IPAA OGIS Conference April 2017

Transcription

1 IPAA OGIS Conference April 207

2 Forward-Looking Statements This presentation includes forward-looking statements within the meaning of Section 27A of the Securities Act of 933, as amended, and Section 2E of the Securities Exchange Act of 934, 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 0-K, 0-Q and 8-K. Consequently, all of the forward-looking statements made in this presentation are qualified by these cautionary statements and there can be no assurances that the actual results or developments anticipated by WRD will be realized, or even if realized, that they will have the expected consequences to or effects on WRD, its business or operations. WRD has no intention, and disclaims any obligation, to update or revise any forward-looking statements, whether as a result of new information, future results or otherwise. Initial production rates subject to decline over time and should not be regarded as reflective of sustained production levels. 2

3 3 I. Company Overview

4 WildHorse Resource Development Corporation Overview Summary Attractive rate of return development: Eagle Ford single-well IRRs of ~55% and North Louisiana Upper Red single well IRRs of ~65% () Extensive inventory supports multi-year growth story Veteran team with successful track record of value creation Significant acquisition opportunities in Eagle Ford / North Louisiana to grow footprint Modest leverage and sufficient liquidity to fund drilling program High Quality Assets OK Total Net Acres (2) 378,024 Proved Reserves (MMBOE) (3) 52.5 % Liquids 64% % Oil 57% Q4 206 Production (Mboe/d) 7.5 % Liquids 56% Drilling Locations: Gross 4,548 Net 2,350 AR MS Pro Forma Historical Production TX LA Q 204 Q Q Q4 204 Q 205 Q2 205 Eagle Ford Q3 205 Q4 205 Q 206 North Louisiana Q2 206 Q3 206 Q4 206 Eagle Ford Net Acres (2) 274,302 Proved Reserves (MMBOE) (3) 04.7 % Liquids 93% % Oil 83% Q4 206 Production (Mboe/d) 0.8 % Liquids 88% Drilling Locations: Gross 3,35 Net,702 North Louisiana Net Acres (2) 03,722 Proved Reserves (BCFE) (3) % Gas 98% Q4 206 Production (Mmcfe/d) 40. % Gas 94% Drilling Locations: Gross,43 Net Note: All operational data as of 2/3/6 and pro forma for Burleson North Acquisition closed on 2/9/6.. See slides 8 and 29 for assumptions embedded in WildHorse IRR calculations. Eagle Ford IRR based on Burleson Main type curve. IRRs based on Consensus Pricing as of 2/22/207: $55.05 / $3.2 for 207, $59.07 / $3.2 for 208, $63.2 / $3.27 for 209, $64.98 / $3.40 for 2020 and thereafter for WTI and Henry Hub respectively. 2. Pro forma acreage as of March, 207; Includes pending acquisition of ~0,500 acres in Burleson County; Includes acreage that WildHorse has the right to lease within the Terryville Complex. 3. Reserve data as of December 3, P Reserve Report audited by Cawley, Gillespie & Associates ( CGA ). 4. Compound annual growth rate, or CAGR, represents a calculation of the average annual compounded growth rate of our average daily production from the first quarter of 204 to the fourth quarter of 206 by comparing our average daily production for the fourth quarter of 206 to our average daily production for the first quarter of 204. The calculation assumes that the growth rate derived from the calculation is even across the periods covered by the calculation and does not take into account any fluctuations in our production for any periods other than the two periods used to calculate the CAGR.

5 $2.45 $2.47 $2.87 $3.4 $3.2 $3.23 $3.27 $3.54 $3.57 $3.59 $3.65 $3.66 $3.67 $3.69 $3.8 $3.83 $3.84 $3.95 $4.4 $4.45 $4.53 $5.34 $5.4 $36.02 $40.79 $42.69 $43.22 $43.46 $44.70 $44.8 $45.83 $46.70 $47.60 $48.04 $48.9 $48.23 $49.20 $49.69 $50.00 $50.40 $5.88 $53.3 $55.50 $57.49 $60.77 $60.89 $62.86 $70.64 $76.8 $79.20 WildHorse Returns Rival the Premier Basins Break-even prices based on before tax half-cycle IRRs of 30% Oil Breakevens by Play $ / Bbl $80.00 $60.00 $40.00 $20.00 $0.00 Gas Breakevens by Play $ / MMBtu $6.00 $4.50 $3.00 $.50 $ Note: Break-evens per Wall Street Research based on strip pricing as of 9//6. Break-even prices based on before tax half-cycle IRRs of 30%. IRRs elsewhere in presentation based on Consensus Pricing as of /5/206. See slides 6 and 27 for more information on WildHorse IRR calculations at consensus pricing.. Midland Basin Lower Spraberry comprised of Core Midland Lower Spraberry, Western Glasscock Lower Spraberry, Howard County Lower Spraberry. 2. Wolfcamp A&B comprised of Core Midland Wolfcamp A&B, Western Glasscock Wolfcamp A&B, Howard County Wolfcamp A&B, Midland East Glassock Wolfcamp A&B. 3. Stack Meramec comprised of STACK Meramec Normal-Pressured Oil, STACK Meramec Over-Pressured Oil. 4. Delaware Basin comprised of Delaware Basin Loving Wolfcamp A, Delaware Basin Reeves Wolfcamp A, Delaware Basin NM Avalon/Leonard.

