) ($2.80) - ($3.30) ($2.90) - ($3.40) ($1.10) - ($1.40) ($1.10) - ($1.40) ($1.65) - ($2.15) ($2.00) - ($2.50) 5.0% - 6.0% 5.0% - 6.0% Commodity Price Realizations (Unhedged) (2) Crude Oil Realized Price (% of WTI NYMEX) Natural Gas Realized Price (% of NYMEX to Henry Hub) NGL Realized Price (% of WTI NYMEX) 98% - 102% 98% - 102% 94% - 98% 90% - 94% 33% - 37% 33% - 37% Drilling Program Wells Spud (Gross) Wells Completed (Gross) D&C Capital Expenditure ($MM) $700 - $800 $700 - $800 Sand Mine Capital Expenditure ($MM) $65 - $75 $65 - $ 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 February 9, Pro-Forma pending North Louisiana sale to a third party with an expected close date of March 30, 2018 with an effective date of January 1, 2018.First quarter of 2018 North Louisiana production is included in both scenarios.

23 WildHorse Commodity Hedging Overview Highlights Disciplined and balanced hedging strategy focused on minimizing commodity price downside (swaps, collars) and cost effectively maximizing commodity price upside (deferred premium puts) Proactive policy reduces WRD s exposure to movements in commodity prices and provides stability to cash flow All trading counterparties have investment grade ratings at both S&P and Moody s While 79% of expected 2018 oil production is hedged, 43% of expected oil production provides upside potential to higher commodity prices through the use of put options Hedges in place help secure WRD s peer leading cash margins Attractive WTI-LLS oil basis hedges protect against a widening basis differential Crude Oil Hedge Contracts: Hedge Summary Total crude oil volumes hedged (Bbl) 9,526,420 8,402,126 1,101,762 Volumes Hedged (Bbl/d) 26,100 23,020 3,010 Total weighted-average price ($/Bbl) (1) $52.24 $53.93 $50.19 % of Expected Production (2) 79% Natural Gas Hedge Contracts: Total natural gas volumes hedged (MMBtu) 11,825,800 9,877,900 Volumes Hedged (MMBtu/d) 32,399 27,063 Total weighted-average price ($/MMBtu) (1) $3.03 $2.81 % of Expected Production (2) 34% Total Hedge Contracts (Swaps, Collars, Puts): Total hedged production (Mboe) 11,497,387 10,048,443 1,101,762 Volumes Hedged (Boe/d) 31,500 27,530 3,010 Total weighted-average price ($/Boe) (1) $46.40 $47.86 $50.19 % of Expected Production (2) 57% WTI-LLS Oil Basis Hedges Volumes hedged (Bbl) 3,988,800 Volumes Hedged (Bbl/d) 10,928 Weighted-average price ($/Bbl) $3.06 % of Expected Production (2) 33% Using the midpoint for collars and floors of puts. 2. Represents mid-point of fiscal year 2018 guidance. 3. Hedges as of 2/12/18.

24 Investment Highlights Oil-Weighted Eagle Ford Pure Play Top Tier Returns, Growth and Margins Proven Ability to Execute Positioned for Long Term Growth Financial Strength and Flexibility 24

25 25 III. Appendix

26 Focused Strategy of Eagle Ford Acreage Growth and Consolidation WildHorse continues to execute on a proven strategy of organic leasing and targeted acquisitions to grow its high quality Eagle Ford acreage position to 404,000 net acres SM Acquisition January st CWEI Acquisition and Comstock Acquisition June/July 2015 Multiple Acquisitions Sept (1) 2 nd CWEI Acquisition Dec 2015 Initial Position Washington Brazos Previous Position 1 st CWEI and Comstock Acquisitions Brazos Previous Position Lee Brazos Previous Position 2 nd CWEI Acquisition Brazos Burleson Burleson Burleson Burleson Lee Lee Lee Lee Washington Washington Washington Washington Organic Leasing / Acreage Swaps 3 rd CWEI Acquisition Dec 2016 APC / KKR June 2017 Lee County Acquisition March 2018 Previous Position Organic Leasing / Swaps Brazos Previous Position 3 rd CWEI Acq. Brazos Previous Position APC / KKR Acq. Brazos Previous Position Lee County 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. 26

