Lonestar Resources US, Inc. J.P. Morgan Energy Conference June 18, 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 • +58,000 Net Acres in the Crude Oil Window of the Eagle Ford Shale $12.00 300 • Unfettered access to oil and gas transportation infrastructure $11.00 • 100% LLS-Based Oil Sales- Current Oil Price = WTI + $4.50/bbl 1 $10.00 $8.35 250 • Technical leader in the Eagle Ford, drilling extended reach laterals with proprietary $9.00 $8.00 200 targeting and completion techniques, yielding differential results $7.00 $6.00 150 § …With Proven Operational Excellence $5.00 • Increased Proved Reserves 82% YOY to 73.6 MMBoe in 2017 $4.00 100 Share Share Price (US$) • Strip PV-10 increased 70% YOY to $647.6 MM2 $3.00 Volume ('000 Shares) • Proved PV-10 Per Share- $10.98 per share5 $2.00 50 $1.00 § Quality Drilling Inventory Built at Low Costs $0.00 0 • 254 drilling locations 1 Volume 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 • $250 MM Senior Unsecured Notes push maturities into 2023 Ticker (NASDAQ:NMS) LONE • Borrowing Base recently increased from $160 MM to $190 MM Share Price3 $8.35 • Liquidity enhanced to $117 MM Shares Out (Fully Diluted) 3 38.8 MM § 2018 Is A Breakout Year For Lonestar • Rigs under contract to drill 2018 Program along with a dedicated Frac Spread Market Cap $326 MM • 2Q18 production expected to rise 33% sequentially 6 Cash3 $2 MM • FY18 Production Guidance recently increased to 10,300 – 11,000 Boe/d (+65% vs. 2017) • FY18 EBITDAX Guidance recently increased to $110 - $125 MM (+65% vs. 2017) Long Term Debt3 $325 MM • Growth can be achieved while improving leverage metrics- from 3.4x in 1Q18 to the Enterprise Value $647MM low-2’s by year-end 2018 1 Assumes $7.50 LLS Differential 2 Based on YE17 Reserve Report 3 June 14, 2018 4 At March 31, 2018 5 Net of debt and preferred obligations, at NYMEX Strip at 12/31/18 6 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 WTI +$4.50/bbl1 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 Guidance- up 33% sequentially3 Growth •2018 Guidance- up 65%, year-over-year3 $400 Rapid Cash Flow$350 Per 3 $300 •Anticipate 100% Increase in 2018 Fully Diluted CFPS to $2.19 Share Growth$250 $200 10 ($mm)10 - $150 $100 1P PV 1P Improving Leverage$50 •Debt/EBITDAX reduced from 5.4x to 3.4x in last 4 quarters $0 Dec-10 Dec-11 Dec-12 Today Ratios Barnett EFS AMU •Debt/EBITDAX projected to fall to 3.0x in 2Q18, @2.2x at YE18 1 Assumes $7.50 LLS Differential 2 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 6,495 Boe/d Eastern 18% 5,495 Boe/d Oil 67% Oil 55% NGL's 16% NGL's 21% Gas Gas 17% 24% Central 2016 2017 Proved Reserves1 Western 76.2 MMBoe 70% 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 $648MM Net Engineered Avg. Developed PUD Proved Developed Total Proved 70% Region Acres Locations WI HBP (MMBOE) (MMBOE) (MMBOE) ($MM) ($MM) $382 MM Western 14,904 51 90% 96% 8.6 21.6 30.1 $100.6 $224.4 Central 33,064 173 70% 95% 10.3 31.7 41.9 $180.4 $392.0 Central 61% Eastern 10,293 30 72% 61% 0.8 3.4 4.2 $13.3 $31.2 Western 35% Western 68% Central 23% Total 58,262 254 75% 89% 