Lonestar Resources, Ltd. IPAA / OGIS Conference April, 215
Disclaimer and Forward Looking Statements Disclaimer This document has been prepared by Lonestar Resources Limited ( Lonestar or Company ) in connection with providing an overview to interested analysts / investors. The information in this presentation is of a general nature and does not purport to be complete. This announcement is not intended as and shall not constitute an offer, invitation, solicitation, or recommendation with respect to the purchase or sale of any securities in any jurisdiction and should not be relied upon as a representation of any matter that a potential investor should consider in evaluating Lonestar. Lonestar, nor any of its affiliates, subsidiaries, directors, agents, officers, advisers or employees, make any representation or warranty, express or implied, as to or endorsement of, the accuracy or completeness of any information, statements, representations or forecasts contained in this announcement, and they do not accept any liability or responsibility for any statement made in, or omitted from, this announcement. Lonestar accepts no obligation to correct or update anything in this announcement, except as required by law. No responsibility or liability is accepted and any and all responsibility and liability is expressly disclaimed by Lonestar and its respective affiliates, subsidiaries, directors, agents, officers, advisers and employees for any errors, misstatements, misrepresentations in or omissions from this announcement. Users of this information should make their own independent evaluation of an investment in or provision of debt facilities to Lonestar. Nothing in this announcement should be construed as financial product advice, whether personal or general, for the purposes of section 766B of the Corporations Act 21 (Cth). This announcement does not involve or imply a recommendation or a statement of opinion in respect of whether to buy, sell or hold a financial product. This announcement does not take into account the objectives, financial situation or needs of any person, and independent personal advice should be obtained. This announcement and its contents may not be reproduced or re distributed in any way without the express written permission of Lonestar. Lonestar has presented petroleum and natural gas production and reserve volumes in barrel of oil equivalent ( boe ) amounts. For purposes of computing such units, aconversion rate of 6, cubic feet of natural gas to one barrel of oil equivalent (6:1) is used. The conversion ratio of 6:1 is based on an energy equivalency conversion method which is primarily applicable at the burner tip and does not represent value equivalence at the wellhead. Readers are cautioned that boe figures may be misleading, particularly if used in isolation. Forward Looking Statements Statements in this announcement reflect management's expectations relating to, among other things, target dates, Lonestar s expected drilling program and the ability to fund development are forwardlooking statements, and can generally be identified by words such as "will", "expects", "intends", "believes", "estimates", "anticipates or similar expressions. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward looking statements. Statements relating to reserves are deemed to be forward looking statements as they involve the implied assessment, based on certain estimates and assumptions that some or all of the reserves described can be profitably produced in the future. These statements are not historical facts but instead represent management's expectations, estimates and projections regarding future events. Although management believes the expectations reflected in such forward looking statements are reasonable, forward looking statements are based on the opinions, assumptions and estimates of management at the date the statements