Lonestar Resources Jefferies Global Energy Conference. November 2013

Transcription

1 Lonestar Resources Jefferies Global Energy Conference November 2013

2 Disclaimer and Forward Looking Statements Disclaimer This document has been prepared by Lonestar in connection with providing an overview to interested analysts / investors. 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 2001 (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, a conversion rate of 6,000 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 reliance on such statements. 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. 2

3 Lonestar Resources: Corporate Summary Share Price History LNR - Daily Share Price $0.300 $0.275 $0.250 $0.225 $0.200 $0.175 $0.150 $0.125 $0.100 $0.075 $0.050 $0.025 $0.000 Pro forma capital Structure ASX code Ordinary shares on issue Current share price (1 November 2013) Market Capitalization Net Debt Enterprise Value LNR 697m AUD$0.275 US$184 mm US$103 mm US$287 mm Major Shareholders Board of Directors EWPO 53.5% Lonestar Management 5.7% Wyllie Group Pty Ltd 5.7% Industry Funds Management 1.0% Contango Asset Management 1.0% Berkinfest SA 1.0% Craig Coleman Frank D. Bracken, III Bernard Lambilliotte Chris Rowland, PhD Robert Scott Chairman Managing Director Non-Executive Director Non-Executive Director Non-Executive Director 1. Source: IRESS. Company disclosure 2. Assumes AUD : USD exchange rate of

4 Significant Portfolio Focused On Unconventional Oil Merger between Lonestar and Amadeus completed January 2 nd, 2013 Amadeus- long-lived oil production, with free significant cash flow Lonestar s Eagle Ford Shale development program delivering fullyfunded production growth Demonstrating the ability to add meaningful Eagle Ford Shale assets- Pirate transaction pushes net leasehold towards 10,000 acres Geographic split of Proved reserves 1 Eagle Ford Shale 12.7 MMBOE Conventional 4.1 MMBOE BAKKEN-THREE FORKS Hydrocarbon split of Proved Reserves 1 Fort Worth Crude Oil & NGL s 14.1 MMBBLS EAGLE FORD SHALE LEGEND Unconventional Assets Natural Gas 16.3 Bcf Conventional Assets 1. Refer to the Reserves Information in the Appendix 4

5 Corporate Progress (To Date) At Merger 1 Today 2 Growth Total Company Proved Reserves (MMBOE) % NPV-10 (US$MM) $239.8 $ % Production (BOEPD) 2,604 4, % EBITDAX (Annualized) $31.2 $ % Borrowing Base (US$MM) $69.0 $ % Eagle Ford Shale Proved Reserves (MMBOE) % NPV-10 (US$MM) $131.7 $ % Production (BOEPD) 886 3, % Leasehold (net acres) 5,059 9, % Net Locations % 1. Reserves and PV-10 estimates are as of December 31, 2012, and Production, EBITDAX figures are for the month of January, Reserves and PV-10 estimates are as of June 30, 2013, and Production, EBITDAX figures are for the month of September, Refer to the Reserves Information in the Appendix 5

6 Management Team Background and Track Record

7 Management Team Biographies Frank D. Bracken, III Managing Director Chief Executive Officer Allen W. Paschal President Over 27 years experience in oil and gas finance Previously Managing Director at Jefferies & Co., Inc., 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 Co-founder of Lonestar Resources predecessor company Over 34 years experience in senior management positions Long track record of building / monetising companies in combination with major private investors / private equity Tom H. Olle Senior Vice President Operations Scott E. Sabatka Vice President Geosciences Doug W. Banister Chief Accounting Officer 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 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 (NASDAQ-listed company $1.2 billion market cap), Northern Region Geoscience Manager at Encore Acquisition Corp, and a Sr. Staff Geologist for Exxon 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 Joe Young Manager- Drilling & Completions Tracy Hindman Manager-Field Logistics Rod Hicks Manager Field Operations 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 Over 31 years of oil and gas service experience 16 years of turnkey drilling experience- Service Drilling, Southeast, LLC Most recently- General Manager- Gulf Coast Division of Unit Drilling Texas 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 7

