Lonestar Resources US, Inc. B. Riley Conference May 23, 2018 Exhibit 99.1
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.
Company Profile Share Price YTD Ticker (NASDAQ:NMS) LONE Share Price2 $7.12 Shares Out (Fully Diluted) 3 38.8 MM Market Cap $276 MM Cash3 $2 MM Long Term Debt3 $325 MM Enterprise Value $599 MM Enterprise Value 1 Based on YE17 Reserve Report 2May 16, 2018 3 At March 31, 2018 Pure Play Eagle Ford Player With Proven Operational Excellence +58,000 Net Acres in the Crude Oil Window of the Eagle Ford Shale Increased Proved Reserves 82% YOY to 73.6 MMBoe in 2017 Strip PV-10 increased 70% YOY to $647.6 MM Quality Drilling Inventory Built at Low Costs 254 drilling locations1 2017 Reserve replacement ratio of 1,499% at F&D costs at $6.07/Boe, Rigs under contract to drill 2018 Program along with a dedicated Frac Spread Oily Inventory- Reserves are 86% Crude Oil & NGLs Driving Value for Shareholders Proved PV-10 per share increased 33% y-o-y to $10.98 per share EBITDAX / Boe of $38.55, making LONE one of most profitable in our peer group Reduced Debt / EBITDAX from 5.4x to 3.4x in last 4 quarters 2Q18 Should be reduced to 3.0x, and into the 2’s in the second half of 2018 Lonestar Positioned For More Growth FY18 Production Guidance increased to 10,300 – 11,000 Boe/d (+65% vs. 2017) FY18 EBITDAX Guidance increased to $110 - $125 MM (+65% vs. 2017) Growth expected to be achieved while reducing leverage metrics and increasing borrowing base and liquidity Lonestar will continue to seek asset growth through focused, disciplined acquisition strategy $7.12
Experienced Management Team John H. Pinkerton Chairman of the Board 37 years experience in the oil and gas industry Founder, Chairman and Chief Executive Officer Range Resources Built Range Resources into a $10 billion Exploration & Production company Executive Previous Experience Biography Tom H. Olle VP – Reservoir Engineering Over 37 years oil and gas industry experience Senior level expertise in reservoir management / project development across a broad array of 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 Gerrity Oil & Gas Frank D. Bracken, III Chief Executive Officer 32 years experience in oil and gas finance Previously Managing Director at Jefferies LLC, where he led >$5 billion in oil and gas transactions Former CFO / Director of Gerrity Oil & Gas Corp, a NYSE-listed E&P Company GOG Jana Payne VP – Geosciences 33 years in all aspects of oil and gas exploration and development Geologic Manager for Petrohawk, responsible for discovery of Hawkville Field, first commercial Eagle Ford Shale well in 2008 Senior Exploitation Manager for Halcon Resources Experience in Eagle Ford, Haynesville, Bossier, Utica and Tuscaloosa Marine Shales Barry D. Schneider Chief Operating Officer 33 years oil and gas industry experience Senior level expertise in management of regional business units at large independent oil & gas companies Previously with US public companies Denbury Resources and Conoco-Phillips
Company Profile 1 12/31/2017Reserves based on NYMEX Strip as of 1/2/2018 * Please see the reserves disclosures at the end of this presentation Production Proved Reserves1 PV-10 Value1 Eastern Central Western Engineered Acreage* Non-Engineered Acreage* Acquired Acreage 6,495Boe/d 76.2 MMBoe $382 MM $648MM 44.9 MMBoe 5,495 Boe/d 18% 70% 70% 2016 2017 2016 2017 2016 2017
2017 Capital Results vs. Peers Reserve Replacement as a % of 2017 Production Finding & Onstream Costs ($/Boe) Note: Figures above calculated from data publically disclosed from the peer companies 2017 Reserve Replacement Ratio All Sources Finding & Onstream Costs
Crude Oil Weighted Production Yields High Margins 1Q18 LOE / Boe Cost and % Liquids 1Q18 EBITDAX Margin 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
Rapidly Improving Financial Metrics Average Daily Production vs. Annualized Adjusted EBITDAX Debt / Adjusted EBITDAX