27 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 Austin 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, ' 27

28 Gen 3 Design Unlocks Improved EURs and Significant Eagle Ford Oil Growth Increased Intensity Has Improved EURs Outperformance on both Bo/ft and Boe/ft (1) Boe/ft ,500 Wells Completed Target Proppant (lbs/ft) ,600 3, ,700 Boe/ft Boe/Ft 76 Bo/Ft 95 Boe/Ft 78 Bo/Ft 99 Boe/Ft 82 Bo/Ft 111 Boe/Ft 80 Bo/Ft 0 Gen 1 Gen 2 Gen 3 Eagle Ford Gen 3 Eagle Ford + Austin Chalk 0 YE 2016 Type Curve YE 2017 Type Curve Gen 3 Gen 3 Eagle Ford Performance Eagle Ford + Austin Chalk Performance WRD s Eagle Ford Oil Mix Leads Other Active Basins (2) Significant Year over Year Oil Growth Oil Mix 100% 80% 60% 40% 20% 82% 78% 69% 69% 60% Oil Mix After Year 1 and 2 of Production Year 1 Year 2 50% 32% 29% MBbls/d % 120% 82% 0% WRD Bakken PRB Midland Delaware Niobrara Stack Scoop E 2018E Eagle Ford wells drilled and completed including refracs as of December 31, 2017, excludes test wells and wells with insufficient production history to estimate an EUR. 2. Source: BMO Equity Research.

29 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 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 29 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.

30 WRD Perpetual Convertible Preferred Equity Summary Issuer WildHorse Resource Development Corporation (NYSE: WRD) Purchaser The Carlyle Group, through its U.S. buyout fund Carlyle Partners VI Size $450.4 million (as of January 31, 2018) 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 32,402,059 fully converted shares based on a Conversion Price of $13.90 per share (as of January 31, 2018) 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 nominates two directors to the WRD Board 30

31 WRD Ownership Chart NGP and Management (1) The Carlyle Group $450MM Series A Perpetual Convertible Preferred Stock KKR Public Stockholders 56.0% (2) 24.3% (2) 4.1% (2) 15.6% (2) Company Shares Breakout Total Common Shares Outstanding 101,137,277 Total Common Shares Fully Diluted for Carlyle Conversion 133,539,336 Market Capitalization (3) $2,173 WildHorse Resource Development Corporation NYSE: WRD Fully Diluted Equity Ownership Pro Forma (2) % Shares Series A Perpetual Convertible Preferred (Carlyle) 24.3% 32,402,059 KKR 4.1% 5,518,125 NGP + Management 56.0% 74,777,842 Public 15.6% 20,841, % Operating Subsidiaries 1. NGP and Management includes WHR Holdings, LLC; Esquisto Holdings, LLC; WHE AcqCo Holdings, LLC; NGP XI US Holdings, LP,Management and WRD LTIP shares. 2. Pro Forma for impact of $450MM Series A Perpetual Convertible Preferred Stock as of 1/31/18 and common shares outstanding as of 12/31/ As of March 1, 2018 assuming share price of $17.03 per share; Includes Series A Perpetual Convertible Preferred Stock based on PIK dividends as of January 31,

32 Crude Oil Hedge Summary Crude Oil Hedge Contracts: Swap contracts: Volume (MBbl) 6,834 6,652 1,102 Volume (Bbl/d) 18,725 18,226 3,010 Weighted-average fixed price $52.24 $54.27 $50.19 Collar contracts: Volume (MBbl) 25 Volume (Bbl/d) 69 Weighted-average floor price $50.00 Weighted-average ceiling price $62.10 Put options (bought): Volume (MBbl) 2,667 1,750 Volume (Bbl/d) 7,306 4,794 Weighted-average floor price $51.74 $52.66 Weighted-average put premium ($3.47) ($5.43) Total Crude Oil Hedge Contracts (Swaps, Collars, Puts): Total crude oil volumes hedged (MBbl) 9,526 8,402 1,102 Total crude oil volumes hedged (Bbl/d) 26,100 23,020 3,010 Total Weighted-Average Price Total weighted-average price (including puts) (1) $52.42 $53.93 $50.19 WTI-LLS Oil Basis Hedges Volumes hedged (MBbl) 3,989 Volumes Hedged (Bbl/d) 10,928 Weighted-average price ($/Bbl) $ Using the midpoint for collars. 32