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% 1499% 1,500% 1,000% 601% 500% 0% Reserve Replacement as a % of 2017 Production WRD LONE SRCI HK PVAC HPR SBOW FANG PDCE MTDR XOG LPI CXO CLR OAS DNR EPE Peer Average All Sources Finding & Onstream Costs $30.00 $25.00 $400 $350 $300 $20.00 $250 $16.41$200 10 ($mm)10 $15.00 - $150 $100 1P PV 1P $50 $10.00 $0 Dec-10 Dec-11 Dec-12 Today $6.07 Barnett EFS AMU $5.00 Finding & Onstream Costs ($/Boe) $0.00 SBOW WRD PDCE HPR LONE SRCI LPI PVAC MTDR CLR DNR CXO OAS HK XOG FANG EPE Peer Average 7 Note: Figures above calculated from data publically disclosed from the peer companies
Crude Oil Weighted Production Yields High Margins 1Q18 LOE / Boe Cost and % Liquids 1Q18 EBITDAX Margin $/BOE % Liquids $/BOE 97% % Liquids $10.00 100% $45.00 100% 89% 97% 86% 88% 88% 89% 85% 90% 86% 85% $40.00 90% 76% 78% 76% 78% $8.00 74% 80% 74% 80% 70% 72% $35.00 72% 69% 69% 69% 70% 69% 63% 63% 70% 63% 63% 70% $30.00 58% 57% 57% 58% $6.00 60% 60% $25.00 (per BOE) 50% 50% 1Q18 EBITDAX $20.00 $4.00 40% 40% $15.00 30% 30% WRD 18% 18% FANG $2.00 20% $10.00 20% PVAC 10% $5.00 10% LONE $21.80 $6.48 $6.36 $6.33 $5.92 $5.48 $5.44 $5.02 $4.04 $3.85 $3.60 $3.48 $3.34 $3.33 $3.27 $2.04 $1.93 $40.40 $40.00 $38.00 $29.82 $28.83 $24.26 $28.78 $27.60 $39.03 $25.56 $23.58 $38.55 $26.33 $33.87 $32.25 $33.25 $0.00 0% $0.00 $14.67 0% MTDR HK LPI EPE CLR HPR CXO OAS DNR XOG SRCI HK LPI WRD PDCE PVAC LONE EPE FANG CLR HPR MTDR CXO OAS SBOW DNR XOG SRCI WRD PDCE PVAC LONE FANG MTDR SBOW Source: Company Press Releases for three months ended March 31, 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 EBITDAX Debt / Adjusted EBITDAX $150 12,000 6.0x $125 10,000 5.5x 5.0x $100 8,000 4.5x $75 6,000 4.0x 3.5x $50 4,000 3.0x Daily Production (Boepd) $25 2,000 LQA Debt Adjsuted / EBITDAX Annualizeed EBITDAX Annualizeed($MM) EBITDAX 2.5x $400 $0 $350 0 2.0x $300 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 $250 Est. $200 Est. 10 ($mm)10 EBITDAX excl. Hedging - $150 Hedging Revenue $100 Hedging Expense PV 1P Production $50 $0 Dec-10 Dec-11 Dec-12 Today Barnett EFS AMU 9
Strip PV-10 Per Share Strip PV-10 1 Strip PV-101 Less Net Debt (Per Share) $700 $700 $647.6 $10.98 $600 $600 $500 +70% $500 +33% $8.27 $400 $382.0 $400 Net PV-10 Preferred $300 PV-10 $300 Net Debt $200 $400 $200 $350 $100 $300 $100 $250 $0 $200 $0 10 ($mm)10 - $150 2016 2017 2016 2017 $100 1P PV 1P $50 $0 Dec-10 Dec-11 Dec-12 Today Barnett EFS AMU 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 Ø Results of Analysis Determine Geosteering Target Cyclone (2016, 2017,2018) 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 § Account for multi-well stress shadows to optimize zipper fracs Burns Ranch (2016, 2017) Ø 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 $3.00 gas flat deck 1 Surface and faculties costs are allocated for 3 well pad (Source of reserve forecast for 10,000’ lateral- W.D. Von Gonten from our Cyclone area); 2 IRR based on reserve forecast for 10,000’ lateral and average type curve from W.D. Von Gonten for our Cyclone area 12
2018 Capital Program Areas of Focus