Strip PV-10 Per Share +70% +33% Strip PV-10 1 Strip PV-101 Less Net Debt (Per Share)
Geo-Engineered Completions Continue to Improve Results Vertical Pilot Logs Used To Select Geo-target to Optimize Both Reservoir & Mechanical Properties Reservoir Properties - Porosity, Total Organic Content, Clay Volume Mechanical Properties - Young’s Modulus, Poisson’s Ratio, Minimum In-situ Stress Results of Analysis Determine Geosteering Target Technical Process Application Experience Horned Frog (2015,2018) Beall Ranch (2015, 2016) Cyclone (2016, 2017,2018) Burns Ranch (2016, 2017) Beall Ranch (2015, 2016) Cyclone/Hawkeye (2016, 2017,2018) Burns Ranch (2016, 2017) Horned Frog (2018) Beall Ranch (2016. 2017) Cyclone (2016, 2017, 2018) Burns Ranch (2017) Wildcat (2017) Azimuthal Gamma Ray LWD Tool to Assist in Geosteering Multi-planar Gamma ray data determines dip angle and direction in real time Lateral “Thru-Bit” Logs Run to TD for Detailed Rock Properties Analysis Triple Combo Log with Spectral Gamma Ray and Dipole Sonic Logs Mangrove Stimulation Design Utilize Thru-Bit Log Data For Reservoir Characterization Models Key Mechanical Properties To Optimize Stimulation Vertical and lateral rock heterogeneity Planar and Non-planar fractures 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 Engineered fibrous pill designed to create near-wellbore isolation to augment frac efficacy across all perforations, maximizing wellbore coverage Increase efficiency through fewer pumped stages, coiled tubing plug drill outs Engineered Flowback Lonestar has increasingly applied controlled flowbacks Implement solids and fluids analysis to avoid negative impact of hydraulic fractures and assess success of completion strategies Horned Frog (2015, 2018) Beall Ranch (2015, 2016) Cyclone/Hawkeye (2016, 2017, 2018) Burns Ranch (2016, 2017) Beall Ranch (2016) Cyclone/Hawkeye (2016, 2017, 2018) Burns Ranch (2016, 2017) Employ Extended Reach Laterals to Drive Efficiencies and Returns Acquire Leasehold in Geometries That Allow For 8,000’ to 13,000’ laterals Say something about hole straightness / drill-outs, etc. LONE has drilled 20 wells over 8,000’ Horned Frog (2015, 2018) Beall Ranch (2016) Cyclone/Hawkeye (2016, 2017, 2018) Burns Ranch (2017)
The Value of Extended Reach Laterals in the Eagle Ford Vertical + Angle Drilling Completion Casing Tubing Cementing $1.3 MM Surface & Facilities Drilling Pad Wellhead Equipment Separation Storage Compression Gathering $0.4 MM 5,000’ Lateral Drilling Completion Casing Fracture Stimulation Other $3.2 MM $0.4 MM $1.7 MM $4.9 MM +5,000’ Lateral Drilling Completion Casing Fracture Stimulation Other $2.3 MM $7.2 MM Total Total Extended Reach Cumulative Cost Cumulative Cost Cumulative Cost Cumulative Cost Note: Prices based on $65 flat oil and $3.00 gas flat deck 1 Surface and faculties costs are allocated for 3 well pad (Source of reserve forecast for 10,000’ lateral- W.D. Von Gonten from our Cyclone area); 2IRR based on reserve forecast for 10,000’ lateral and average type curve from W.D. Von Gonten for our Cyclone area Lateral 5,000’ + 5,000’ 10,000’ Completed Well Cost ($MM) $4.9 MM $2.3 MM $7.2 MM Gross Reserves (BOE) 281,000 354,000 632,000 Net Reserves (BOE) 227,000 294,000 521,000 Finding & Onstream Cost ($/BOE) $21.59 $7.82 $13.82 PV10 ($MM) $2.2 MM $5.0 MM $8.2 MM Internal Rate of Return2 32% 253% 80%
2018 Capital Program Areas of Focus
Cyclone/Hawkeye – Locator Map Cyclone #10H Cyclone #9H Cyclone #5H Cyclone #4H Cyclone #27H Cyclone #26H Harvey Johnson #1H-#6H Hawkeye #1H & #2H Type Gross Net Acreage 9,443 7,808 HBP 7,718 6,450 Developed 1,910 1,579 Undeveloped 7,533 6,229 Producing Wells 16 12 Drilling Locations 43 28 *Offset operator EUR’s are Lonestar internal estimates Leasehold Summary Legend PDP # – Oil EUR/1000’ # – Gas EUR/1000’ # – BOE EUR/1000’ # – proppant/ft PUD PROB
