Lonestar Resources US, Inc. Enercom August 21st, 2018
Disclaimer and Forward Looking Statements Forward Looking Statements The information in this presentation includes “forward‐looking statements” that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact included in this presentation, regarding our strategy, future operations, financial position, projected costs, prospects, plans and objectives of management are forward‐looking statements. When used in this presentation, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward‐looking statements, although not all forward‐looking statements contain such identifying words. These forward‐looking statements are based on Lonestar Resources US Inc.’s (“LONE” or the “Company”) current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. We caution you that these forward‐looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, variations in the market demand for, and prices of, crude oil, NGLs and natural gas, lack of proved reserves, estimates of crude oil, NGLs and natural gas data, the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing, borrowing capacity under our credit facilities, general economic and business conditions, failure to realize expected value creation from property acquisitions, uncertainties about our ability to replace reserves and economically develop our reserves, risks related to the concentration of our operations, drilling results, potential financial losses or earnings reductions from our commodity price risk management programs, potential adoption of new governmental regulations, our ability to satisfy future cash obligations and environmental costs and the risk factors discussed in or referenced in our filings with the United States Securities and Exchange Commission (“SEC”), including our Annual Report on Form 10‐K, our Quarterly Reports on Form 10‐Q and our Current Reports on Form 8‐K. You are cautioned not to place undue reliance on any forward‐looking statements, which speak only as of the date of this presentation. Except as otherwise required by applicable law, we disclaim any duty to update any forward‐looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this presentation. Our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or cost increases. Reconciliation of Non‐GAAP Financial Measure EBITDAX is a financial measure that is not presented in accordance with generally accepted accounting principles in the United States (“GAAP”). Reconciliations of this non‐ GAAP financial measure can be found in this presentation. Industry and Market Data This presentation has been prepared by LONE and includes market data and other statistical information from third‐party sources, including independent industry publications, government publications or other published independent sources. Although LONE believes these third‐party sources are reliable as of their respective dates, LONE has not independently verified the accuracy or completeness of this information. Some data are also based on the LONE’s good faith estimates, which are derived from its review of internal sources as well as the third‐party sources described above. 2