6 Multi-Year Drilling Inventory Drives Upside Potential Net Horizontal Locations by Area Inventory Breakevens (0% Pre-tax IRR) # of Net Locations () # of Net Locations 2,500 2,000 Multiple decades of drilling inventory across Eagle Ford and North Louisiana based on net locations () ,350 Net Locations 648 2,500 2,000 2,64 2,233 2, , ,500, ,322, ,702,000,573,587, , Burleson Main Burleson North Burleson West Burleson South Eagle Ford Additional upside locations in: Lee Washington RCT Weyer. Bear Creek Austin Chalk in Burleson County; Eagle Ford in Washington County; Buda, Woodbine, Georgetown and Pecan Gap across much of our Eagle Ford acreage Northern Louisiana Additional Cotton Valley intervals North Louisiana Total Locations 0 $35.00 / $2.00 $45.00 / $2.50 $55.00 / $3.00 $65.00 / $3.50 Eagle Ford North Louisiana 6. As of December 3, 206, we identified 2,350 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 2,350 estimated drilling locations, 20, 342 and,56 are associated with proved, probable and possible reserves as of December 3, 206. Accordingly, 650 of these locations 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.

7 High Quality Eagle Ford Position with Extensive Operated Inventory 274,302 net acres in the East Texas Eagle Ford Shale, focused on Burleson, Lee and Washington Counties,702 total net (3,35 gross) drilling locations, ~86% of which are in Burleson County Drilled and completed 38 operated horizontal Eagle Ford wells as of 2/3/6 Q4 206 net production of 0.8 MBoe/d (88% liquids) Completions evolution and D&C reductions have dramatically improved well results and returns D&C cost per lateral foot reduced by 67% since Gen EUR per,000 lateral feet increased 28% from Gen to Gen 3 completions ~55% IRRs (2) for core Burleson acreage (~87% of total Burleson locations) High realized pricing given proximity to Gulf Coast and low operating costs compared to Permian Significant Austin Chalk upside potential Currently operating five rigs with plans to average 4.5 rigs in Snap G H (WRD) IP30 = 978 BOE/D (79% oil) 6/64 Choke FTP,86 psi 6,735 LL (/22/5) Snap H H (WRD) IP30 = 883 BOE/D (74% oil) 6/64 Choke FTP 2, psi 7,476 LL (//6) Candace (WRD) IP29 =,075 BOE/D (95% oil) 6/64 Choke FTP,600 psi 7,48 LL (7/2/6) Lucy H (Halcon) IP30 = 944 BOE/D (93% oil) 8,897 LL (/3/4) Snoe H (WRD) IP30 = 949 BOE/D (74% oil) 34/64 Choke FTP 574 psi 5,782 LL (2/24/4) Schoppe C H (WRD) IP30 = 753 BOE/D (79% oil) 6/64 Choke FTP,727 psi 7,756 LL (9/5/5) Brollier H (SM Energy/WRD) IP30 = 83 BOE/D (3% oil) 9/64 Choke FCP 2,44 psi 4,367 LL (7/27/3) Liebscher O.L. Unit 2H (Enervest) IP30 = 989 BOE/D (56% oil) 4,539 LL (6/30/3) Austin Chalk WRD Completion Generation 2 3 Horizontal Well Activity () Burleson Main Burleson North Burleson West Burleson South Washington Lee Other WRD Acreage Depth Contour Lines (ft) Interstate Pipelines WildHorse Comstock Apache Anadarko Halcon CWEI Other Enervest 2 2 J. Malazzo B H (WRD) IP30 = 850 BOE/D (73% oil) 26/64 Choke FTP,70 psi 7,842 LL (6/8/4) Grant 4H (Apache) IP30 = 67 BOE/D (86% oil) 7,726 LL (5/20/4) Walker Family 3H (Apache) IP30 =,377 BOE/D (66% oil) 8,833 LL (2/8/4) McCullough-Wineman 2H (Apache) IP30 =,208 BOE/D (62% oil) 8,407 LL (2/23/3) Fojt H (WRD) IP30 = 89 BOE/D (6% oil) 24/64 Choke FTP,380 psi 7,980 LL (/30/4) Smith H (WRD) IP30 =,76 BOE/D (60% oil) 24/64" Choke FTP,93 psi 8,309 LL (4/4/4) Hensz B H (WRD) IP30 = 898 BOE/D (7% oil) 24/64 Choke FTP,464 psi 6,3 LL (3/4/5) Johnston Unit 3 (Enervest) IP30 = 825 BOE/D (9% oil) 4,574 LL (9/28/3) Austin Chalk 7 Note: Offset operator well results on a 2-stream basis. WRD well results on a 3-stream basis. Unless noted otherwise, all acreage data as of March, 207; pro-forma for the pending acquisition of ~0,500 acres in Burleson County.. Data for WildHorse based on actual results reported by WildHorse management; peer data based on IHS Enerdeq horizontal wells drilled since 6/30/3. 2. See slide 8 for assumptions embedded in Eagle Ford IRR calculations.

8 API Mcf / STB 0,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000, Positioned in the Highly Productive, Liquids-Rich Core Geology matters: Gas to oil ratio Clay content Oil gravity Pore pressure geopressure of ~0.75 Psi / Ft The Eagle Ford is a Cretaceous sediment where the formation s carbonate content can exceed 70% in WRD s position Clay content increases in the Northeast portion of the play in Brazos and Madison counties Top of Eagle Ford Structural Map Milam Brazos Burleson Lee Grimes Bastrop Washington Waller Austin Fayette WRD Acreage Shallow -6,000' -7,000' -8,000' -9,000' -0,000' -,000' -2,000' -3,000' -4,000' Deep Milam Lee Gross Thickness Isopach Map Brazos Grimes Burleson Washington Waller Austin Fayette WRD Acreage Thick 500' 450' 400' 350' 300' 250' 200' 50' 00' 50' Thin High carbonate content and lower clay content allow more effective hydraulic fracturing Gross Eagle Ford thickness ranges from over 00 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 Oil Gravity Milam Brazos Lee Lee Washington Fayette WRD Acreage API Gas / Oil Ratio Milam Brazos Lee Washington Fayette WRD Acreage Mcf / STB 0,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000,