are made, and are subject to a variety of risks and uncertainties and other factors that could cause actual events or results to differ materially from those projected in the forward looking statements. These factors include risks related to: exploration, development and production; oil and gas prices, markets and marketing; acquisitions and dispositions; competition; additional funding requirements; reserve estimates being inherently uncertain; incorrect assessments of the value of acquisitions and exploration and development programs; environmental concerns; availability of, and access to, drilling equipment; reliance on key personnel; title to assets; expiration of licences and leases; credit risk; hedging activities; litigation; government policy and legislative changes; unforeseen expenses; negative operating cash flow; contractual risk; and management of growth. In addition, if any of the assumptions or estimates made by management prove to be incorrect, actual results and developments are likely to differ, and may differ materially, from those expressed or implied by the forward looking statements contained in this document. Such assumptions include, but are not limited to, general economic, market and business conditions and corporate strategy. Accordingly, investors are cautioned not to place undue relianceonsuchstatements. All of the forward looking information in this announcement is expressly qualified by these cautionary statements. Forward looking information contained herein is made as of the date of this document and Lonestar disclaims any obligation to update any forward looking information, whether as a result of new information, future events or results or otherwise, except as required by law. Currency All amounts in this presentation are US$ unless otherwise stated. Lonestar s presentation currency is $US. 2
Company Profile Lonestar is a rapidly growing E&P company focused on the Eagle Ford Shale $.7 Share Price History 1. Drilling and acquisition capital concentrated in the crude oil window of the Eagle Ford Shale Long term development plan is funded out of cash flow Combine management and technical expertise with balance sheet to opportunistically consolidate assets in the oil window Maximize value of Conventional and Bakken assets Share Price (US$) $.6 $.5 $.4 $.3 Crude Oil $.2 78% $.1 $. NGLs 9% 8. 6. 4. 2.. Volume (MM Shares) Volume Share Price Financial Profile Asset Profile 3 Ticker (OTCQX / ASX) LNREF / LNR Share Price 1 $.15 Shares Out 752.2 Market Cap $112.8 Cash 2 $1. Long Term Debt $269. Enterprise Value $371.8 Category Oil (MMBbls) NGL s (MMBbls) Gas (Bcf) Reserves (MMBOE) SEC PV1 ($MM) Proved 23.6 3. 26. 3.1 $75.8 Probable 1.7.7 5.4 12.3 $153.8 Possible 4.2.3 2.4 4.9 $92.5 Total 38.5 4. 33.7 48.1 $952.2 1 In U.S. dollars, as of April 17, 215 2 In U.S. dollars, as of December 31, 214 3 Please see the reserves disclosures at the end of this presentation 3
Lonestar s Footprint 1 BAKKEN THREE FORKS 35, net acres Resource Assessment 3 D Seismic Complete 8 Conventional Prospects identified Intense Fracturing in Unconventional Targets CONVENTIONAL OIL & GAS Mature Producing Assets 3.5 MMBOE of Engineered Reserves $11 MM of EBITDAX EAGLE FORD SHALE 31,358 net acres Active Acquisition & Development 44.6 MMBOE of Engineered Reserves +95% of Lonestar s 215 Capital Budget 1. Please see the reserves and EBITDAX disclosures at the end of this presentation 4
1 ($mm) $4 $35 $3 $25 $2 $15 $1 $5 $ Ba rnet EFSA MU Lonestar s Track Record of Rapid Growth Net Acreage Eagle Ford Shale Trend 35, 3, 25, 2, Reserves (MMBOE) 1 5 4 3 15, 1, 5, Dec 11 Dec 12 Dec 13 Dec 14 Engineered 2 1 Dec 11 Dec 12 Dec 13 Dec 14 Proved Probable Possible PV 1 1 EBITDAX 2 $1, $1 $9 $8 $7 $6 $5 $4 $3 $2 $1 $ Dec 1 Dec 1 1 Dec 12 Today1P PV Dec 11 Dec 12 Dec 13 Dec 14 Proved Probable Possible $9 $8 $7 $6 $5 $4 $3 $2 $1 $ Dec 11 Dec 12 Dec 13 Dec 14 1 Please see the reserves disclosures at the end of this presentation 2 Please see the EBITDAX assumptions at the end of this presentation 5