Experienced Management Team Executive Previous Experience Biography . John H. Pinkerton 37 years experience in the oil and gas industry . Founder, Chairman and Chief Executive Officer Range Resources Chairman of the Board . Built Range Resources into a $10 billion Exploration & Production company Frank D. Bracken, III . 32 years experience in oil and gas finance . Previously Managing Director at Jefferies LLC, where he led >$5 billion in oil and gas transactions Chief Executive Officer GOG . Former CFO / Director of Gerrity Oil & Gas Corp, a NYSE‐listed DJ Basin E&P Company Gerrity Oil & Gas . 33 years oil and gas industry experience Barry D. Schneider . Senior level expertise in management of regional business units at large independent oil & gas Chief Operating Officer companies . Previously with US public companies Denbury Resources and Conoco‐Phillips . 33 years in all aspects of oil and gas exploration and development Jana Payne . Geologic Manager for Petrohawk, responsible for discovery of Hawkville Field, first commercial Eagle Ford Shale well in 2008 VP – Geosciences . Senior Exploitation Manager for Halcon Resources . Experience in Eagle Ford, Haynesville, Bossier, Utica and Tuscaloosa Marine Shales . Over 37 years oil and gas industry experience Tom H. Olle . Senior level expertise in reservoir management / project development across a broad array of VP – Reservoir Engineering reservoir types . Senior roles at US public companies Encore Acquisition Corp and Burlington Resources High Caliber Executive Team with Deep Industry Expertise and 30 Years of Average Experience 3
Company Profile . Pure Play Eagle Ford Operator… Share Price YTD • +60,000 Net Acres in the Crude Oil Window of the Eagle Ford Shale $12.00 $7.99 500 • Unfettered access to oil and gas transportation infrastructure $11.00 $10.00 • 100% LLS‐Based Oil Sales‐ Current Oil Price = Premium to WTI 400 $9.00 • Technical leader in the Eagle Ford, drilling extended reach laterals with proprietary $8.00 targeting and completion techniques, yielding differential results 300 $7.00 Shares) (US$) $6.00 ('000 . …With Proven Operational Excellence Price $5.00 200 • Increased Proved Reserves 82% YOY to 73.6 MMBoe in 2017 $4.00 Share 1 $3.00 Volume • Strip PV‐10 increased 70% YOY to $647.6 MM 100 $2.00 • Proved PV‐10 Per Share‐ $10.98 per share4 $1.00 . Quality Drilling Inventory Built at Low Costs $0.00 0 1 • 254 drilling locations Volume LONE Equity Price • Oil‐intensive drilling inventory‐ reserves are 86% crude oil & NGL’s • 5‐year All‐Sources Finding & Onstream Costs of $8.94 per Boe Enterprise Value . Balance Sheet Improvement Sets Up Rapid Growth Ticker (NASDAQ:NMS) LONE • $250 MM Senior Unsecured Notes push maturities into 2023 2 • Borrowing Base recently increased from $160 MM to $190 MM Share Price $7.99 • Liquidity currently $108 MM Shares Out (Fully Diluted) 3 38.8 MM . 2018 Is A Breakout Year For Lonestar Market Cap $310 MM • Rigs under contract to drill 2018 Program along with a dedicated Frac Spread • 2Q18 production increased 43% sequentially Cash3 $5.5 MM 5 • 2018 Production Guidance increased again to 10,600 – 11,200 Boe/d (+68% vs. 2017) Long Term Debt3 $334 MM • 2018 EBITDAX Guidance recently increased to $115 ‐ $130 MM (+89% vs. 2017) 5 • Growth can be achieved while improving leverage metrics‐ from 3.4x in 1Q18 to the Enterprise Value $639 MM low‐2’s by year‐end 2018 1Based on YE17 Reserve Report 2August 17, 2018 3At June 30, 2018 4 Net of debt and preferred obligations, at NYMEX Strip at 12/31/18 5 At mid‐ point of guidance 4