9 D&C Evolution Has Led to Increased Returns and Superior Well Performance Drilling and Completion Design Evolution Increased Intensity Has Improved EURs (EUR /,000 ft) New completion designs have enhanced average actual well EUR from 76 MBoe /,000 Ft to 97 MBoe /,000 Ft (28% increase) Slickwater XL technique (Gen 3) increased sand concentration and clusters per stage to further stimulate the reservoir and increase fractures in the target zone Gen 3 completion designs coupled with restricted choke management are expected to increase the long-term EUR of the well >90% improvement in drilling feet / day through process optimization and high spec rigs ~64% reduction in flat times through use of multi-well pads, offline cementing, walking packages and speedheads Proven and improving results in the Eagle Ford Gen 3 Completions Outperforming Type Curve (6 Mo Cum) Cum. Production (Boe) 00,000 80,000 60,000 Generation Hybrid completions Generation 2 Slickwater Generation 3 Slickwater XL 9% Outperformance MBoe $ / ft $3,000 $2,500 $2, ,225 6,447 6,233 Gen Gen 2 Gen 3 Wells Drilled Avg Lat Length (ft) Eagle Ford Average D&C Costs per Lateral Foot $2,958 40,000 20, Days Gen 3 Avg Boe Cum Burleson Main Type Curve $,500 $,000 $500 $0 $, $989 Gen Gen 2 Gen 3. Includes all Eagle Ford wells drilled and completed as of December 3, 206. Drilling and completion costs ( D&C ) exclude land costs and title fees. 9

10 Running Sum of 6 Month Cum. Production (MBoe) The Premier Operator Well Results Have Outperformed Peers Eagle Ford Running 6 Month Cumulative Production by Operator () 7,000 6,000 5,000 WildHorse wells have outperformed peers 4,000 3,000 WildHorse 2,000, Wells Drilled WildHorse Apache Anadarko Halcon Clayton Williams Comstock. WildHorse based on company data. Peer data based on HPDI Drilling Info. Includes wells with six months of production history. 0

11 Proximity to Gulf Coast Leads to Advantaged Oil Pricing WildHorse regional location provides lower operating costs and better realized pricing due to proximity to demand centers for oil, natural gas and NGLs Low basis differentials along the Gulf Coast represent competitive advantage when compared to other plays ($8.47) DJ Basin Comparative Basin Differentials () Bakken SCOOP / STACK Sufficient pipeline take-away capacity decreases risk of midstream bottleneck Potential upside to develop an integrated midstream system to service Eagle Ford assets ($6.39) Permian Basin ($7.0) WRD Eagle Ford Oil currently trucked but infrastructure in place to pipe ($3.50) ($2.83) ($4.37) South Texas Eagle Ford U.S. Shale Basins WTI Cushing # Basin Differential Source: Corporate Filings and Company Data.. Differentials based on average realized $/Bbl for the twelve months ended 2/3/6. Companies included in Permian: FANG, LPI, RSPP, CXO; Companies included in Eagle Ford: CRZO, SN; Companies included in DJ Basin: PDCE, SYRG, XOG; Companies included in Bakken: CLR, WLL; Companies included in SCOOP / STACK: NFX.

12 Eagle Ford Wells Outperform Competing Basins and Peers on Cash Margin Cash Margin: WRD Eagle Ford vs. Competing Basins () (Full Year 206) $/Boe $50.00 $43.40 $43.40 $43.40 $43.40 $43.40 $40.00 $30.00 $7.04 $2.80 $6.4 (2) $.8 $0.25 $9.76 $3.20 $7.34 $5.39 $3.86 $4.95 $3.0 $4.25 Commodity Mix Differential $20.00 $2.05 $5.98 $7.4 $5.39 $2.04 $.40 $.55 LOE (incl. Gathering Fees) $0.00 $25.6 $22.52 $8.28 $7.63 $7.26 Production & Ad Valorem Taxes Cash Margin $0.00 WRD Eagle Ford Permian Bakken Eagle Ford DJ Basin 2 Source: Company filings and investor presentations. Note: Assumes 6: gas to oil ratio. Commodity mix assumes NGLs at 35% of WTI. Does not include G&A and other corporate level costs.. Companies included in Permian: CXO, FANG, LPI and RSPP; Companies included in Eagle Ford: CRZO and SN; Companies included in DJ Basin: PDCE, SYRG and XOG; Companies included in Bakken: CLR and WLL. 2. All WRD Eagle Ford data pro forma for the Burleson North acquisition. WRD Eagle Ford LOE was $2.42 / Boe excluding the Burleson North Acquisition.