33 Natural Gas Hedge Summary Gas Hedge Contracts: Swap contracts: Volume (BBtu) 11,826 9,878 Volume (MMBtu/d) 32,399 27,063 Weighted-average fixed price $3.03 $2.81 Collar contracts: Volume (BBtu) Volume (MMBtu/d) Weighted-average floor price Weighted-average ceiling price Put options (bought): Volume (BBtu) Volume (MMBtu/d) Weighted-average floor price Weighted-average put premium Total Gas Hedge Contracts: Total gas volumes hedged (BBtu) 11,826 9,878 Total gas volumes hedged (MMBtu/d) 32,399 27,063 Total Weighted-Average Price Total weighted-average price (excluding puts) (1) $3.03 $2.81 Total weighted-average price (including puts) (1) $3.03 $ Using the midpoint for collars. 33

34 WildHorse Resource Development CG&A Reserve Detail (1) December 31, 2017 December 31, 2016 Oil Natural Gas NGLs Total % Oil PV-10 (MBbl) (MMcf) (MBbl) (MBoe) (%) ($M) PDP 61, ,465 12, ,498 57% $1,392,178 PDNP 3,109 11, ,997 62% $39,015 PUD 217, ,291 44, ,820 64% $2,108,144 Total Proved 282, ,808 57, ,315 62% $3,539,337 Y-O-Y Growth 223% 110% 429% 198% 372% Probable 271, ,244 54, ,955 68% $1,767,148 2P Reserves 554,289 1,117, , ,270 65% Y-O-Y Growth 187% 111% 416% 182% Possible 554,586 2,384,281 87,954 1,039,920 53% $3,620,826 (2) 3P Reserves 1,108,875 3,501, ,759 1,892,190 59% Y-O-Y Growth 158% 69% 356% 131% Oil Natural Gas NGLs Total % Oil PV-10 (MBbl) (MMcf) (MBbl) (MBoe) (%) ($M) PDP 18, ,530 3,674 44,878 41% $361,189 PDNP 743 9, ,392 31% $18,565 PUD 68, ,222 7, ,235 65% $370,233 Total Proved 87, ,103 10, ,505 57% $749,988 Probable 105, ,551 10, ,202 70% $366,727 2P Reserves 192, ,654 21, ,707 64% Possible 237,364 1,540,204 22, ,213 46% $847,809 3P Reserves (2) 430,298 2,068,858 43, ,920 53% 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, See slides for cautionary statements and additional disclosures regarding PV-10 and 3P reserves.

35 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; 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 fourth quarter of 2017 and 2016 EBITDAX to the most comparable measure calculated in accordance with GAAP: For the Three Months Ended December 31, (Amounts in $000s) Net Income (Loss) $ 14,066 $ (17,636) Add (Deduct): Interest expense, net 10,981 2,225 Income tax (benefit) expense (60,071) (6,025) Depreciation, depletion and amortization 56,735 20,353 Exploration expense 19,043 3,050 (Gain) loss on derivative instruments 92,602 18,077 Cash settlements received / (paid) on commodity derivatives (5,378) (1,093) Stock-based compensation 2, Acquisition related costs Debt Extinguishment costs - 1,309 Initial public offering costs Gain (loss) on sale of properties - 43 Non-cash liability amortization - - North Louisiana settlement 7,000 - Adjusted EBITDAX $ 137,957 $ 21,179 35

36 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 expects to include a full reconciliation of PV-10 as of December 31, 2017 to standardized measure in its Form 10-K for the year ended December 31, 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. 36