2018‐ A Breakout Year For Lonestar’s Financials Disciplined Capital •2018 Drilling &Completion Program‐ 85% to 90% funded by Spending internally generated cash flow Premium Hydrocarbon •100% oil sold at LLS basis‐ currently a premium to WTI Pricing •Natural gas garnering NYMEX pricing High IRR Drilling •Oil‐focused Eagle Ford Shale drilling program Program •2018 program IRR’s average 78%2 Rapid Production •2Q18 Results‐ up 43% sequentially3 Growth •2018 Guidance‐ up 68%, year‐over‐year3 Rapid Cash Flow Per •Anticipate 100% Increase in 2018 Fully Diluted CFPS to $2.323 Share Growth Improving Leverage1P PV‐10 ($mm) •Debt/EBITDAX reduced from 5.4x to 2.8x in last 4 quarters $40 $350 $30 $250 $20 $150 $10 $50 $0 Dec‐10Dec‐11Dec‐12oday T •Debt/EBITDAX projected to fall to 2.5x at YE18 Ratios BarnetEFSAMUt 1 Weighted average of 2018 Working Interest and assumes $65 flat oil & $3.00 flat gas, 3 at midpoint of guidance 5
Lonestar’s Footprint Production 11,140 Boe/d Eastern 6,495 Boe/d NGL's 22% Oil 67% Oil 57% NGL's 16% Gas 21% Gas 17% Central FY ‘17 2Q18 Proved Reserves1 Western 76.2 MMBoe 44.9 MMBoe Oil 69% Oil 60% NGL's 15% NGL's 18% Engineered Acreage* Gas * Gas Non‐Engineered Acreage 21% 16% Acquired Acreage 2016 2017 PV‐10 Value1 Proved Reserves 1 PV‐10 1 Proved Proved $648MM Net Engineered Avg. Developed PUD Proved Developed Total Proved Region Acres Locations WI HBP (MMBOE) (MMBOE) (MMBOE) ($MM) ($MM) $382 MM Western 18,447 51 88% 96% 8.6 21.6 30.1 $100.6 $224.4 Central 31,861 173 70% 96% 10.3 31.7 41.9 $180.4 $392.0 Central 61% Western 35% Eastern 9,729 30 68% 65% 0.8 3.4 4.2 $13.3 $31.2 Western 68% Central 23% Total 60,037 254 74% 91% 19.6 56.6 76.2 $294.3 $647.6 Eastern Eastern 10% 5% 1 * 12/31/2017Reserves based on NYMEX Strip as of 1/2/2018 Please see the reserves disclosures at the end of this presentation 2016 2017 6
2017 Capital Results vs. Peers 2017 Reserve Replacement Ratio 2,000% 1,499% Production 1,500% 2017 of % a 1,000% as 776% 500% Replacement 0% Reserve WRD LONE SRCI AXAS SN HK PVAC SBOW MTDR XOG LPI CXO CLR Peer Average All Sources Finding & Onstream Costs $30.00 $25.00 ($/Boe) $20.00 Costs $15.00 1P PV‐10 ($mm) $10.68 Onstream $10.00 $40 $350 $30 $250 $20 $150 $10 $50 $0 Dec‐10Dec‐11Dec‐12oday T & $6.07 $5.00 BarnetEFSAMUt Finding $0.00 SBOW WRD AXAS LONE SRCI SN LPI PVAC MTDR CLR CXO HK XOG Peer Average 7 Note: Figures above calculated from data publically disclosed from the peer companies
Crude Oil Weighted Production Yields High Margins 2Q18 LOE / Boe Cost and % Liquids 2Q18 EBITDAX Margin $/BOE % Liquids $/BOE % Liquids $10.00 100% $50.00 100% 87% 87% 84% 84% 90% $45.00 84% 90% 79% 79% $8.00 75% 80% $40.00 84% 75% 80% 70% 72% 72% 70% 67% 65% 67% 63% 70% $35.00 63% 65% 70% 55% $6.00 56% 60% $30.00 55% 56% 60% 50% $25.00 50% $4.00 40% $20.00 40% 30% $15.00 30% $2.00 15% 20% $10.00 15% 20% 10% $5.00 10% $10.73 $7.69 $6.24 $5.62 $5.19 $4.57 $4.32 $3.70 $3.49 $3.10 $2.84 $2.68 $1.56 $44.94 $28.44 $24.90 $34.69 $19.42 $18.54 $43.61 $28.20 $29.02 $25.90 $25.23 $35.33 $0.00 0% $0.00 $14.22 0% SN HK LPI CLR SN HK LPI CXO XOG SRCI CLR WRD PVAC CXO AXAS LONE XOG SRCI MTDR WRD SBOW PVAC AXAS LONE MTDR SBOW Source: Company Press Releases for three months ended June 30, 2018, EBITDAX adjusted to eliminate the effects of the cash settlement of commodities hedges in the period 8