13 North Louisiana Acreage Position Contiguous Position in the Prolific Terryville Field 03,722 net acres across four areas in North Louisiana Ruston-Choudrant- Tremont ( RCT ) Field, Weyerhaeuser, Bear Creek and Athens Geologically analogous to RRC s Terryville Field Drilled operated horizontal wells to date Management drilled 55 wells for MRD / RRC prior to turning over operation in January net (,43 gross) locations in North Louisiana 493 net (946 gross) RCT drilling locations 27 net (40 gross) Weyerhaeuser drilling locations ~65% IRRs for RCT Upper Red (2) Q4 net production of ~40. MMcfe/d 94% natural gas High realized pricing given proximity to Henry Hub Wholly-owned midstream subsidiary enhances single-well economics Currently operating one rig and expect to add a second rig in Q2 207 Bellevue Timber 6-9 HC- (MRD) IP30 = 36.4 MMCFE/D (79% gas) 6,48 LL (4/29/5) DL Sanford 8-7 HC (MRD) IP30 = 3. MMCFE/D (79% gas) 7,00 LL (8/9/4) Davison 6-9 HC 2 (MRD) IP30 = 27.3 MMCFE/D (78% gas) 6,6 LL (2/5/4) Dowling 9-30-HC (MRD) IP30 = 29.4 MMCFE/D (8% gas) 6,624 LL (6/23/4) Dowling 9-30-HC 2 (MRD) IP30 = 3.9 MMCFE/D (8% gas) 6,624 LL (7/2/4) Lewis 2-28 HC #2 (MRD) IP30 = 26.5 MMCFE/D (85% gas) 7,752 LL (6/4/5) Dowling HC- (MRD) IP30 = 33.7 MMCFE/D (8% gas) 7,620 LL (6/6/5) TL McCrary HC-2 (MRD) IP30 = 24.6 MMCFE/D (8% gas) 7,00 LL (6/22/4) Werner HC-2 (MRD) IP30 = 28.4 MMCFE/D (82% gas) 8,300 LL (2/28/4) Temple 8-5 HC-3 (MRD) IP30 = 27.4 MMCF/D (85% gas) 7,40 LL (4/8/5) Claiborne Athens Bear Creek Bienville Athens Bear Creek Horizontal Well Activity () RRC Terryville Field Low Decline PDP Base with Horizontal Development Upside Horizontal Development Focus Area RCT Weyerhaeuser Jackson Lincoln WildHorse Acreage RRC Terryville Field WildHorse Wells RRC Wells RRC Expansion Wells RRC Permit Weyerhaeuser Union Ouachita Wright 3-24 HC 3 (MRD) IP30 = 30.4 MMCFE/D (83% gas) 6,606 LL (2/30/3) Colvin Estate HC (MRD) IP30 = 30.4 MMCFE/D (82% gas) 8,04 LL (4/20/4) Hearne 33-4 HC 4 (MRD) IP30 = 28.3 MMCFE/D (86% gas) 7,597 LL (0/28/4) Harrison 7 6 HC- (Nadel/WRD) IP24hr 5.3 MMcfe/d (98% gas; Flowing back) 4,245 LL (7/30/6) Williams -2H (Nadel & Gussman) IP30 = 4.0 MMCFE/D (95% gas) 4,49 LL (5/20/5) Spillers 8-7 HC- (WRD) IP30 = 9.4 MMCFE/D (98% gas) 8,884 LL (3/26/5) Ates 8 7 HC- (WRD) IP30 = 6.0 MMCFE/D (98% gas) 6,705 LL (9/7/5) Taylor 3-2 H- (WRD) IP30 = 2.8 MMCFE/D (98% gas) 6,796 LL (2//4) Smelley 5-22 HC- (WRD) IP30 = 7.0 MMCFE/D (97% gas) 8,40 LL (6/28/5) Elliott 2- HC- (Linn/WRD) IP24hr = 22.3 MMCFE/D (98% gas) 6,503 LL (3/3/5) 3. Source: Company data and estimates, MRD Investor Presentation, Louisiana Department of Natural Resources, and IHS Enerdeq. 2. See slide 29 for assumptions embedded in North Louisiana IRR calculations.

14 RCT The Extension of the Terryville Complex RCT acreage is located in close proximity to top performing Terryville Complex and is an extension to the southeast along the northern fault line Well logs show the reservoir is consistent across the acreage Well design evolution: Generation one cluster, fracture penetrates water bearing zone Generation 2 two clusters yields better fracture containment within the target zone Generation 3 three clusters with restricted choke program for flowback, further containment within target zone and reduces water yields and operating costs Well Design Case Study: Pruitt (Gen ) vs. Smelley (Gen 2) Pruitt and Smelley wells are direct offsets and well logs confirm similar reservoir quality Well results suggest Pruitt production is drawing from the water-bearing Pink zone, while Smelley production is contained within the Upper Red 3 2 Elliott 2- HC- (Linn/WRD) IP24hr = 22.3 MMcfe/d (98% gas) 6,503 LL (3/3/5) Harrison 7 6 HC- (Nadel/WRD) IP24hr 5.3 MMcfe/d (98% gas; Flowing back) 4,245 LL (7/30/6) Pruitt 6 2 HC- (WRD) IP MMcfe/d (98% gas) 9,02 LL (2/7/5) Smelley 5-22 HC- (WRD) IP30 = 7.0 MMcfe/d (97% gas) 8,40 LL (6/28/5) Taylor 3-2 H- (WRD) IP30 = 2.8 MMcfe/d (98% gas) 6,796 LL (2//4) Taylor 3-2 H-2 (WRD) IP30 = 8.6 MMcfe/d (98% gas) 4,594 LL (/2/5) Claiborne Bienville Water-Bearing Zone Lincoln Jackson Union Ouachita Lincoln Generation One Cluster per Stage Jackson 3 Williams -2H (Nadel & Gussman) IP30 = 4.0 MMcfe/d (95% gas) 4,49 LL (5/20/5) Union Ouachita WRD Completion Generation 2 Generation 2 Two Clusters per Stage 3 Water-Bearing Zone 2 Ates 8 7 HC- (WRD) IP30 = 6.0 MMcfe/d (98% gas) 6,705 LL (9/7/5) Rounsaville 2 6 HC- (WRD) IP30.5 MMcfe/d (99% gas) 4,633 LL (4/23/5) Pipes 4 HC- (WRD) IP MMcfe/d (97% gas) 8,22 LL (/6/5) Surline 3 2 HC- (WRD) IP30.6 MMcfe/d (98% gas) 7,20 LL (5/23/5) Spillers 8-7 HC- (WRD) IP30 = 9.4 MMcfe/d (98% gas) 8,884 LL (3/26/5) Weyerhaeuser RCT RRC Terryville WildHorse Wells Fault Line 4