Cyclone/Hawkeye – Locator Map Harvey Johnson #1H -#6H Hawkeye #1H & #2H Leasehold Summary Type Gross Net Cyclone #27H Cyclone #26H Acreage 9,443 7,808 HBP 7,718 6,450 Developed 1,910 1,579 Undeveloped 7,533 6,229 Producing Wells 16 12 PUD Locations 22 13 Cyclone #10H Cyclone #9H PROB Locations 21 15 Cyclone #5H NYMEX Strip PV-10 ($MM) Total Locations 43 28 Cyclone #4H $137.5 Legend PDP PUD PROB # – Oil EUR/1000’ # – Gas EUR/1000’ # – BOE EUR/1000’ $647.6 # – proppant/ft *Offset operator EUR’s are Lonestar internal estimates 14
Cyclone / Hawkeye Results Lonestar Wells vs. Other Operators’ Direct Offsets 150 Highlights 125 Cyclone #9H #10H Cyclone #4H #5H § Lonestar’s Cyclone / Hawkeye wells 100 are outperforming all offset wells Cyclone #26H #27H except one (deeper) 75 Hawkeye #1H & #2H § Each set of wells has progressively outperformed our prior well set 50 Cumulative Production (MBbls) Production Cumulative 25 0 Months 120 - Day Average Oil Production 800 75 Third Party Forecast 70 700$400 66 Highlights 600$350 65 $300 60 500 § Hawkeye wells are 30% better than $250 54 $200 55 400 49 average Cyclone well, per foot 10 ($mm)10 49 - $150 50 300$100 49 1P PV 1P 45 § Hawkeye wells are 22% better than Day Production (Bopd) Production Day $50 - 200 40 $0 (Bopd/1,000') Production Day our best Cyclone well, per foot - 120 120 Dec-10 Dec-11 Dec-12 Today 100 35 Barnett EFS AMU 120 § 0 30 Outperforming Third Party projections by 15% 15
Cyclone/Hawkeye- Economic Summary Economic Summary1 W.D. Von Gonten & Co. Type Curve Well Statistics Vertical Depth 8,500' 1,000 Perforated Interval 10,000' • Hawkeye Wells are outperforming Type 900 30-day IP Rate Curve by 15% though 4 months • 43 drilling locations (50% PUD) Crude Oil (bopd) 794 800 NGL's (blpd) 53 • Pursuing additional leasehold opportunities Natural Gas (Mcfgpd) 253 Equivalent (Boepd) 889 700 Technical EUR / ft 600 Crude Oil (bbls) 57 NGL's (bbls) 4 500 Natural Gas (Mcf) 18 Equivalent (Boe) 64 400 Economic Reserves 3 Stream Production (Boepd) Production Stream 3 Crude Oil (bbls) 565,400 300 NGL's (bbls) 37,475 Natural Gas (Mcf) 179,905 200 Equivalent (Boe) 632,859 Economic Factors 100 Cap. Exp. ($MM) $7.2 PV-10 ($MM) $8.2 0 IRR (%) 80% 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 Months of Production Von Gonten Curve 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 $3.00 flat gas deck 16
Karnes County – Locator Map Georg #18,19H,20H Leasehold Summary Type Gross Net Acreage 5,037 3,914 HBP 4,259 3,274 Developed 2,773 2,107 Undeveloped 2,264 1,807 Producing Wells 12 9 PUD Locations 35 28 Legend PDP NYMEX Strip PV-10 ($MM) PUD PROB $104.3 # – Oil EUR/1000’ # – Gas EUR/1000’ # – BOE EUR/1000’ # – proppant/ft $647.6 17 *Offset operator EUR’s are Lonestar internal estimates