Management Team Background and Track Record
High Caliber Management Team Executive Previous Experience Biography Frank D. Bracken, III Chief Executive Officer GOG Gerrity Oil & Gas Over 28 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 / Board Member of Gerrity Oil & Gas Corp, a NYSE listed E&P Company Barry D. Schneider Chief Operating Officer Over 28 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 Tom H. Olle Senior Vice President Operations Over 36 years oil and gas industry experience Senior level expertise in reservoir management / project development across a broad array of reservoir types Previous senior roles at US public companies Encore Acquisition Corp and Burlington Resources Douglas W. Banister Chief Financial Officer CPA with 28 years experience in finance, planning and business development Prior experience with international companies such as Uniden, LSG Sky Chefs, and Ernst & Young Most recently, VP / Controller at ontargetjobs.com High Caliber Executive Team with Deep Industry Expertise and 3 Years of Average Experience 7
High Caliber Management Team (Cont d) Executive Previous Experience Biography Scott E. Sabatka Vice President Geosciences Over 34 years US / international exploration and development experience, including in the Texas Gulf Coast, Permian, Williston, Powder and Malay Basins Previously Director of Geosciences at Approach Resources, Northern Region Geoscience Manager at Encore Acquisition Corp, and a Sr. Staff Geologist for Exxon Joe Young Manager Drilling & Completions Engineer with 13 years of experience in drilling and completions Positions of increasing responsibility at Schlumberger Drilling and completions engineer at Pioneer Natural Resources in Eagle Ford Shale and Wolfcamp Shale plays Tracy Hindman Manager Field Logistics Service Drilling Over 31 years of oil and gas service experience 16 years of turnkey drilling experience at Service Drilling, Southeast, LLC Most recently General Manager Gulf Coast Division of Unit Drilling Texas Rod Hicks Manager Field Operations Over 33 years of oil and gas drilling, completion and operations experience Held positions of increasing responsibility at Kerr McGee, Encore Acquisition Corp, and Quantum Resources High Caliber Executive Team with Deep Industry Expertise and 3 Years of Average Experience 8
Eagle Ford Shale Growth and Development Plan
Well Positioned In Low Price Environment Focused Operations In The Eagle Ford Shale +3, Net Acres in the Crude Oil Window That Allow For Sustained Drilling Activity 1% Operated, Allowing for Control of Timing and Quality of Capital Expenditures 2 46% IRR Returns (at Strip) Available Across Portfolio at Current Well Costs Durable Cash Expense Structure 1 Created a High Margin Cost Structure in the Eagle Ford Shale Eagle Ford Operating Expenses (LOE and Taxes) $9.59 per BOE Eagle Ford Total Cash Costs (LOE, Taxes, G&A and Interest Expense) $23.77 per BOE Capital Structure That Transcends Industry Volatility Net Debt / EBITDAX of ~2.9x at YE 214 Senior Unsecured Debt $22 MM Due 219, 8.75% Coupon Senior Secured Credit Facility $15 MM, with $49 MM Drawn at YE 214 Oil is Materially Hedged Through 216 Hedging is Not A Lucky Market Call, it is Capital Discipline 2,5 bopd swapped at $88. per bbl WTI in 215 1,9 bopd swapped at $8. per bbl WTI in 216 Acquired 3, Acres in a Highly Competitive Macro Environment Current Environment Could Be Materially More Hospitable to Further Asset Growth Already Gaining Access to Additional Acreage & Reserves Via Farm Ins 1
Lonestar Focused on Low Cost Basins $14 Break even WTI ($/Boe; 22.5:1 Oil / Gas Ratio) $12 $1 $8 $6 $4 $2 $ Source: ITG Investment Research 11