15 Superior Well Performance Combined with Premium Pricing Leads to Best-in-Class Economics Proximity to Gulf Coast Provides High Gas Realizations and Access to Future Demand Growth Primary Demand Drivers () A Proximity to New LNG Exports Facilities Five LNG export facilities are FERC approved and under construction with four on the USGC Capacity of the approved facilities is fully contracted with take-or-pay tolling agreements with end-users in Asia and Europe, and major LNG traders portfolio B Proximity to Expanding USGC lndustrial Demand Growth driven by projects exploiting the competitive and regional advantage of cheap natural gas and NGLs Industrial demand growth is centered in the USGC petrochemical sector C Proximity to Increased Mexican Import Needs Expansion of Mexico s gas pipeline and power transmission infrastructure Progress in generation build out for underserved regions of Mexico C C Northern Louisiana Northern Hub (2) Louisiana ($0.08) Hub (2) Exports to Mexico Exports to Mexico Incremental 3.5 Bcf/d Incremental 3.5 Bcf/d $ Discount to Henry $ Hub Discount to Henry Hub by 2020 by 2020 Henry Hub B Henry Hub B USGC Industrial USGC Industrial Demand Demand A A LNG Export Incremental 5.5 LNG Export Incremental 5.5 Bcf/d by 2020 Incremental 8.5 Bcf/d Bcf/d by 2020 Incremental by Bcf/d by 2020 ($0.08) Terryville Complex Terryville Complex ($.05) ($.05) Dominion South Marcellus (3) Dominion South Marcellus (3) 5. Source: Mexico Secretariade Energy (SENER), US Energy Information Administration (EIA), US Federal Energy Regulatory Commission (FERC), University of Texas Center for Energy Economics (CEE), Mobius Risk Group estimates. 2. Northern Louisiana Hub reflects the Year to Date average basis at Columbia Mainline as of /5/6. 3. Dominion South Marcellus reflects the Year to Date average basis at Dominion South Hub as of /5/6.

16 North Louisiana Wells Outperform Competing Basins and Peers on Cash Margin 206 Cash Margin: WRD North Louisiana vs. Competing Basins () (Full Year 206) $/Mcfe $3.00 $2.92 $2.50 $2.69 $0.4 $0.0 $0.0 $0.38 $0.37 $0.73 $2.65 $0.0 $0.48 $ Average HHUB Price $2.00 $0.2 Commodity Mix $.50 $0.69 (3) $0.9 Differential $.00 $.95 $0.08 $0.4 $0.09 Gathering, Processing, & Transportation (2) LOE $0.50 $.06 $0.93 Production & Ad Valorem Taxes Cash Margin $0.00 WRD NLA Diversified Gas Marcellus 6 Source: Company filings and investor presentations. Note: Assumes 6: gas to oil ratio. Commodity mix assumes NGLs at 35% of WTI. Due to commodity mix, company and basin Mcfe prices surpass the $2.55 full year 206 average HHUB Price. Does not include G&A and other corporate level costs.. Companies included in Marcellus: RICE, EQT, AR, COG, RRC. Companies included in Diversified Gas: SWN, CHK. 2. Gathering, Processing, & Transportation fees exclude intercompany eliminations for non-wholly owned consolidated subsidiaries. 3. Includes GP&T expense.

17 7 IV. Financial Overview

18 WildHorse Financial Strategy Preserve Financial Flexibility Ample liquidity to carry out 207 capital development plan Target leverage at conservative levels (Net Debt / EBITDAX < 2.0x) Low Cost Operator Focus on low cost operations and maintaining strong operating margins Allocate capital among projects and areas that optimize drill-bit F&D Grow reserves and production by redeploying operating cash flows into high return areas Hedge to Secure Cash Flows Lock in commodity prices to reduce cash flow volatility and ensure rate of return Protect drilling program to fund efficient production growth Increased hedge position post-ipo by 9,000+ MBoe and FY7 hedges by ~80% to 6,530 Mboe (72% of estimated 207 production, based on mid-point of guidance) Maintain Liquidity To Support Future Growth History of prudently managing balance sheet Ready access to the capital markets and maintain revolver availability Selectively pursue accretive acquisitions and fund conservatively on a debt / equity basis over the long-term 8

19 Pro Forma Capitalization Capital Markets Activity & Revolving Credit Facility Capitalization Initial Public Offering (includes partial exercise of overallotment option) Shares Issued: 29,797,00 Price per Share: $5.00 Gross Proceeds: $447.0 MM Net Proceeds: $424.3 MM Total shares outstanding: 93,987, % Senior Unsecured Notes due 2025 Principal Amount: $350.0MM Revolving Credit Facility ($ in millions) As of December 3, 206 Cash and cash equivalents $33 Long-term debt: Credit facility % Senior Unsecured Notes 350 Total long-term debt $350 Total owners and stockholders equity $,040 Total capitalization $,390 Full Year 206 Adjusted EBITDAX 2 $3 Net Debt / Full Year 206 Adjusted EBITDAX.9x 5 year term (202) Borrowing base reduced from $450MM to $362.5MM concurrent with Senior Notes offering (undrawn as of March 28, 207) Significant capacity for additional hedging 9. As of 2/3/6 pro forma for the partial exercise of over-allotment option and issuance of $350MM in senior unsecured notes. 2. Adjusted EBITDAX is a non-gaap financial measure. See appendix for reconciliations to our most directly comparable financial measure calculated and presented accordance with GAAP.

20 Fiscal Year 207 Guidance Full Year 207 Guidance Net Average Daily Production (Mboe/d) Oil (% of Production) Natural Gas (% of Production) NGLs (% of Production) Average Costs (per Boe) Lease Operating Expense Gathering, Processing, and Transportation Taxes Other than Income Cash General and Administrative () 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) 207 FY Guidance Low High % - 56% 35% - 38% 8% - 0% ($2.75) - ($3.25) ($0.95) - ($.5) ($2.00) - ($2.25) ($2.75) - ($3.25) 95% - 00% 95% - 00% 22% - 27% Drilling Program Wells Spud (Gross) 90-0 Wells Completed (Gross) D&C Capital Expenditure ($MM) $450 - $ Note: Guidance as of February 28, 207. 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. 2. Based on strip pricing as of February 23, 207