Karnes County Economic Evaluation Economic Summary1 W.D. Von Gonten & Co. Type Curve Well Statistics Vertical Depth 8,500' 1,000 Perforated Interval 5,600' • Max-30 rates- ~950 Boe/d • Extending locations by 13% with off-lease pads 30-day IP Rate 900 • Outperforming Type Curve Crude Oil (bopd) 688 • 35 drilling locations (100% PUD) NGL's (blpd) 46 800 Natural Gas (Mcfgpd) 292 Equivalent (Boepd) 782 700 Technical EUR / ft Crude Oil (bbls) 70 600 NGL's (bbls) 5 Natural Gas (Mcf) 30 500 Equivalent (Boe) 80 Economic Reserves 400 Crude Oil (bbls) 384,865 (Boepd) Production Stream 3 NGL's (bbls) 26,997 300 Natural Gas (Mcf) 170,983 Equivalent (Boe) 440,359 200 Economic Factors Cap. Exp. ($MM) $5.2 100 PV-10 ($MM) $5.7 IRR (%) 94% 0 0 6 12 18 24 Months of 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 $3.00 flat gas deck 18
Horned Frog – Locator Map Leasehold Summary Type Gross Net Acreage 6.733 6,050 HBP 5,347 5,022 Developed 653 572 Undeveloped 6,120 5,478 Producing Wells 6 6 PUD Locations 11 11 PROB/Other Locations 16 16 Total Locations 27 27 NYMEX Strip PV-10 ($MM) Legend Horned Frog G#1H & H#1H $38.3 PDP PUD PROB # – Oil EUR/1000’ # – Gas EUR/1000’ # – BOE EUR/1000’ # – proppant/ft $647.6 19 *Offset operator EUR’s are Lonestar internal estimates
Horned Frog Economic Evaluation Economic Summary1 W.D. Von Gonten & Co. Type Curve Well Statistics 2,250 Vertical Depth 9,100' Perforated Interval 10,000' • Max 30 Rates >2,200 Boe/d 2,000 • 30-day IP Rate Recent Laterals ranging from 10,000’ to 12,000’ • Oil rates on new wells 75% higher Crude Oil (bopd) 440 NGL's (blpd) 473 1,750 • 27 drilling locations (40% PUD) Natural Gas (Mcfgpd) 4,753 Equivalent (Boepd) 1,705 1,500 Technical EUR / ft Crude Oil (bbls) 22 1,250 NGL's (bbls) 35 Natural Gas (Mcf) 356 Equivalent (Boe) 116 1,000 Economic Reserves 750 Crude Oil (bbls) 204,759 (Boepd) Production Stream 3 NGL's (bbls) 336,693 Natural Gas (Mcf) 3,381,555 500 Equivalent (Boe) 1,105,044 Economic Factors 250 Cap. Exp. ($MM) $7.9 PV-10 ($MM) $4.4 0 IRR (%) 46% 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 Months of Production Von Gonten Curve 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 20
Horned Frog Results Lonestar Wells vs. Other Operators’ Direct Offsets Highlights § Max-30 IP’s for Lonestar’s new wells at Horned Frog 1,750 G1H H1H averaged 2,155 Boe/d A1H B1H § 11,362’ avg. lateral length 1,500 § 1,650 #/ft proppant (with diverters) § 60-Day IP’s for Lonestar’s new wells at Horned Frog 1,250 averaged 1,956 Boe/d § 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 § LONE is currently fracking the Horned Frog NW #2H & #3H Proppant Proppant Concenration (#/ft) § Petrophysics have generated an oiler target 500 § 7,700’ avg. lateral length 0 50 $400 100 150 200 § 2,000 #/ft proppant (with diverters)- up 20% 60-Day$350 IP (BOEPD / 1,000' Lateral) $300 § Lonestar has 27 drilling locations in Horned Frog Area, $250 Vintage Completions$200 Modern Completions LONE Wells with very little Proved Reserves at 12/31/17 10 ($mm)10 - $150 § 9 Proved Undeveloped $100 1P PV 1P $50 § 11 Probable Undeveloped $0 Dec-10 Dec-11 Dec-12 Today § 7 Unbooked locations at 12/31/17 Barnett EFS AMU 21