Rapidly Improving Financial Metrics Average Daily Production vs. Annualized Adjusted EBITDAX1 Debt / Adjusted EBITDAX $210 14,000 6.0x $180 12,000 5.5x 5.0x $150 10,000 ($MM) (Boepd) 4.5x $120 8,000 4.0x $90 6,000 EBITDAX 3.5x Production $60 4,000 3.0x $30 2,000 Daily 2.5x Annualizeed $0 0 2.0x 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 Est. Est. Est. Est. LQA EBITDAX excl. Hedging Hedging Revenue Hedging Expense Production 1 Annualized Adjusted EBITDAX is reported quarterly Adjusted EBITDAX multiplied by 4 9
Strip PV‐10 Per Share‐ 2017 Strip PV‐10 1 Strip PV‐101 Less Net Debt (Per Share) $700 $647.6 $700 $10.98 $600 $600 $500 $500 $400 $382.0 $8.27 $400 Net PV‐10 $300 PV‐10 $300 Preferred $200 Net Debt $200 $100 $100 $0 $0 2016 2017 2016 2017 1NYMEX pricing as follows:$ 59.55/Bbl for oil for 2018, $56.22 for 2019, $56.22 for 2020, $53.79 for 2021, $52.29 for 2022, $51.70 for 2023, $51.59 for 2024, $51.76 for 2025, $52.07 for 2026, and escalated 3% thereafter and $2.87/MMBtu for natural gas for 2018, $2.81 for 2019, $2.81 for 2020, $2.82 for 2021, $2.85 for 2022, $2.89 for 2023, $2.93 for 2024, $2.97 for 2025, $3.01 for 2026 and escalated 3% thereafter. NGL pricing used in determining our NYMEX reserves were approximately 30% of future crude oil price 10
Geo‐Engineered Completions Continue to Improve Results Technical Process Application Experience • Vertical Pilot Logs Used To Select Geo‐target to Optimize Both Reservoir & Mechanical Properties Horned Frog (2015,2018) . Reservoir Properties ‐ Porosity, Total Organic Content, Clay Volume Beall Ranch (2015, 2016) . Mechanical Properties ‐ Young’s Modulus, Poisson’s Ratio, Minimum In‐situ Stress Cyclone (2016, 2017,2018) Results of Analysis Determine Geosteering Target Burns Ranch (2016, 2017) • Azimuthal Gamma Ray LWD Tool to Assist in Geosteering . Multi‐planar Gamma ray data determines dip angle and direction in real time Beall Ranch (2015, 2016) • Lateral “Thru‐Bit” Logs Run to TD for Detailed Rock Properties Analysis Cyclone/Hawkeye (2016, 2017,2018) . Triple Combo Log with Spectral Gamma Ray and Dipole Sonic Logs Burns Ranch (2016, 2017) Horned Frog (2018) • Mangrove Stimulation Design . Utilize Thru‐Bit Log Data For Reservoir Characterization Horned Frog (2015, 2018) . Models Key Mechanical Properties To Optimize Stimulation Beall Ranch (2015, 2016) . Vertical and lateral rock heterogeneity Cyclone/Hawkeye (2016, 2017, 2018) . Planar and Non‐planar fractures Burns Ranch (2016, 2017) . Account for multi‐well stress shadows to optimize zipper fracs Facilitates Design of Engineered (Non‐Geometric) Completion, Usually Yielding 150’ Stages • Increased Use of Diverters, Both Near‐Field and Far‐Field Beall Ranch (2016) . Engineered fibrous pill designed to create near‐wellbore isolation to augment frac efficacy across all Cyclone/Hawkeye (2016, 2017, 2018) perforations, maximizing wellbore coverage Burns Ranch (2016, 2017) . Increase efficiency through fewer pumped stages, coiled tubing plug drill outs Horned Frog (2015, 2018) • Employ Extended Reach Laterals to Drive Efficiencies and Returns Beall Ranch (2016) . Acquire Leasehold in Geometries That Allow For 8,000’ to 13,000’ laterals . Say something about hole straightness / drill‐outs, etc. Cyclone/Hawkeye (2016, 2017, 2018) . LONE has drilled 20 wells over 8,000’ Burns Ranch (2017) • Engineered Flowback Beall Ranch (2016. 2017) . Lonestar has increasingly applied controlled flowbacks Cyclone (2016, 2017, 2018) . Implement solids and fluids analysis to avoid negative impact of hydraulic fractures and assess success of Burns Ranch (2017) completion strategies Wildcat (2017) 11