Lonestar Is Gaining Scale, Ratcheting Costs Lower $2. $1.2 $18. Lease Operating Expense Per BOE $16. $14. $12. $1. $8. $6. $4. $1. $.8 $.6 $.4 $.2 Lease Operating Expense ($MM) $2. $. Apr 14 May 14 Jun 14 Jul 14 Aug 14 Sep 14 Oct 14 Nov 14 Dec 14 Jan 15 Feb 15 Mar 15 Field Personnel Regulatory, Legal, Insurance Workover & Repairs Roads & Location Labor Direct Well Costs Chemicals Saltwater Disposal Gathering & Compression LOE ($MM) $. 12
Revenue/BOE vs % Oil Production $65. $6. LNREF $55. Revenue / BOE $5. $45. $4. $35. $3. % 1% 2% 3% 4% 5% 6% 7% 8% 9% 1% % Oil Production Note: Revenue/BOE from 4Q14. Peer companies include AXAS, AREX, CRK, ESTE, EOX, GST, GDP, HK, MTDR, PVA, SN, SFY, TPLM. 13
Production Cost/BOE vs % Oil Production $25. $2. Production Costs / BOE $15. $1. LNREF $5. $. % 1% 2% 3% 4% 5% 6% 7% 8% 9% 1% % Oil Production Note: Production Cost /BOE from 4Q14. Peer companies include AXAS, AREX, CRK, ESTE, EOX, GST, GDP, HK, MTDR, PVA, SN, SFY, TPLM. 14
Field Netback/BOE vs % Oil Production $55. $5. $45. LNREF Field Netback / BOE $4. $35. $3. $25. $2. % 1% 2% 3% 4% 5% 6% 7% 8% 9% 1% % Oil Production Note: Field Netback/BOE from 4Q14. Peer companies include AXAS, AREX, CRK, EOX, GST, GDP, HK, MTDR, PVA, SN, SFY, TPLM. 15
Lonestar s Leverage is Among Lowest of its Peers 12.x 1.x Debt/NTM EBITDAX 8.x 6.x 4.x Average 2.x.x Peer 11 Peer 4 Peer 3 Peer 7 Peer 1 Peer 6 Peer 12 Peer 5 LNREF Peer 9 Peer 2 Peer 8 Peer 1 Note: Debt is from the latest available public data. Peer companies include AXAS, AREX, CRK, EOX, GST, GDP, HK, MTDR, PVA, SN, SFY, TPLM. EBITDAX data is the average estimate from Global Hunter Securities, Canaccord Genuity, Stephens & Co. and SunTrust Robinson Humphreys 16
Lonestar s Hedges Are Among Highest of its Peers 9% % of Oil Hedged 215 8% 7% 6% 5% 4% 3% Highly Hedged in 215 Highly Hedged in 216 Lonestar 2% 1% % % 1% 2% 3% 4% 5% % Of Oil Hedged 216 Note: Debt is from the latest available public data. Peer companies include AXAS, AREX, CRK, EOX, GST, GDP, HK, MTDR, PVA, SN, SFY, TPLM. 17
215 Guidance 215 Eagle Ford Drilling Budget $74 to $83 million Average Daily Production Results & Guidance 15 gross / 13.5 net wells Negligible spending on Conventional Assets, similar to 214 Goal to essentially fund drilling budget out of cash flow 215 Net Production Guidance of 5,7 to 6,1 BOEPD Equates to 27 to 36% growth over 214 results Yields growth in output, based on 4Q15 vs. 4Q14 Production Mix Crude Oil 7 to 75% NGL s 9 to 11% Natural Gas 21 to 14% 215 EBITDAX Guidance of $84 to $95 million Based on a WTI oil price range of $5 to $6 Risked and unrisked production results from new drilling Crude Oil Hedges Provide Considerable Insulation 215 ~2,5 BOPD at ~$88. WTI (BOEPD) EBITDAX ($MM) 6,5 6, 5,5 5, 4,5 4, 3,5 3, 2,5 2, 1,5 1, 5 $1 $9 $8 $7 $6 $5 $4 $3 $2 $1 $ Dec 11 Dec 12 Dec 13 Dec 14 215 Guidance EBITDAX Results & Guidance Dec 11 Dec 12 Dec 13 Dec 14 215 Guidance $1 $9 $8 $7 $6 $5 $4 $3 $2 $1 $ WTI Oil Price ($/bbl) 18
Eagle Ford Shale Asset Overview
Portfolio Focused on the Eagle Ford Total Eagle Ford Net Acres Engineered Acreage 31,358 Gross Engineered Locations 143 Additional Locations 43 Avg. W.I. 92% Non Engineered Acreage Eastern Net Acres 1 1,73 Gross Engineered Locations 32 Additional Locations 43 Avg. W.I. 89% Central Net Acres 11,492 Gross Engineered Locations 61 Additional Locations Avg. W.I. 96% Western Net Acres 9,136 Gross Engineered Locations 5 Additional Locations Avg. W.I. 91% 1 Includes 1,481 net acres which are acquirable, subject to title 2
Lonestar s Footprint Across The Eagle Ford Is Significant 14 12 1 Counties With Completion 8 6 4 2 21
