Lonestar Resources US, Inc. Investor Update Ex. 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 Registration Statement on Form 10, 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.
Meaningful balance sheet improvement over the last 12 months $ in MM September, 30 2016 March 31, 2017 September 30, 2017 Senior Secured Facility $94.5 $50.0 $128.8 12.0% Second Lien $38.0 $17.0 $0.0 8.75% Unsecured Notes $151.8 $151.8 $151.8 Total Debt $284.3 $218.8 $279.8 Net Debt / LTM EBITDAX 4.5x 3.9x 3.4x1 Since late 2015, we have focused on building scale while improving our balance sheet February 25, 2016: Lonestar announces a 30% increase in proved reserves to 40.2 MMBoe from year end 2014 proved reserves of 31.0 MMBoe March 10, 2016: Lonestar gains shareholder approval to re-domicile in the United States July 5, 2016: Lonestar commences a 1-for-2 reverse stock split, and the post-split shares began trading on the NASDAQ under the ticker “LONE” August 18, 2016: Lonestar begins open-market repurchases of its 8.75% Senior Unsecured Notes, which totaled $68.2 MM, funded by the issuance of the new $38.0 MM 12.00% Second Lien Notes October 5, 2016: Lonestar enters into an agreement to sell its remaining conventional assets for $14.0 MM, bringing total proceeds from its conventional asset divestiture process to $15.8 MM December 22, 2016: Lonestar closes sale of 13.8 MM shares of common stock, raising gross proceeds of $79.4 MM, which is applied to its Second Lien and Revolver balances June 15, 2017: Lonestar closes $116.6 MM acquisition of 21,238 net acres in the Eagle Ford Shale (the “Acquisitions”), funded with $80 MM Series A Convertible Preferred and $24 MM Senior Secured Credit Facility borrowings November 13, 2017: Lonestar reports third quarter results with $81.2MM annualized, run-rate EBITDAX (first results that fully reflect positive impact of the Acquisitions) Late 2015 Present 1 Net Debt/LTM EBITDAX conforms with RBL amendment. Represents 3Q17 EBITDAX of $20.3mm annualized This set of datapoints doesn’t make this look like a progression. Massive hedge revenues in 2016 (@$25 MM) skew the math. Ideas? TBD – Discussed with Chase
Transformative Results – Building Scale while Reducing Leverage NGLs 9% Note: 9/30/17 EBITDAX and leverage statistics reflect 3Q17 EBITDAX of $20.3mm annualized 1 Eagle Ford only (excludes conventional assets) Building Scale $3.09 Reducing Leverage Repurchased $68.8 MM in senior unsecured notes Sold 13.8 MM shares of common stock raising $79.4 MM in gross proceeds to repay revolver borrowings and second lien notes Sold $80.0 MM Series A convertible preferred equity Net Acres Proved Reserves (MMBoe) Total Debt Net Debt / EBITDAX (30%) 70% 67% (13%) MM MM Avg. Daily Prod.1 (Boe/d) LTM EBITDAX ($MM) 27% 28% MM MM
Company Profile - Current 1 Mid-year 2017 Reserves based on NYMEX Strip as of 11/6/2017 *Please see the reserves disclosures at the end of this presentation Production Pro forma Proved Reserves Pro forma PV-10 Value Eastern Central Western Engineered Acreage* Non-Engineered Acreage* Acquired Acreage 7,662 Boe/d 76.8 MMBoe $382 MM $596MM 44.9 MMBoe 5,266 Boe/d 46% 71% 56% Proved Reserves¹ PV-10¹ Region Net Acres Engineered Locations Avg. WI HBP PDP (MMBOE) PUD (MMBOE) Proved (MMBOE) PDP ($MM) Proved ($MM) Western 14,904 51 90% 96% 8.4 21.9 30.3 $91.4 $202.9 Central 31,975 163 77% 93% 8.9 32.5 41.4 $139.5 $356.8 Eastern 10,293 43 72% 61% 1.2 3.9 5.1 $19.3 $36.3 Total 57,172 257 79% 88% 18.5 58.3 76.8 $250.2 $595.9 12/31/2016 6/30/2017 Q1 2017 Q3 2017 12/31/2016 6/30/2017
Lonestar Has Scaled Its Eagle Ford Shale Business Margin Expansion Expense 2Q17 3Q17 Chg. 2Q17 3Q17 Chg. LOE $3.5 $4.5 +28% $6.87 $6.40 (7%) Taxes $1.1 $1.5 +43% $2.10 $2.19 +4% G&A $3.1 $2.3 (26%) $6.12 $3.26 (47%) Int. Exp. $6.0 $5.0 (16%) $11.65 $7.14 (39%) Total $13.7 $13.3 (3%) $26.74 $18.99 (29%) $ MM $ / Boe Field Margin $4.4 $13.4 +205% $8.63 $19.15 +122% Driven by Strong Volume Growth, Cash Expenses Dropped 28%... LOE- $6.40 per Boe, down 7% Taxes- $2.19 per Boe, up 4% G&A- $3.26 per Boe, down 47% Int. Exp.- $7.14 per Boe, down 39% …Driving Field Margins Up 119% in 3Q17 Revenues per Boe- $38.14, up 8% Expenses per Boe- $18.99, down 29% Field Margin per Boe- $19.15, up 122%