Executive Summary § Pure Play Eagle Ford Operator… Net Eagle Ford Leasehold • +58,000 Net Acres in the Crude Oil Window of the Eagle Ford Shale • Unfettered access to oil and gas transportation infrastructure 70,000 1 • 100% LLS-Based Oil Sales- Current Oil Price = WTI + $4.50/bbl 60,000 • Technical leader in the Eagle Ford, drilling extended reach laterals with proprietary targeting and completion techniques, yielding differential results 50,000 40,000 § …With Proven Operational Excellence Acres • Increased Proved Reserves 82% YOY to 73.6 MMBoe in 2017 30,000 2 • Strip PV-10 increased 70% YOY to $647.6 MM 20,000 • Proved PV-10 Per Share- $10.98 per share5 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 § Balance Sheet Improvement Sets Up Rapid Growth 80 • $250 MM Senior Unsecured Notes push maturities into 2023 • Borrowing Base recently increased from $160 MM to $190 MM 70 • Liquidity enhanced to $117 MM 60 50 § 2018 Is A Breakout Year For Lonestar 40 • Rigs under contract to drill 2018 Program along with a dedicated Frac Spread 30 • 2Q18 production expected to rise 33% sequentially 6 • FY18 Production Guidance recently increased to 10,300 – 11,000 Boe/d (+65% vs. 2017) 20 • FY18 EBITDAX Guidance recently increased to $110 - $125 MM (+65% vs. 2017) 10 Proved Reserves (MMBOE) Reserves Proved • Growth can be achieved while improving leverage metrics- from 3.4x in 1Q18 to the 0 low-2’s by year-end 2018 2012 2013 2014 2015 2016 2017 1 Assumes $7.50 LLS Differential 2 Based on YE17 Reserve Report 3 June 12, 2018 4 At March 31, 2018 5 Net of debt and preferred obligations, at NYMEX Strip at 12/31/18 6 At mid-point of guidance 22
Executive Summary Key Investor Considerations Net Eagle Ford Leasehold § 2017 Was A Year Of High Growth For Lonestar 70,000 § 82% increase in Proved Reserves § 225% Increase in Proved PV-10- $648 MM 1 60,000 § 1,500% Reserve Replacement 50,000 § “All Sources” Finding & Onstream Costs of $6.07 per BOE 40,000 § Financial Improvement is Significant And Accelerating § Refinanced 8 ¾% Notes due April 2019. No Unsecured Maturities until 2023 Acres 30,000 § Extended Maturity on Senior Secured Facility from October, 2018 to June, 2020 § LQA Debt / EBITDAX has been reduced from 5.4x in 2Q17 to 3.4x in 1Q18 20,000 § Lonestar expects significant increase in Borrowing Base in May 10,000 § 2018 New Drills Are Performing Well... 0 § Hawkeye (Gonzales County)- outperforming 3rd Party projections by 16% 2012 2013 2014 2015 2016 2017 through 90 days. § Horned Frog (LaSalle County)- Max 30 day rates averaged 2,155 Boe/d § Georg (Karnes County)- early avg. rates >1,250 Boe/d (89% oil) Proved Reserves …And Net Production Is Ramping Quickly, Increased 2Q18 Guidance… 80 § April 2018 Production- exceeded 10,000 Boe/d § 2Q18 Production Guidance- 10,000 to 10,500 Boe/d 70 § 2Q18 EBITDAX Guidance- $27.0 MM to $29.0 MM 60 …And Increased Full-Year 2018 Guidance… 50 § 2018 Production Guidance- 10,300 - 11,000 Boe/d (up 65%) 40 § 2018 EBITDAX Guidance- $110 - $125 MM (up 65%) 30 …With Energy Services Locked Up To Execute § Rigs Under Contract to Drill 2018 Capital Program, with optionality to expand 20 § Dedicated Frac Spread Up and Running 10 Proved Reserves (MMBOE) Reserves Proved 0 2012 2013 2014 2015 2016 2017 1 Based on WD Von Gonten reserve report, prices based on NYMEX Strip at 1/2/2018 2 Excludes Karnes County locations, which have IRR’s of 71% 23