Western Region Summary Lonestar s Properties & Offset Wells Overview Gross Leasehold Net Leasehold % HBP Top EPS Lateral Lengths Assumed Spacing 6,' 4,' 1,38 9,136 91% 8,' 8,' 5' to to Engineered Acreage Non Engineered Acreage Property Summary Property Beall Ranch Asherton Meiners Gerke Burns Ranch Total Wells PDP 18 4 3 25 Engineered Locations PUD PROB POSS Total 17 17 6 6 3 3 6 18 24 32 18 5 Average WI% 98% 99% 85% 1% 79% 91% Burns Ranch Asherton Reserves Summary Beall Ranch Category PDP PUD Proved Probable Possible Total Reserves # Oil NGL's Wells (MMBbls) (MMBbls) 25 4.3 1.1 32 7. 1.6 57 11.3 2.7 18 2.7.5.. 75 14. 3.2 Gas Equiv. PV 1 (Bcf) (MMBOE) ($MM) 7.5 11.4 18.9 4.. 22.8 6.6 1.5 17.1 3.8. 21. $177 $212 $389 $72 $ $461 Note: Please see the Reserves disclosures at the end of this presentation. Reserves do not reflect recent announced acquisitions 22
Western Region Burns Ranch Area Overview Gross Leasehold 3,697 Net Leasehold 2,95 % HBP 7% Top EPS 7,3' to 8,' Assumed Spacing 5' WI% 79% NRI % 59% Engineered Locations Category # Length # PDP 5,' 1 PUD 6 6,' 2 PROB 18 7,' POSS 8,' 21 Total 24 Total 24 Engineered Acreage Non Engineered Acreage Single Well IRR Sensitivities (1,2) Burns Ranch Area Type Curve Oil Price ($/Bbl) $55 $65 $75 $85 $5.8 32% 5% 72% 98% Capex ($MM) $6.4 25% 39% 56% 77% $7.1 19% 31% 45% 62% Production (Boepd) 6 5 4 3 2 1 12 24 36 48 6 72 84 96 18 12 Oil NGLs Dry Gas Note: Type curves engineered by Lonestar 1. Assumes flat natural gas price of $3.5 / Mcf. 2. Assumes flat LLS differential of $3. / bbl. Months on Production 23
Western Region Beall Ranch Overview Gross Leasehold 2,39 Net Leasehold 2,335 % HBP 1% Top EPS 7,' to 7,3' Assumed Spacing 5' WI% 98% NRI % 73% Engineered Locations Category # Length # PDP 18 5,' 11 PUD 17 6,' 5 PROB 7,' 1 POSS 8,' Total 35 Total 17 Single Well IRR Sensitivities (1,2) Beall Ranch Short Lateral Type Curve Engineered Acreage Non Engineered Acreage Oil Price ($/Bbl) $55 $65 $75 $85 $3.4 52% 82% 121% 17% Capex ($MM) $3.8 4% 63% 94% 131% Production (Boepd) 5 4 3 2 1 $4.2 31% 5% 75% 13% 12 24 36 48 6 72 84 96 18 12 Oil NGLs Dry Gas Note: Type curves engineered by Lonestar 1. Assumes flat natural gas price of $3.5 / Mcf. 2. Assumes flat LLS differential of $3. / bbl. Months on Production 24
Central Region Summary Lonestar s Properties & Offset Wells Overview Gross Leasehold Net Leasehold % HBP Top EPS Lateral Lengths Assumed Spacing 11,978 11,492 54% to 9,5' to 8,' 5' 75' 6,' 5,' Engineered Acreage Non Engineered Acreage Southern Gonzales Property Summary Property Pirate Area S. Gonzales Gonzo Total Wells PDP 8 3 3 14 Gonzo Average Engineered Locations PUD PROB POSS Total WI% 15 21 36 1% 3 3 5% 22 22 1% 18 43 61 96% Pirate Reserves Summary Category PDP PUD Proved Probable Possible Total Reserves # Oil NGL's Wells (MMBbls) (MMBbls) 14 1.4.1 18 3.5.1 32 5..2 43 7.2.1.. 75 12.1.3 Gas Equiv. PV 1 (Bcf) (MMBOE) ($MM).4 1.1 1.5 1.. 2.4 1.6 3.8 5.4 7.5. 12.9 $64 $61 $126 $65 $ $19 Note: Please see the Reserves disclosures at the end of this presentation 25
Central Region Southern Gonzales Overview Gross Leasehold 97 Net Leasehold 485 % HBP 1% Top EPS 8,7' to 9,5' Assumed Spacing 5' 75' WI% 5% NRI % 38% Engineered Locations Category # Length # PDP 3 5,' PUD 3 6,' 3 PROB 7,' POSS 8,' Total 6 Total 3 Single Well IRR Sensitivities (1,2) Engineered Acreage Non Engineered Acreage Southern Gonzales Area Type Curve Oil Price ($/Bbl) $55 $65 $75 $85 $4.8 26% 46% 72% 16% Capex ($MM) $5.3 18% 34% 54% 79% $5.9 13% 25% 41% 61% Production (Boepd) 7 6 5 4 3 2 1 12 24 36 48 6 72 84 96 18 12 Oil NGLs Dry Gas Note: Type curves engineered by Lonestar 1. Assumes flat natural gas price of $3.5 / Mcf. 2. Assumes flat LLS differential of $3. / bbl. Months on Production 26
Central Region Pirate Area Overview Gross Leasehold 7,528 Net Leasehold 7,528 % HBP 59% Top EPS 6,' to 8,5' Assumed Spacing 75 WI% 1% NRI % 78% Engineered Locations Category # Length # PDP 8 5,' 5 PUD 15 6,' 19 PROB 21 7,' 12 POSS 8,' Total 44 Total 36 Engineered Acreage Non Engineered Acreage Single Well IRR Sensitivities (1,2) Pirate Area Type Curve Oil Price ($/Bbl) $55 $65 $75 $85 $5.8 2% 36% 56% 8% Capex ($MM) $6.4 14% 26% 42% 6% Production (Boepd) 5 4 3 2 1 $7.1 1% 2% 32% 42% 12 24 36 48 6 72 84 96 18 12 Oil NGLs Dry Gas Note: Type curves engineered by Lonestar 1. Assumes flat natural gas price of $3.5 / Mcf. 2. Assumes flat LLS differential of $3. / bbl. Months on Production 27