Core Eagle Ford Position with Substantial Inventory Note: Breakeven based on 0% IRR , using field cash flows & assumes $3.00 NYMEX Henry Hub gas price. 1 IRRs calculated based on costs and expenses in Mid year 2017 reserve report and NYMEX Strip as of November 6, 2017. Engineered Locations 257 6 43 35 20 3 22 22 21 67 18 IRR¹ 39% 144% 62% 65% 36% 52% 29% 28% 16% 30% 18%
Crude Oil Weighted Production Yields High Margins 3Q17 LOE / Boe Cost and % Liquids 3Q17 EBITDAX Margin Source: Company 10-Q filings based for the period ended September 30, 2017
Five Year Capital Investing Efficiency 5-Year Historical Finding & Development Cost Recycle Ratio1 Note: All Finding & Development Costs and Operating Cash Flow figures are provided by Seaport Global Securities. ECR, SRCI, WRD & XOG excluded from peer group due to absence of 5 year data 1 Recycle Ratio calculated: Operating Cash Flow per BOE / All Sources F&D Cost per BOE
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 31 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 Over 25 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 32 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
Eagle Ford Shale Asset Overview
Geo-Engineered Completions 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 Integrated Approach to Drilling, Completion, Stimulation & Production of Eagle Ford Laterals Technical Process Application Experience Horned Frog (2015) Beall Ranch (2015, 2016) Cyclone (2016, 2017) Burns Ranch (2016, 2017) Beall Ranch (2015, 2016) Cyclone (2016, 2017) Burns Ranch (2016, 2017) Beall Ranch (2016. 2017) Cyclone (2016, 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 BroadbandTM Sequence Diverter 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 Analysis Lonestar has been a longstanding proponent of controlled flowbacks Implement solids and fluids analysis to avoid negative impact of hydraulic fractures and assess success of completion strategies Horned Frog (2015) Beall Ranch (2015, 2016) Cyclone (2016, 2017) Burns Ranch (2016, 2017) Beall Ranch (2016) Cyclone (2016, 2017) Burns Ranch (2016, 2017)
The Value of Extended Reach Laterals in the Eagle Ford Vertical + Angle Drilling Completion Casing Tubing Cementing $1.2 MM Surface & Facilities Drilling Pad Wellhead Equipment Separation Storage Compression Gathering $0.4 MM 5,000’ Lateral Drilling Completion Casing Fracture Stimulation Other $3.0 MM $0.4 MM $1.6 MM $4.6 MM +5,000’ Lateral Drilling Completion Casing Fracture Stimulation Other $2.1 MM $6.7 MM Total Total Extended Reach Cumulative Cost Cumulative Cost Cumulative Cost Cumulative Cost Note: NYMEX Strip as of November 6, 2017 1 Surface and faculties costs are allocated for 3 well pad (Source of reserve forecast for 10,000’ lateral- W.D. Von Gonten from our Cyclone area); 2IRR based on reserve forecast for 10,000’ lateral and average type curve from W.D. Von Gonten for our Cyclone area Lateral 5,000’ + 5,000’ 10,000’ Completed Well Cost ($MM) $4.6 MM $2.1 MM $6.7 MM Gross Reserves (BOE) 289,000 346,000 635,000 Net Reserves (BOE) 234,000 287,000 521,000 Finding & Onstream Cost ($/BOE) $19.66 $7.32 $12.96 PV10 ($MM) $1.5 MM $4.0 MM $6.0 MM Internal Rate of Return2 26% 225% 62%