The Value of Extended Reach Laterals in the Eagle Ford Surface & Facilities Drilling Pad Wellhead Equipment Separation Storage Compression $0.4 MM Gathering $0.4 MM Cumulative Cost Lateral 5,000’ + 5,000’ 10,000’ Vertical + Angle Completed Well Cost ($MM) $4.9 MM $2.3 MM $7.2 MM Drilling Gross Reserves (BOE) 281,000 354,000 632,000 Completion $1.7 MM Casing Net Reserves (BOE) 227,000 294,000 521,000 Tubing Cementing Cumulative Cost Finding & Onstream Cost ($/BOE) $21.59 $7.82 $13.82 $1.3 MM PV10 ($MM) $2.2 MM $5.0 MM $8.2 MM Internal Rate of Return2 32% 253% 80% Extended Reach 5,000’ Lateral Total +5,000’ Lateral Total Drilling Drilling Completion Completion Casing $4.9 MM Casing $7.2 MM Fracture Stimulation Fracture Stimulation Other Other $3.2 MM Cumulative Cost $2.3 MM Cumulative Cost Note: Prices based on $65 flat oil and $3.00 gas flat deck 1 Surface and faculties costs are allocated for 3 well pad (Source of reserve forecast for 10,000’ lateral‐ W.D. Von Gonten from our Cyclone area); 2IRR based on reserve forecast for 10,000’ lateral and average type curve from W.D. Von Gonten for our Cyclone area 12
2018 Capital Program Areas of Focus
Cyclone/Hawkeye – Locator Map Leasehold Summary Type Gross Net Acreage 12,102 7,237 HBP 9,660 5,141 Developed 2,957 2,619 Undeveloped 9,145 4,617 Producing Wells 16 12 PUD Locations 22 13 PROB Locations 21 15 NYMEX Strip PV‐10 ($MM) Total Locations 50 35 $137.5 Legend PDP PUD PROB $647.6 *Offset operator EUR’s are Lonestar internal estimates 14
Cyclone / Hawkeye Results Lonestar Wells vs. Other Operators’ Direct Offsets 150 Highlights 125 . Lonestar’s Cyclone / Hawkeye wells 100 are outperforming all offset wells except one (deeper) 75 . Each set of wells has progressively outperformed our prior well set 50 Cumulative Production (MBbls) 25 0 Months 180 ‐ Day Average Oil Production 700 70 Third Party Forecast 65 600 62 Highlights 60 500 (Bopd) 55 (Bopd/1,000') 400 51 . Hawkeye wells are 29% better than 49 50 300 46 average Cyclone well, per foot Production 45 Production 1P PV‐10 ($mm) Day 200 . Hawkeye wells are 24% better than ‐ 40 Day 180 $40 $350 $30 $250 $20 ‐ $150 $10 $50 $0 100 Dec‐10Dec‐11Dec‐12oday T 35 our best Cyclone well, per foot 180 0 BarnetEFSAMUt 30 . Outperforming Third Party projections by 23% 15
Cyclone/Hawkeye‐ Economic Summary Economic Summary1 W.D. Von Gonten & Co. Type Curve Well Statistics 900 Vertical Depth 8,500' • Hawkeye Wells are outperforming Type Perforated Interval 10,000' 800 Curve by 23% though 6 months 30‐day IP Rate • 50 drilling locations (44% PUD) Crude Oil (bopd) 794 700 • Pursuing additional leasehold opportunities NGL's (blpd) 53 Natural Gas (Mcfgpd) 253 600 (Bopd) Equivalent (Boepd) 889 500 Technical EUR / ft Crude Oil (bbls) 57 400 NGL's (bbls) 4 Natural Gas (Mcf) 18 300 Production Equivalent (Boe) 64 Oil 200 Economic Reserves Crude Oil (bbls) 565,400 100 NGL's (bbls) 37,475 Natural Gas (Mcf) 179,905 0 Equivalent (Boe) 632,859 123456789101112131415161718192021222324 Economic Factors Months Cap. Exp. ($MM) $7.2 PV‐10 ($MM) $8.2 WDVG Actual Production IRR (%) 80% 1 All reserves and economic data sourced from Lonestar’s 12/31/17 reserve report, independently engineered by WD Von Gonten &Co. Assumes $65 flat oil price and $3.00 flat gas deck 16