Eastern Region Summary Overview Lonestar s Properties & Offset Wells Gross Leasehold 12,78 Net Leasehold 1 1,73 % HBP 33% Top EPS 6,5' to 12,' Lateral Lengths 4,' to 8,' Assumed Spacing 75 Engineered Acreage Non Engineered Acreage Aguila Vado Property Summary Wells Engineered Locations Average Property PDP PUD PROB POSS Total WI% Robertson 2 8 8 8% N. Brazos 6 12 2 1 15 92% C. Brazos 2 7 9 84% S. Brazos 91% Total 8 12 4 16 32 89% Reserves Summary # Oil NGL's Gas Equiv. PV 1 Category Wells (MMBbls) (MMBbls) (Bcf) (MMBOE) ($MM) PDP 8 1.3.1.5 1.4 $55 PUD 12 3.3.1.7 3.5 $74 Proved 2 4.5.2 1.2 4.9 $129 Probable 4.8.1.4.9 $17 Possible 16 4.2.3 2.4 4.9 $93 Total Reserves 4 9.5.5 4. 1.7 $239 Note: Please see the Reserves disclosures at the end of this presentation 1 Includes 1,481 net acres which are acquirable, subject to title 28
Eastern Region Central Brazos Area Overview Gross Leasehold 2,328 Net Leasehold 1,948 % HBP 35% Top EPS 9,8' to 1,5' Assumed Spacing 75 WI% 68% NRI % 51% Engineered Locations Category # Length # PDP 5,' PUD 6,' PROB 2 7,' 2 POSS 7 8,' 7 Total 9 Total 9 Engineered Acreage Non Engineered Acreage Single Well IRR Sensitivities (1,2) Central Brazos Area Type Curve Oil Price ($/Bbl) $55 $65 $75 $85 $6.3 21% 36% 55% 79% Capex ($MM) $7. 16% 27% 41% 6% Production (Boepd) 7 6 5 4 3 2 $7.7 11% 2% 32% 46% 1 12 24 36 48 6 72 84 96 18 12 Oil NGLs Dry Gas Note: Type curves engineered by Lonestar 1. Assumes flat natural gas price of $3.5 / Mcf. 2. Assumes flat LLS differential of $3. / bbl. Months on Production 29
Conventional Assets Stability & Free Cash Flow
Conventional Assets 3.5 MMBOE Proved Reserves 1 79% Crude Oil 11% of Lonestar s Total Proved Reserves 727 BOEPD 4Q14 Production 57% Crude Oil & NGL s 12% of Lonestar s Total Production Long Lived Reserves with Low Capital Requirements Reserves/Production ratio of 15 years Current Capital Plans are de minimus Continue to Trim Around the Edges Sold Non Operated Raccoon Bend assets for $3.2 MM Sold for PV 11, Lowest Margin Asset in Conventional Portfolio West Texas North Texas East Texas South Texas Daily Production 1, 9 8 7 6 5 4 3 2 1 Jan 13 Feb 13 Mar 13 Apr 13 Net Production (BOEPD) May 13 Jun 13 Jul 13 Aug 13 Sep 13 Oct 13 Nov 13 Dec 13 Jan 14 Feb 14 Mar 14 Apr 14 May 14 Jun 14 Jul 14 Aug 14 Sep 14 Oct 14 Nov 14 Dec 14 North Texas West Texas East Texas South Texas Other 1. Please see Reserves disclosures at the end of this presentation 31
Bakken Three Forks Resource Assessment Moving Forward
West Poplar Project Williston Basin West Poplar Resource Assessment Greater Williston Basin Lonestar (65% WI) assembled 57,5+ gross acres in a contrarian move, across the Brockton Froid fault Horizontal Objectives Bakken, Three Forks, Lwr. Lodgepole Vertical Objectives Charles, Nisku, Greenhorn, Amsden, Mission Canyon, Tyler/Heath In July, 212 Lonestar and its partners drilled the Clark Farms #29 1 as a vertical completion Confirmed area is sufficiently mature, but not over cooked by Poplar Intrusion, as popularly believed Tested 4 o + API gravity crude from: Lower Lodgepole Bakken Three Forks Combined interval 15 thick one horizontal, one series of staged fracture stimulations to drain upwardly bounded by tighter Middle Lodgepole limestone downwardly bounded by anhydrite layer capping Nisku thinning of interval from Basin center has led to more brittle rock with macro and micro fractures as evident by cores Lonestar and its partners shot a 15 mi 2 3 D Survey, which has been processed and Interpreted 35 Charles targets $1.3 MM well costs, 154, BOE EUR 44 Nisku targets $1.5 MM well costs, 38, BO EUR 34 BPS locations $5.8 MM well costs, 5, BOE EUR Key Investment Considerations