Strong Well Results Cyclone – Central Region Wildcat – Eastern Region Cyclone Harvey Johnson Aguila Vado Wildcat Deep Brazos Shallow Brazos Well name Operator IP-30 BOEPD % Liquids Cyclone #4H Lonestar 653 93% Cyclone #5H Lonestar 625 93% CR 298 1H EOG 703 96% Merritt 9H EOG 291 95% Hagen EF 2H Marathon 503 99% Lessor D 2H EOG 330 96% Barnhardt No. 8H Marathon 139 94% Well name Operator IP-30 BOEPD % Liquids Wildcat B1H Lonestar 2,123 75% Rodgers 1H Apache 1,812 74% Walker Family 3H Apache 1,783 79% Tucker Unit 2H Apache 1,626 79% Goen Family 2H Apache 1,586 74% Ewert 3H Apache 1,515 74% Rodgers 3H Apache 1,491 75% 5 2 3 4 5 1 2 3 4 5 7 6 1 3 4 5 7 6 2 1 2 7 6 3 4 1 6 7 Gen 1 Gen 2 Gen 3 Horned Frog – Western Region La Salle Well name Operator IP-30 BOEPD % Liquids Horned Frog A1H Lonestar 1,337 60% Horned Frog B1H Lonestar 1,294 61% ARN 2H Silverbow 1,165 63% PGE Maguey A1H Chesapeake 1,121 57% Ernst LAS C1H Chesapeake 1,061 77% Weeks C3H Statoil 848 58% Carden EF 6H Silverbow 765 54% 3 4 5 7 6 3 4 5 6 7 1 2 1 2
Horned Frog – Locator Map Gonzales Horned Frog Area Summary In March, 2015, Lonestar identified a 4,402-acre block held by Conoco-Phillips which was set to expire on July 5, 2015. On April 29, 2015, Lonestar farmed-in for 100% WI and delivered COP a 3.0% ORRI. Lonestar conducted a preliminary field study and determined that well results could be improved with proper geo-steering and higher proppant concentrations. Lonestar (100% WI) completed the A1H & B1H with perforated intervals of 8,233’ and 1,556 #/ft of proppant. Wells were steered within a petrophysically-derived 20-foot window. Average Max-30 day rates of 1,438 BOEPD (A1H) and 1,315 BOEPD (B1H) set records for the area. Lonestar (10% WI) drilled the D1H and E1H in 4Q15, and encountered significant geosteering challenges, and disappointing results. After HBP’ing the acreage, Lonestar commenced a more in-depth development optimization study. In May, 2017, LONE acquired an additional 1,070 net acres in the area. LONE has acquired the 3-D seismic across the greater Horned Frog acreage to prepare for development drilling in 2018.
EUR Improvement – Western Region (Horned Frog) Drilling and Completion Design Evolution LONE’s Gen 3 Completion enhanced EURs by 130% from 0.5 MMBoe to 1.2 MMBoe Lonestar used petrophysics to select 20-foot target Lonestar pumped >1,500# in engineered stages LONE’s Current Proved Reserves are 1.0 MMBOE per well 0.2 MMbbls crude oil / 0.3 MMbbls NGLs / 3.3 Bcf natural gas Generate 28% IRR at Strip pricing as of November 6, 2017 LONE Plans Significant Improvements to Gen 4 Development Wells Pump @1,800# with diverters in engineered stages Utilize more aggressive choke management with a goal of increasing oil recoveries by as much as 160,000 barrels Generation 1 Proppant <1,000# Broad Geotarget Generation 2 Proppant >1,000# Tighter Geotarget Generation 3 Proppant >1,500# 20-foot Geotarget Gen 3 Completions Outperforming Offsets (26 Mo Cum) Gen 3 Completions Outperforming Gen 3 Designs have Improved EURs1 (MBOE) Wells Drilled # Proppant / Ft 130% EUR Improvement 39 891 # 2 1,572# 22 1,103 # Gen 1 Gen 2 Gen 3 LONE 1 EURs are Lonestar internal estimates
Cyclone – Locator Map Wilson Gonzales De Witt Wilson Gonzales Cyclone Area Summary Cyclone #10H Cyclone #9H Cyclone #5H Cyclone #4H Cyclone #27H Cyclone #26H Hawkeye Lonestar gained entry to its Cyclone position in 2016 Lonestar acquired a total of 2,906 gross / 2,656 net acres in 2016 Primary Term Leasing Exchange Agreement with Lucas Lonestar completed 6 wells since Cyclone in May, 2016 Lonestar has acquired another 1,654 acres at Hawkeye ($3.4 MM) MY17 Reserves & PV-10: PDP- 6 wells*, 1.3 MMBOE, $31.2 MM PV10 PUD- 26 locs, 6.6 MMBOE, $71.6 MM PV10 PROB- 17 locs, 5.0 MMBOE, $37.7 MM PV10 Total- 43 locs, 12.9 MMBOE, $140.5 MM PV10 * Cyclone 26H & 2&H were converted to PDP in Sep-17