Karnes County – Locator Map Leasehold Summary Type Gross Net Acreage 4,991 3,886 HBP 4,259 3,274 Developed 2,773 2,107 Undeveloped 2,218 1,779 Producing Wells 12 9 PUD Locations 35 28 Legend NYMEX Strip PV‐10 ($MM) PDP PUD $104.3 PROB $647.6 17 1Acreage as of 8/1e
Karnes County Economic Evaluation Economic Summary1 W.D. Von Gonten & Co. Type Curve Well Statistics Vertical Depth 8,500' 1,000 Perforated Interval 5,600' 900 • Max‐30 rates‐ ~950 Boe/d • Extending locations by 13% with off‐lease pads 30‐day IP Rate 800 Crude Oil (bopd) 688 • Outperforming Type Curve NGL's (blpd) 46 700 • 35 drilling locations (100% PUD) Natural Gas (Mcfgpd) 292 Equivalent (Boepd) 782 600 (Boepd) 500 Technical EUR / ft Crude Oil (bbls) 70 400 NGL's (bbls) 5 Natural Gas (Mcf) 30 300 Equivalent (Boe) 80 200 Economic Reserves Production 100 Crude Oil (bbls) 384,865 NGL's (bbls) 26,997 0 Natural Gas (Mcf) 170,983 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Equivalent (Boe) 440,359 Stream 3 Months of Production Economic Factors Cap. Exp. ($MM) $5.2 PV‐10 ($MM) $5.7 IRR (%) 94% WDVG Actual Production 1 All reserves and economic data sourced from Lonestar’s 12/31/17 reserve report, independently engineered by WD Von Gonten &Co. Assumes $65 flat oil price and $3.00 flat gas deck 18
Horned Frog – Locator Map NW Frog Horned Leasehold Summary1 Type Gross Net Acreage 6.809 6,048 HBP 6,432 5,326 Developed 689 572 Undeveloped 6,120 5,478 Producing Wells 6 6 PUD Locations 11 11 PROB/Other Locations 16 16 NYMEX Strip PV‐10 ($MM) Total Locations 27 27 $38.3 Legend PDP PUD PROB $647.6 19 1Acreage as of 8/1e *Offset operator EUR’s are Lonestar internal estimates
Horned Frog Economic Evaluation Economic Summary1 W.D. Von Gonten & Co. Type Curve Well Statistics Vertical Depth 9,100' 2,500 Perforated Interval 10,000' • Max 30 Rates >2,200 Boe/d 30‐day IP Rate • Recent Laterals ranging from 10,000’ to 12,000’ Crude Oil (bopd) 440 2,000 • Oil rates on new wells 75% higher NGL's (blpd) 473 • 27 drilling locations (40% PUD) Natural Gas (Mcfgpd) 4,753 (Boepd) Equivalent (Boepd) 1,705 1,500 Technical EUR / ft Crude Oil (bbls) 22 Production 1,000 NGL's (bbls) 35 Natural Gas (Mcf) 356 Equivalent (Boe) 116 Stream ‐ 500 Economic Reserves 3 Crude Oil (bbls) 204,759 NGL's (bbls) 336,693 0 Natural Gas (Mcf) 3,381,555 123456789101112131415161718192021222324 Equivalent (Boe) 1,105,044 Economic Factors Months Cap. Exp. ($MM) $7.9 WDVG Actual Production PV‐10 ($MM) $4.4 IRR (%) 46% 1 All reserves and economic data sourced from Lonestar’s 12/31/17 reserve report, independently engineered by WD Von Gonten &Co. Assumes $65 flat oil price and $3.00 flat gas deck 20