21 WildHorse Commodity Hedging Overview WildHorse s commodity risk management policy provides for hedging estimated production from total proved reserves Proactive policy reduces WildHorse s exposure to movements in commodity prices and provides stability to free cash flow All trading counterparties have investment grade credit ratings at both S&P and Moody s Current hedges include primarily costless, fixed price swaps and collars, as well as deferred premium puts Hedge Summary as of March 28, Natural Gas Hedge Contracts: Total natural gas volumes hedged (BBtu) 7,757,566 9,878 Volumes Hedged (MMBtu/d) 48,650 3,687 27,063 Total weighted-average price () $3.2 $3.03 $2.8 % of 207 estimated production 89% Crude Oil Hedge Contracts: Total crude oil volumes hedged (MBbls) 3,570,664,38 Volumes Hedged (Bbl/d) 9,78 4,558 3,784 Total weighted-average price () $53.75 $53.72 $54.92 % of 207 estimated production 72% Total Hedge Contracts: Total hedged production (Mboe) 6,530 3,59 3,028 Volumes Hedged (Boe/d) 7,889 9,839 8,295 Total weighted-average price ($/boe) () $38. $34.64 $34.24 % of 207 estimated production 72%. Using the midpoint for collars. 2

22 Investment Highlights Attractive Acreage Position with Strong Returns Extensive Inventory Supports Multi-Year Growth Story Balanced Asset Portfolio with Significant Capital Allocation Optionality Financial Strength and Flexibility Experienced, Proven and Aligned Management Team 22

23 23 V. Appendix

24 EGN CPE CRZO MTDR RSPP WPX SYRG PE LPI WRD SM XOG PDCE GPOR RICE % RSPP CPE PE CRZO WRD XOG SYRG MTDR EGN RICE GPOR LPI PDCE SM WPX 4% $.02 $.56 9% 50% $2.70 $3.5 $3.36 $4.74 $4.67 $4.23 $4.5 $4.3 $ % 77% 72% $ % 53% 56% $6.38 6% 6% 5% 50% 48% 48% 46% 45% 79% $ % 56% 73% 59% 6% $ % 64% 63% 84% 68% 7% Low Cost Operator with Leading Margins Full Year 206 LOE / Boe Cost and % Liquids Full Year 206 Unhedged EBITDAX Margin () $/Boe $0.00 % Liquids 00% 80% $ % 60% $ % 40% $4.00 $ % 20% $0.00 0% 0% 24 Source: Public Filings. Note: WildHorse full year 206 LOE pro forma for Burleson North.. Adjusted EBITDAX and Unhedged EBITDAX Margin are non-gaap financial measures. See appendix for reconciliations to our most directly comparable financial measure calculated and presented in accordance with GAAP.

25 EUR Improvement Summary Type Curve Economics Burleson Main Burleson Main Single Well Summary Type Well Assumptions Wellhead EUR (MBoe) 555 Oil EUR (Mbbl) 497 % Oil 90% Gas EUR (MMcf) 348 Sales EUR (MBoe) 594 Oil EUR (Mbbl) 497 Gas EUR(MMcf) 29 NGL EUR (Mbbl) 60 % Gas 6% % Oil 84% % NGL 0% % Liquids 94% GOR (Mcf/bbl) 0.70 Lateral Length (ft) 6,500 Shrinkage 63% Variable Water Cost ($/Water Bbl) $0.90 Type Curve 30-day Oil IP (Bbl/d) day Gas IP (Mcf/d) day IP (Boe/d, 3-Stream) day IP (Boe/d) per,000' 4 Initial Decline (%) 78% B Factor.40 Terminal Decline (%) 6% Summary () Net Drilling Locations (3) 649 EUR /,000 Foot (MBoe) 9 D&C ($MM) $5.6 D&C / Foot $862 NPV0 ($MM) $5.6 IRR (%) 55% Boe/d, Burleson Main Single Well Type Curve (with recent Gen 3 well results) Month Burleson Main Type Curve Gen 3 Avg Boe IRR Sensitivity (2) Oil Price $45.00 $50.00 $55.00 $60.00 $ % 27% 36% 46% 58% 72% 5% 3% 4% 53% 66% 82% 0% 35% 46% 59% 75% 92% 5% 39% 52% 66% 84% 04% 20% 43% 58% 74% 93% 6% 25. Consensus Pricing as of 2/22/207: $55.05 / $3.2 for 207, $59.07 / $3.2 for 208, $63.2 / $3.27 for 209, $64.98 / $3.40 for 2020 and thereafter for WTI and Henry Hub respectively. 2. IRR sensitivities assume $3.00 Henry Hub for the life of the well. 3. See slide 9 for further information regarding our drilling locations.

26 Significant Proven Austin Chalk Reservoir Leads to Attractive Co-Development Opportunity Austin Chalk / Eagle Ford Co-Development Potential Burleson, Washington and Lee County Austin Chalk Wells Vertical Wells And First Few Horizontals (Boe),000,000 00,000 Potential for stacked / staggered development in Austin Chalk and Eagle Ford across WRD s acreage position Based on early evaluations, WRD believes the Austin Chalk could potentially produce single well returns in line with the company s Burleson core and North Louisiana acreage So far, WRD has identified an area of approximately 60,000 to 80,000 net acres with redevelopment potential in the Austin Chalk WRD recently spud its first Austin Chalk well and expects to see results in the second half of 207 Nearby operators have recently had success in the Austin Chalk st Year Cumulative Production (28 Samples) Horizontal Development Infill Horizontal Development New Enervest Wells Bastrop Austin Chalk Producing Wells Horizontal Vertical Lee Milam Brazos Karnes County Austin Chalk Wells Total Burleson Washington Lee Karnes Total, ,478 Burleson Fayette Wilson Robertson Washington Austin Vertical Horizontal GeoSouthern Rig New Enervest Wells DeWitt Vertical Horizontal 0,000,000 Atascosa Karnes Goliad Historical Austin Chalk Enervest Multi-fracs Although the industry has known about the Austin Chalk for many years, it took a new approach to turn it into a high rate of return play which competes with EOG's top-tier assets. We expect the Austin Chalk to make a meaningful contribution to our future success. - Bill Thomas, CEO, EOG Resources (2Q 6 Earnings Call) Note: Maps include currently producing horizontal and vertical wells as of /5/6. 26