Cyclone/Hawkeye- Economic Summary W.D. Von Gonten & Co. Type Curve Economic Summary 1 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 Hawkeye Wells are outperforming Type Curve by 16% though 3 months 43 drilling locations (33% PUD) Pursuing additional leasehold opportunities
Cyclone / Hawkeye Results Lonestar Wells vs. Other Operators’ Direct Offsets 90-Day Average Oil Production Lonestar’s Cyclone / Hawkeye wells are outperforming all offset wells except one (deeper) Each set of wells has progressively outperformed our prior well set Highlights Hawkeye wells are 28% better than average Cyclone well, per foot Hawkeye wells are 19% better than our best Cyclone well, per foot Outperforming Third Party projections by 16% Highlights Third Party Forecast Cyclone #9H #10H Cyclone #4H #5H Hawkeye #1H & #2H Cyclone #26H #27H
Karnes County – Locator Map 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 Drilling Locations 35 28 *Offset operator EUR’s are Lonestar internal estimates Leasehold Summary Legend PDP # – Oil EUR/1000’ # – Gas EUR/1000’ # – BOE EUR/1000’ # – proppant/ft PUD PROB Georg #18,19H,20H
Karnes County Economic Evaluation W.D. Von Gonten & Co. Type Curve Economic Summary1 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 IP rates >1,250 Boe/d Extending locations by 13% with off-lease pads Outperforming Type Curve 35 drilling locations (100% PUD)
Horned Frog – Locator Map 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 Drilling Locations 27 27 *Offset operator EUR’s are Lonestar internal estimates Leasehold Summary Legend PDP # – Oil EUR/1000’ # – Gas EUR/1000’ # – BOE EUR/1000’ # – proppant/ft PUD PROB Horned Frog G#1H & H#1H
Horned Frog Economic Evaluation W.D. Von Gonten & Co. Type Curve Economic Summary1 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 Max 30 Rates >2,200 Boe/d Recent Laterals ranging from 10,000’ to 12,000’ Oil rates on new wells 75% higher 27 drilling locations (33% PUD)
Horned Frog Results Lonestar Wells vs. Other Operators’ Direct Offsets LONE Wells Modern Completions Vintage Completions B1H A1H H1H G1H Max-30 IP’s for Lonestar’s new wells at Horned Frog averaged 2,155 Boe/d 11,362’ avg. lateral length 1,650 #/ft proppant (with diverters) Lonestar’s new wells at Horned Frog outperformed both its own prior wells, and all “modern” completions drilled in 2017 by other operators LONE is currently fracking the Horned Frog NW #2H & #3H Petrophysics have generated an oiler target 7,700’ avg. lateral length 2,000 #/ft proppant (with diverters)- up 20% Lonestar has 27 drilling locations in Horned Frog Area, with very little Proved Reserves at 12/31/17 9 Proved Undeveloped 11 Probable Undeveloped 7 Unbooked locations at 12/31/17 Highlights
Executive Summary Net Eagle Ford Leasehold Key Investor Considerations Proved Reserves 2017 Was A Year Of High Growth For Lonestar 82% increase in Proved Reserves 225% Increase in Proved PV-10- $648 MM 1 1,500% Reserve Replacement “All Sources” Finding & Onstream Costs of $6.07 per BOE Financial Improvement is Significant And Accelerating Refinanced 8 ¾% Notes due April 2019. No Unsecured Maturities until 2023 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 Lonestar expects significant increase in Borrowing Base in May 2018 New Drills Are Performing Well... Hawkeye (Gonzales County)- outperforming 3rd Party projections by 16% 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) …And Net Production Is Ramping Quickly, Increased 2Q18 Guidance… April 2018 Production- exceeded 10,000 Boe/d 2Q18 Production Guidance- 10,000 to 10,500 Boe/d 2Q18 EBITDAX Guidance- $27.0 MM to $29.0 MM …And Increased Full-Year 2018 Guidance… 2018 Production Guidance- 10,300 - 11,000 Boe/d (up 65%) 2018 EBITDAX Guidance- $110 - $125 MM (up 65%) …With Energy Services Locked Up To Execute Rigs Under Contract to Drill 2018 Capital Program, with optionality to expand Dedicated Frac Spread Up and Running 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%