Horned Frog Results Lonestar Wells vs. Other Operators’ Direct Offsets Highlights 2,000 . Max‐30 IP’s for Lonestar’s new wells at Horned Frog averaged 2,155 Boe/d 1,750 G1H H1H . 11,362’ avg. lateral length (#/ft) . 1,650 #/ft proppant (with diverters) 1,500 . 120‐Day IP’s for Lonestar’s new wells at Horned Frog 1,250 averaged 1,930 Boe/d Concenration . Lonestar’s new wells at Horned Frog outperformed 1,000 both its own prior wells, and all “modern” completions drilled in 2017 by other operators 750 Proppant . LONE is currently fracking the Horned Frog NW #2H & #3H 500 . Petrophysics have generated an oiler target 050100150200 . 7,700’ avg. lateral length 120‐Day Production (BOEPD / 1,000' Lateral) . 2,000 #/ft proppant (with diverters)‐ up 20% . Lonestar has 27 drilling locations in Horned Frog Area, Vintage Completions Modern Completions LONE Wells with very little Proved Reserves at 12/31/17 . 9 Proved Undeveloped . 11 Probable Undeveloped . 7 Unbooked locations at 12/31/17 21
Horned Frog Economic Evaluation Economic Summary1 Horned Frog NW 2H & 3H vs. Type Curve Well Statistics Vertical Depth 8,765' 1,100 Perforated Interval 7,410' 1,000 30‐day IP Rate 900 Crude Oil (bopd) 562 NGL's (blpd) 179 800 Natural Gas (Mcfgpd) 2,039 (Boepd) Equivalent (Boepd) 1,080 700 600 Technical EUR / ft Crude Oil (bbls) 35 500 Production NGL's (bbls) 31 400 Natural Gas (Mcf) 355 Equivalent (Boe) 125 300 Stream ‐ 3 200 Economic Reserves Crude Oil (bbls) 249,177 100 NGL's (bbls) 221,619 0 Natural Gas (Mcf) 2,525,188 123456789101112131415161718192021222324 Equivalent (Boe) 891,660 Months Economic Factors Cap. Exp. ($MM) $7.0 LONE Curve Actual Production PV‐10 ($MM) $3.9 IRR (%) 39% 1 All reserves and economic data sourced from Lonestar’s 12/31/17 reserve report, independently engineered by WD Von Gonten &Co. Assumes $65 flat oil price and $3.00 flat gas deck 22
Executive Summary . Pure Play Eagle Ford Operator… Net Eagle Ford Leasehold • +60,000 Net Acres in the Crude Oil Window of the Eagle Ford Shale • Unfettered access to oil and gas transportation infrastructure 70,000 • 100% LLS‐Based Oil Sales‐ Current Oil Price = Premium to WTI 60,000 • Technical leader in the Eagle Ford, drilling extended reach laterals with proprietary 50,000 targeting and completion techniques, yielding differential results 40,000 . …With Proven Operational Excellence Acres • Increased Proved Reserves 82% YOY to 73.6 MMBoe in 2017 30,000 • Strip PV‐10 increased 70% YOY to $647.6 MM1 20,000 • 2 Proved PV‐10 Per Share‐ $10.98 per share 10,000 . Quality Drilling Inventory Built at Low Costs 0 • 254 drilling locations 1 2012 2013 2014 2015 2016 2017 • Oil‐intensive drilling inventory‐ reserves are 86% crude oil & NGL’s • 5‐year All‐Sources Finding & Onstream Costs of $8.94 per Boe Proved Reserves . 2018 Is A Breakout Year For Lonestar… 80 • Rigs under contract to drill 2018 Program along with a dedicated Frac Spread 70 • 2Q18 production increased 43% sequentially 60 • FY18 Production Guidance recently increased to 10,600 – 11,200 Boe/d (+68% vs. 2017) 3 50 3 (MMBOE) • FY18 EBITDAX Guidance recently increased to $115 ‐ $130 MM (+89% vs. 2017) 40 • Growth can be achieved while improving leverage metrics‐ from 3.4x in 1Q18 to the low‐2’s by year‐end 2018 30 Reserves 20 . …And 2019 Is Setting Up For Another Year Of Growth 10 • Rigs under contract to drill 2018 Program along with a dedicated Frac Spread Proved 0 3 • 2019 Production Outlook of 13,000 – 14,000 Boe/d, and increase of 27% 2012 2013 2014 2015 2016 2017 • 2019 Adjusted EBITDAX Outlook of $140 to $160 million, an increase of 23% 3 1 Based on YE17 Reserve Report 2 Net of debt and preferred obligations, at NYMEX Strip at 12/31/18 3 At mid‐point of guidance 23