27 EUR Improvement Summary Type Curve Economics RCT Upper Red Single Well Summary Type Well Assumptions Wellhead EUR (MMcfe) 4,592 Gas EUR (MMcf) 4,275 Oil EUR (Mbbl) 53 % Gas 98% Sales EUR (MMcfe) 4,52 Gas EUR(MMcf) 4,204 Oil EUR (Mbbl) 53 % Gas 98% % Oil 2% Choke (Mmcfd/,000').5 Flat Time (Days) 20 Oil Yield (bbl/mmcf) 3.7 Lateral Length (Ft) 7,500 Shrinkage 99.5% BTU Factor,090 Type Curve 30-day Gas IP (Mcf/d), day Oil IP (Bbl/d) day IP (Mcfe/d), day IP (Mcfe/d) per,000',533 Initial Decline (%) 65% B Factor.40 Terminal Decline (%) 5% Summary() Net Drilling Locations (4) 493 EUR /,000 Foot (Bcfe).9 D&C ($MM) $8.4 D&C / Foot $,20 NPV0 ($MM) $9.3 IRR (%) 67% MMcfe/d 0 Restricted Rate RCT Upper Red Single Well Type Curve IRR Sensitivity (2) Cumulative Production (Bcfe) 0, Month Type Curve Type Curve Cum Average of Representative Wells (3) Gas Price,000 $2.00 $2.50 $3.00 $3.50 $4.00 0% 5% 3% 52% 78% 2% 5% 8% 35% 58% 89% 26% 0% 20% 40% 66% 00% 42% 5% 23% 44% 74% % 59% 20% 26% 50% 82% 24% 78% Consensus Pricing as of 2/22/207: $55.05 / $3.2 for 207, $59.07 / $3.2 for 208, $63.2 / $3.27 for 209, $64.98 / $3.40 for 2020 and thereafter for WTI and Henry Hub respectively. Excludes inter-company gathering fees to wholly-owned midstream system. 2. IRR sensitivities assume $50.00 WTI for the life of the well. 3. Representative wells include the Smelley 5-22 HC-, Ates 8 7 HC-, Spillers 8-7 HC- and Taylor 3-2 H-. 4. See slide 9 for further information regarding our drilling locations.

28 Lower Red Upper Red WildHorse Position is a Direct Offset to RRC Terryville Field Terryville Field RCT Terryville Complex A A B B Regional reservoir continuity Consistent drilling targets Stacked horizontal targets 20 + miles A A RCT Weyerhaeuser RRC Terryville Fault Line Lincoln B B Union Jackson Ouachita Source: Company data. 28

29 Natural Gas Hedge Summary Natural Gas Hedge Summary - As of March 28, Swap contracts: Volume (BBtu) 9,030,566 9,878 Volume (MMBtu/d) 24,739 3,687 27,063 Weighted-average fixed price $3.5 $3.03 $2.8 Collar contracts: Volume (BBtu) 5,520 Volume (MMBtu/d) 5,23 Weighted-average floor price $3.00 Weighted-average ceiling price $3.36 Put options: Volume (BBtu) 3,207 Volume (MMBtu/d) 8,788 Weighted-average strike price $3.40 Weighted-average put premium ($0.37) Total Natural Gas Hedge Contracts : Total natural gas volumes hedged (BBtu) 7,757,566 9,878 Total natural gas volumes hedged (MMBtu/d) 48,650 3,687 27,063 Total Weighted-Average Price Total weighted-average price (excluding puts) $3.6 $3.03 $2.8 Total weighted-average price (including puts) $3.2 $3.03 $2.8. Using the midpoint for collars. 29

30 Crude Oil Hedge Summary Oil Hedge Summary - As of March 28, Swap contracts: Volume (MBbl) 2,46,639,38 Volume (Bbl/d) 5,880 4,489 3,784 Weighted-average fixed price $52.90 $53.68 $54.92 Collar contracts: Volume (MBbl) 6 25 Volume (Bbl/d) Weighted-average floor price $50.00 $50.00 Weighted-average ceiling price $62.0 $62.0 Put options: Volume (MBbl),363 Volume (Bbl/d) 3,734 Weighted-average strike price $55.00 Weighted-average put premium ($4.77) Total Crude Oil Hedge Contracts: Total crude oil volumes hedged (MBbl) 3,570,664,38 Total crude oil volumes hedged (Bbl/d) 9,78 4,558 3,784 Total Weighted-Average Price Total weighted-average price (excluding puts) $52.98 $53.72 $54.92 Total weighted-average price (including puts) $53.75 $53.72 $ Using the midpoint for collars. 30

31 June 30, 206 December 3, 206 WildHorse Resource Development CG&A Reserve Detail Oil Natural Gas NGLs Total % Gas PV-0 (MBbl) (MMcf) (MBbl) (MBoe) (%) ($M) PDP 8,449 36,530 3,674 44,878 5% $36,89 PDNP 743 9, ,392 65% $8,565 PUD 68,255 79,222 7,09 05,235 28% $370,233 Total Proved 87, ,03 0,874 52,505 36% $749,988 Probable 05, ,55 0,790 50,202 23% $366,727 2P Reserves 92, ,654 2, ,707 29% $,6,75 Possible 237,364,540,204 22,49 56,23 50% $847,809 3P Reserves 430,298 2,068,858 43,82 88,920 42% $,964,524 Oil Natural Gas NGLs Total % Gas PV-0 (MBbl) (MMcf) (MBbl) (MBoe) (%) ($M) PDP 9,33 34,087 2,600 34,260 65% $228,98 PDNP 8 7,932 0,330 99% $2,75 PUD 40,385 58,746 4,976 7,89 37% $97,938 Total Proved 49, ,764 7,575 07,409 47% $429,67 Probable 6,288 9,398 7,439 00,627 32% $266,839 2P Reserves 0, ,63 5,05 208,035 39% $696,50 3. Based on SEC pricing of $43.2 per barrel and $2.24 per mmbtu as of June 30, 206, and $42.75 per barrel and $2.48 per mmbtu as of December 3, 206. Audited locations does not include management locations. 2. See slide 46 for cautionary statements and additional disclosures regarding 3P reserves