Large, contiguous unit allows for low cost exploration and rapid acreage retention Low levels of drilling hold entire unit for 5 years Commercial production stops lease expirations Only 2 horizontals required to fulfil terms of unit agreement 3 D seismic has defined ~8 conventional vertical targets Nisku and Charles optimized structural placement up dip from producers and show wells Low cost means of retaining acreage while Bakken play is matured and optimized, oil prices recover Bakken Petroleum System physical evidence for high probability of economic success hydrocarbon mature, fractured, relatively shallow 3 D seismic allows for in zone placement of laterals, optimized orientation for fracture systems 33
Appendix
Glossary 1P reserves means proved reserves. 2P reserves means proved plus probable reserves. bbl means barrel. boe means barrels of oil equivalent, determined using a ratio of 6 Mcf of natural gas to 1 bbl of condensate or crude oil scf means standard cubic feet. btu means British thermal units. m prefix means thousand. mm prefix means million. b prefix means billion. pd suffix means per day. NGL means Natural Gas Liquids, including condensate these products are stripped from the gas stream at 3rd party facilities remote to the field. TEV means total enterprise value LTM means last twelve months NTM means next twelve months HBP means held by production EPS means earnings per share Note: BOE may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf : 1bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf : 1 bbl, utilising a conversion ration of 6 Mcf : 1 bbl may be misleading if used in isolation. 35
Reserves Information Reserves Reporting: Pursuant to ASX Listing Rules ( LR ) the reserves information in this document: (i) is effective as at 1 January, 215 (LR 5.25.1) (ii) has been estimated and is classified in accordance with SPE PRMS (Society of Petroleum Engineers Petroleum Resources Management System) (LR 5.25.2) (iii) is reported according to the Company s economic interest in each of the reserves and net of royalties (LR 5.25.5) (iv) has been estimated and prepared using the deterministic method (LR 5.25.6) (v) has been estimated using a 6:1 BOE conversion ratio for gas to oil, pursuant to the information in the disclaimer section of this document (LR 5.25.7) Other Reserves Information: Lonestar operates most of its properties which are generally held by standard oil and gas lease arrangements. Detailed information on the operator and lease arrangements is disclosed in the Company announcement related to the initial acquisition of properties. The Company s working interest ownership (WI%) and net revenue interest ownership (NRI%) in relation to each of its properties are generally included in the Company s presentations which are available on the ASX or the Company s websites. Well spacing assumptions and lateral length assumptions are generally included in the Company s presentations as is additional information on capital cost and taxation assumptions. In accordance with ASX LR 5.43 the Company confirms that it is not aware of any new information or data that materially affects the reserves information included in previous Company announcements including as to material assumptions and technical parameters underpinning the estimates, other than as set out in this announcement. Qualified Petroleum Reserves and Resources Evaluators: In accordance with ASX Listing Rules 5.41 and 5.42: The reserve reporting provided in this document in relation to the Company s Eagle Ford Shale properties is based on and fairly represents information and supporting documentation that has been prepared by Mr. William D. Von Gonten, Jr., P.E., and Mr. Taylor D. Matthes, P.E. who are employed by W. D. Von Gonten & Co Petroleum Engineering. Mr. Von Gonten holds a Bachelor of Science degree in Petroleum Engineering from Texas A&M University