EUR Improvement – Central Region (Cyclone) Drilling and Completion Design Evolution Gen 3 Completions Outperforming Offsets Gen 3 Completions Outperforming Increased Intensity has Improved EURs1(MBbls) Gen 1 Gen 2 Gen 3 LONE 200% EUR Improvement 11 759# 3 1,103# 2 1,518# 4 1,516# 1 EURs are Lonestar internal estimates LONE’s Gen 3 Completion enhanced oil EURs by 200% from 0.1 MMBO to 0.4 MMBO Lonestar used petrophysics to select a 20-foot target Lonestar pumped >1,500# in engineered stages, with diverters LONE’s Current Proved Reserves are 0.7 MMBOE per well 0.6 MMbbls crude oil / 0.1 MMbbls NGLs / 0.5 Bcf natural gas Generate 62% IRR at Strip pricing as of November 6, 2017 LONE Generating Improved Results-to-date in Gen 4 Development Wells Cyclone #4H, #5H- online June 2017 with perf. Intervals of 8,996’ (IP30- 653 Boe/d) Pumped 1,820 #/ft with diverters in engineered stages Cyclone #26H, #27H- online Sept 2017 with perf. intervals of 8,315’ (IP30- 709 Boe/d) Pumped 1,526 #/ft with diverters in engineered stages Generation 1 Proppant <1,000# Broad Geotarget Generation 2 Proppant >1,000 Tighter Geotarget Generation 3 Proppant >1,500# 20-foot Geotarget Wells Drilled # Proppant / Ft Cyclone #4H #5H Cyclone #9H #10H
Wildcat – Locator Map Acquired original interests as part of Clayton Williams acquisition in 2013 (523 net acres). Built out acreage position with 98 leases to 1,260 acres. Offset operator drilled 16 wells in 2015 & 2016 with encouraging early production rates. Wildcat Summary Wildcat Arhopulos McFarlane LEGEND Lonestar Acreage Partner Acreage Eagle Ford Well
EUR Improvement – Eastern Region (Wildcat) Drilling and Completion Design Evolution Wildcat B1H Has Outperformed Offsets To Date LONE’s Wildcat B1H Well Has Outperformed Gen 2 Wells Increased Proppant, Steering has Improved EURs1(MBOE) 61% EUR Improvement 6 1,717’ 15 2,184’ 1 2,089’ LONE’s Gen 3 Completion Represents Leap Forward in Recoveries Geo-steered in petrophysically-derived 20-foot window Lonestar pumped @2,100# in engineered stages Lonestar has aggressively choke-managed the Wildcat B1H (20/64”) Wildcat B#1H Outperforming Offset Wells 6-Month Cumulative Production 66% Better than Avg. Offset Well 6-Month Cumulative Production 21% Better than Best Offset Well Initial Reserves Upgraded 31% from 0.8 MMBOE to 1.1 MMBOE per well 0.4 MMbbls crude oil / 0.4 MMbbls NGLs / 1.6 Bcf natural gas Generate 39% IRR at Strip pricing LONE Has Significant Unbooked Inventory in Brazos County 9,555 gross / 6,420 net acres 46 gross / 30 net drilling locations Generation 1 Proppant <2,000# Generation 2 Proppant >2,000# Generation 3 Proppant >2,000# 20-foot Geotarget Wells Drilled # Proppant / Ft Gen 1 Gen 2 Gen 3 LONE 1 EURs are Lonestar internal estimates
Financial Overview
Financial Strategy Preserve Financial Flexibility Capital Budget – Limit NTM Capital Expenditures to NTM Cash Flow on a Rolling Basis Seek to drive Leverage Ratios into the mid-2x’s in near term Strong Asset Coverage – 2.1x @ 9/30/17 & 1.9x fully drawn Hedge to Secure Cash Flows Maintain Liquidity to Support Future Growth Lonestar’s Long-Term Strategy Has Focused On Hedging Significant Volumes on a Programmatic Basis 2014-2016 – Lonestar Hedged an Average of 74% of its Annual Crude Oil Production Volumes 2017- ~91% of Expected Crude Oil Production Hedged at $52.78/barrel 2018- ~70% of Expected Crude Oil Production Hedged at $51.79/barrel 2019- ~52% of Expected Crude Oil Production Hedged at $48.90/barrel Seek to increase Borrowing Base with Internally Funded Capital Program Sufficient liquidity as of September 30, 2017 ($37MM)
Strong Strip PV-10 Asset Coverage Reserve Report – Strip Pricing Reserve Category Net Oil (MMBoe) Net NGLs (MMBoe) Net Gas (Bcf) Equivalent (MMBoe) NYMEX Pricing 1 PV-10 ($MM) SEC Pricing 2 PV-10 ($MM) PDP 12.4 3.1 18.2 18.5 $250.2 $213.2 PUD 40.9 8.2 55.1 58.3 $345.8 $250.0 Total Proved 53.3 11.3 73.3 76.8 $595.9 $463.2 Confidence Converting Undeveloped Reserves to PDPs Low-cost position allows for efficient conversion of undeveloped reserves to PDP ~100% drilling success rate on existing wells Significant liquidity to implement drilling plan Experience in the Basin providing insight into optimal well spacing and drilling and completions techniques for the area 1 Mid-year 2017 Strip Reserves based on NYMEX strip as of 11/6/2017 2 SEC Pricing assumes $48.95 oil flat & $3.00 gas flat