32 32 Reconciliation of Adjusted EBITDAX 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; stockbased compensation; incentive-based compensation expenses; exploration costs; provision for environmental remediation; transaction related costs; IPO related expenses; and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and cash settlements paid; gains on sale of assets and other non-routine items. WildHorse 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. WildHorse'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 WildHorse does. The following table presents the Pro Forma information () for the periods indicated. Additional Pro Forma information disclosed on the press release issued March 29, 206. Three Months Year Ended Ended December 3, December 3, (Amounts in $000s) Net Income (loss) $ (3,95) $ (34,894) Add (Deduct): Interest expense, net 2,225 7,834 Income tax (benefit) expense (6,025) (5,575) Depreciation, depletion an amortization 24,09 98,298 Exploration expense 3,050 2,026 Impairment of proved oil and gas properties - - (Gain) loss on derivative instruments 8,077 26,77 Cash settlements received / (paid) on commodity derivatives (,093) 4,975 Stock-based compensation Acquisition related costs (Gain) loss on sale properties Debt extinguishment costs,309,667 Initial public offering costs 378,560 Non-cash liability amortization - (286) Adjusted EBITDAX $ 28,620 $ 3,040 () Our calculations for the pro-forma fourth quarter and full year 206 were calculated with unaudited lease operating statements provided by CWEI during the acquisition process. As a result, the pro-forma calculations leave out expenses associated with corporate overhead items such as CWEI s G&A expense as well as the impact of CWEI s commodity hedges. Reported GAAP fourth quarter 206 and full year 206 results are also provided in this presentation. Because entities contributed to us in connection with our initial public offering were under common control, our predecessor s historical financial statements have been recast and accounted for as a combination of entities under common control. As such, the financial data presented herein (i) (a) as of, and for the year ended, December 3, 206, and (b) as of December 3, 205, and for the period from February 7, 205 (the inception of common control) to December 3, 205, have been derived from the consolidated and combined financial position and results attributable to our predecessor and previous owner contributed to us for periods prior to our initial public offering and (ii) for the period from January, 205 to February 6, 205, have been derived from the financial position and results attributable to our previous owner.

33 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-0 and 3P Reserves PV-0 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 0% per annum to reflect timing of future cash flows and using SEC pricing assumptions in effect at the end of the period. SEC pricing for oil and natural gas of $42.75 per Bbl and $2.48 per MMBtu; $43.2 per Bbl and $2.24 per MMBtu; and $50.28 per Bbl and $2.59 MMBtu was based on the unweighted average of the first-day-of-the-month prices for each of the twelve months preceding December 206, June 206, and December 205, respectively. PV-0 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-0 estimates of probable and possible reserves are more uncertain than PV-0 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-0 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-0 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from reserves on a more comparable basis. The following table provides a reconciliation of PV-0 of WRD s proved reserves to the Standardized Measure of discounted future net cash flows at December 3, 206, 205 and 204: Neither PV-0 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-0 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 3, 206 have been prepared by WildHorse s internal reserve engineers and audited by Cawley, Gillespie & Associates, Inc. ( CGA ), WildHorse s independent reserve engineers. The estimates of proved, probable and possible reserves as of June 30, 206 included in this presentation with respect to Esquisto Resources II, LLC have been prepared by CGA, and the estimates of proved, probable and possible reserves as of June 30, 206 included in this presentation with respect to WildHorse Resources II, LLC have been prepared by WildHorse s internal reserve engineers and audited by CGA. 33

34 Cautionary Statements and Additional Disclosures WRD has provided summations of its proved, probable and possible reserves and summations of its PV-0 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-0 of probable reserves, as well as the underlying volumetric estimates, are inherently more uncertain of being recovered and realized than comparable measures for proved reserves, and that the uncertainty for possible reserves is even more significant. Further, because estimates of probable and possible reserve volumes have not been adjusted for risk due to this uncertainty of recovery, their summation may be of limited use. Actual quantities that may be ultimately recovered from WildHorse s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of WildHorse s ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates. EUR or Estimated Ultimate Recovery, when referring to a currently producing well, refers to the sum of total gross remaining proved reserves attributable to each location in WildHorse s reserve report and cumulative sales from such location. EUR is shown on a combined basis for oil/condensates, gas and NGLs after the effects of processing. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineers Petroleum Resource Management System or the SEC s rules. Management Locations WRD has disclosed net horizontal drilling locations in this presentation in the proved, probable, and possible categories as audited by CG&A, WRD s third party engineers, as well as 650 drilling 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 those 2,350 net horizontal drilling locations,,700 lie within the geographic areas to which proved, probable and possible reserves are attributed. The remaining 650 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. 34

35 Cautionary Statements and Additional Disclosures 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): 206 D&C and other expenditures $7.8 Reserve additions (Mboe): Extensions, discoveries and additions 26.9 Performance revisions (2.3) Total additions 24.6 Total Drill-bit F&D costs ($/boe) $4.79 Cash General and Administrative Expenses per Boe Our presentation of cash general and administrative ("G&A") expenses per Boe is a non-gaap measure. We define cash G&A per Boe as total G&A determined in accordance with U.S. GAAP less non-cash equity compensation expenses, expressed on a per-boe basis. We report and provide guidance on cash G&A per Boe because we believe this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than, total G&A per Boe as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. 35