and Mr. Matthes holds a Bachelor of Science degree in Petroleum Engineering from Texas A&M University. Both of these persons are Registered Texas Professional Engineers. Mr. Von Gonten has 24 years of experience as a Petroleum Engineer and Mr. Matthes has more than 5 years of experience as a Petroleum Engineer. Both of these persons are members of the Society of Petroleum Engineers. Messrs. Von Gonten and Matthes have consented to the inclusion in this document of the information and context in which it appears. The reserve reporting provided in this document in relation to the Company s Conventional properties is based on and fairly represents information and supporting documentation that has been prepared by Mr. William M. Kazmann who is President and Senior Partner La Roche Petroleum Consultants, Ltd. Mr. Kazmann received his Bachelor of Science and Master of Science degrees in Petroleum Engineering from the University of Texas at Austin in 1973 and 1975 respectively. He has worked in the oil and gas industry since that time. Mr. Kazmann is a Licensed Professional Engineer in the State of Texas and is a member of the American Association of Petroleum Geologists, Society of Petroleum Engineers, Society of Independent Professional Earth Scientists (serving as National Director from 1993 to 1996 and National Treasurer in 1994 and 1995), Dallas Geological Society, and Dallas Petroleum Club (serving as Director from 24 through 26). Mr. Kazmann has consented to the inclusion in this document of the information and context in which it appears. Reserves Cautionary Statement: Hydrocarbon reserves and resource estimates are expressions of judgment based on knowledge, experience and industry practice. Estimates that were valid when originally calculated may alter significantly when new information or techniques become available. Additionally, by their very nature, reserve and resource estimates are imprecise and depend to some extent on interpretations, which may prove to be inaccurate. As further information becomes available through additional drilling and analysis, the estimates are likely to change. The may result in alterations to development and production plans which may, in turn, adversely impact the Company s operations. Reserves estimates and estimates of future earnings are, by nature, forward looking statements and subject to the same risks as other forward looking statements. Commodity Pricing Used: Lonestar s reserves and PV 1 have been estimated using index prices determined in accordance with US SEC pricing guidelines for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the lift of the properties. The unweighted arithmetic averages of the first day of the month prices for the year ended December 31, 214 were $94.99 per bbl for oil and $4.35 per mmbtu for natural gas and for the year ended December 31, 213 were $96.94 bbl for oil and $3.66 per mmbtu for natural gas. These prices were adjusted by lease for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead." 36
EBITDA Assumptions EBITDA estimates are based on the following assumptions: Production estimates as set out in this presentation. The total number of planned wells at each asset is consistent with assumptions contained in the respective reserve assessments. The estimated well drilling and completion capital expenditure is based on the most recent Authorisations for Expenditures at each asset (as of 31 December 214). Operating expenditure for each asset is based on the most recent Lease Operating Statements for each asset (as of 31 December 214). Oil prices and gas prices are based on a NYMEX futures pricing scenario as set out in the table below. Pricing adjustments are made to these prices for individual assets to account for quality, transportation fees, marketing bonuses and regional price differentials. Year Oil (US$/bbl) Gas (US$/MMBtu) 215 $5. $6. $2.82 37