Internally Funded Growth Note: 1Q17 – 2Q17 periods are pro forma the acquisition. Cash Flow represents estimated EBITDAX (2017E: $74mm, 2018E: $110mm) less 3Q17 annualized interest expense $20mm. Such estimates are for illustrative purposes only. EBITDAX defined as realized prices, including hedging gains/losses, less field operating and G&A expenses. Drilling & Completion Spending vs. Cash Flows ($MM)
High Levels of Commodity Price Protection 1 Total production based on 2H17 estimated volumes 2 Based on 4Q17 hedges Since inception, Lonestar has implemented a strategy to reduce the effects of volatility of oil and natural gas prices on the Company’s results of operations by securing fixed price contracts for a portion of its expected sales volumes Hedging Program focuses on Crude Oil (63% of total production volumes1) ~90% ~40% Oil – WTI Fixed Price Swap Natural Gas – Henry Hub Fixed Price Swap Volume Hedged Weighted Average Hedge Price $52.78 $49.64 $3.36 $3.09 $51.79 $48.90 ~91% ~50% 64% 85% ~70% ~15% $ / Mcf: % of Production Hedged $85.76 $71.02 $ / Bbl:
Appendix
Lonestar capitalization overview Current Capitalization as of 9/30/17 1 LONE reported EBITDAX for the 3 months ended 9/30/17 multiplied by four as amended for RBL for 3Q17 2 Credit Metrics assume 100% equity treatment for the Series A Convertible Preferred * Please see the reserves disclosures at the end of this presentation LONE Reported ($MM) (as of 9/30/17) Cash $5 Senior Credit Facility 128 Second Lien 12.000% Notes - 8.750% Senior Unsecured Notes 152 Total Debt $280 Perpetual Convertible Preferred 80 Common + Retained Earnings 152 Total Stockholders Equity $232 Financial & Operating Statistics LTM EBITDAX1 $81 LTM Interest Expense 26 Q317 Daily production (Mboe/d) 7,662 Liquidity Borrowing Base $160 Cash 5 Credit Facility Borrowings (128) Total Current Liquidity $37 Credit Metrics2 Net Debt / LTM EBITDAX 3.4x Interest Coverage 3.1x Asset Coverage* 2.1x Asset Coverage (Fully Drawn) 1.9x
Organizational Structure LNR America, Inc. (Delaware) Lonestar Resources, Inc. (Delaware) Lonestar Operating, LLC (Texas) Various Subsidiaries (Texas LLC’s) 100% 100% 100% Parent Lonestar Resources US, Inc. (A Nasdaq Listed Delaware Corporation) 50% Lonestar Resources America, Inc. (Delaware) 100% Lonestar Resources Intermediate, Inc. (Delaware) 50% The subsidiaries of LRAI are guarantors along with LRAI of the revolver and bond debt Created in December 2015 for redomicilation and equity transfer of LRAI from LNR (Australia) Created in June 2016 for redomicilation/tax purposes Restricted Group
Reserves Information Oil & Natural Gas Reserves This presentation provides disclosure of LONE’s proved reserves, which are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions (using unweighted average 12-month first day of the month prices), operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. In this presentation, proved reserves attributable to LONE as of 6/30/17 are estimated utilizing SEC reserve recognition standards and pricing assumptions based on SEC pricing of (i) $48.95 / Bbl crude, $3.00 / MMBtu natural gas. References to our estimated proved reserves as of 6/30/17 are derived from our proved reserve reports prepared W.D. Von Gonten & Co. (“WDVG”). The average future prices for benchmark commodities used in determining our 11/6/17 Strip Pricing reserves were $57.09 for oil for 2017, $56.66 for 2018, $53.07 for 2019, $50.93 for 2020, $49.88 for 2021, $49.60 for 2022, $49.84 for 2023, $50.36 for 2024, $50.97 for 2025, $51.37 for 2026, and escalated 3% thereafter and $3.09/MMBtu for natural gas for 2017, $3.05 for 2018, $2.92 for 2019, $2.87 for 2020, $2.87 for 2021, $2.89 for 2022, $2.95 for 2023, $3.02 for 2024, $3.09 for 2025, $3.17 for 2026, and escalated 3% thereafter. We may use the term “expected ultimate recoveries” (“EURs”) or other descriptions of volumes of reserves, which terms include quantities of oil and natural gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC's guidelines strictly prohibit LONE from including in filings with the SEC. Unless otherwise stated in this presentation, such estimates have been prepared internally by our engineers and management without review by independent engineers. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized, particularly in areas or zones where there has been limited or no drilling history. We include these estimates to demonstrate what we believe to be the potential for future drilling and production by the Company. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. In addition, we have made no commitment to drill all of the drilling locations. Ultimate recoveries will be dependent upon numerous factors including actual encountered geological conditions, the impact of future oil and natural gas pricing, exploration and development costs, and our future drilling decisions and budgets based upon our future evaluation of risk, returns and the availability of capital and, in many areas, the outcome of negotiation of drilling arrangements with holders of adjacent or fractional interest leases. Our estimates may change significantly as development of our properties provide additional data and therefore actual quantities that may ultimately be recovered will likely differ from these estimates. Our related expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells, the undertaking and outcome of future drilling activity and activity that may be affected by significant commodity price declines or drilling cost increases. Engineered Acreage is acreage to which Proved, Probable and/or Possible reserves have been assigned to drilling location on that acreage by our independent petroleum consultants Non-Engineered acreage is acreage to which Proved, Probable and/or Possible reserves have not been assigned to drilling location on that acreage by our independent petroleum consultants
Non-GAAP Reconciliation Reconciliation of Non‐GAAP Financial Measures Adjusted EBITDAX Adjusted EBITDAX is not a measure of net income as determined by GAAP. Adjusted EBITDAX is a supplemental non‐GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. The Company defines Adjusted EBITDAX as net (loss) income before depreciation, depletion, amortization and accretion, exploration costs, non‐recurring costs, (gain) loss on sales of oil and natural gas properties, impairment of oil and gas properties, stock‐based compensation, interest expense, income tax (benefit) expense, rig standby expense, other income (expense) and unrealized (gain) loss on derivative financial instruments and unrealized (gain) loss on warrants. Management believes Adjusted EBITDAX provides useful information to investors because it assists investors in the evaluation of the Company’s operating performance and comparison of the results of the Company’s operations from period to period without regard to its financing methods or capital structure. The Company excludes the items listed above from net income in arriving at Adjusted EBITDAX to eliminate the impact of certain non‐cash items or because these amounts can vary substantially from company to company within its industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. The Company’s computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. The following table presents a reconciliation of Adjusted EBITDAX to the GAAP financial measure of net income (loss) for each of the periods indicated. 1 Interest expense consists of Amortization of finance costs and Dividends paid on the preferred stock 2 Represents a non‐recurring cost associated with a drilling rig contract 3 Non‐recurring costs consists of Acquisitions Costs and General and Administrative Expenses related to the re‐domiciliation to the United States, and listing on the NASDAQ.