8 ($mm) $400 $350 $300 $250 $200 $150 $100 $50 $0 Barnett EFS AMU A Track Record of Rapid Growth Lonestar has achieved rapid growth in terms of acreage position, reserves and production Net acreage 1P Reserves 1 60,000 50, Net Acres 40,000 30,000 20,000 10,000 1P Reserves (Mmboe) Dec-10 Dec-11 Dec-12 Today 0 Dec-10 Dec-11 Dec-12 Today Barnett Eagle Ford Conventional Bakken Eagle Ford Conventional Barnett 1P PV-10 2 EBITDA and Production Projections 1P PV-10 ($mm) $400 $350 $300 $250 $200 $150 $100 $50 $0 Dec-10 Dec-11 Dec-12 Today1P PV-10 Dec-10 Dec-11 Dec-12 Today Millions $160.0 $140.0 $120.0 $100.0 $80.0 $60.0 $40.0 $20.0 $ ,000 6,000 5,000 4,000 3,000 2,000 1,000 0 BOEPD Eagle Ford Conventional Barnett EBITDA High Production Low Production 1. Reserves as of June 30th Refer to the Reserves Information in the Appendix 8

9 Eagle Ford Shale Growth and Development Strategy

10 Eagle Ford Growth Strategy Lonestar Focuses On The Crude Oil Window In the Eagle Ford Shale Highest Margins Per BOE in the play Current Revenue Mix- 92% crude oil / 4% NGL s / 4% natural gas ~$82.80 per BOE 1 Extremely High EBITDA Margins- ~$72.50 per BOE 1 Operational Control with Low Completed Well Costs 100% Operated Leasehold with complete control over well costs and well timing Lonestar s recently completed wells range from $5.2 to $6.0 MM for 5,000 to 6,000 laterals Reduced mechanical risk vs. deeper, higher pressured Condensate Window Operating Team with Expertise and Focus Pioneered 500-foot well spacing All wells pad-drilled Zipper fracs Choke management Execution Plan- Drill Inventory Using Internally Generated Cash Lonestar has increased its lease inventory to 9,859 net acres = 75 net operated Eagle Ford Shale locations Lonestar plans to drill Eagle Ford Shale wells annually through 2016 Spend <$3 million annually on Drilling, Workovers and Recompletions to attempt to maintain production on Conventional Assets Execution of this plan would Increase EBITDAX from $63-75 mm in 2013 to $ mm in Strategic Plan- Increase Eagle Ford Leasehold Position To Extend And Accelerate Growth Focus On Acquiring Leasehold With Proven Offset Production Direct / Nearby Offset Wells with EUR s that Yield Corporate Hurdle Rate at Lonestar s Well Costs, as Drilled Achieve Upside to Hurdle Rates Through Optimization of Drilling, Completion & Production Techniques Consolidate Eagle Ford Positions Among Smaller Operators Farm-ins & Lease Purchases from Operators Too Small to Exploit Eagle Ford Purchases from Operators with Production, Leasehold who are Seeking Basin Exit 1 Results for three months ended September 30, Based on current drilling plans, subject to change 3 Refer to Forward Looking Statements and Assumptions information on page 2 of the Presentation 10

11 Eagle Ford Leasehold Position Gonzo Asherton Operator Lonestar Gross acres 711 Net acres 690 WI 97.0% Royalty 24.0 % Beall Ranch Operator Lonestar Gross acres 2,373 Net acres 2,318 WI 97.7% Royalty 25.0% Pirate Operator Lonestar Gross acres 3,525 Net acres 3,468 WI 98.4% Royalty 25.0 % Operator Lonestar Gross acres 3,383 Net acres 3,383 WI 100.0% Royalty 24.1 % 1. Refer to the Reserves Information in the Appendix 11

12 Eagle Ford Shale - Beall Ranch WI% 97.7% Leasehold and activity map Royalty% 25.0% How Acquired Operator Purchase of Working Interest Lonestar Resources, Inc. Gross Acres 2,373 Net Acres 2,318 Reserves 1 PV-10 1 Recent Production 3 Drilling Schedule 2 Comments 1P: 10.5 mmboe (86% liquids) 2P: 10.5mmboe 1P Reserves: US$ million Gross ~4,013 boepd from 15 wells Net ~2,941 boepd from 15 wells 20 drilling locations remaining 2013: 6 wells (now producing) 2014: 6 wells 2015: 6 wells Lonestar pioneered 500-foot spacing at Beall Ranch in February 2011 Pad drilling Zipper fracs 2013 capex per well- US$6.4 million (now actual) 1. Estimates from internal engineering, roll-forward of W.D. Von Gonten & Co., as of June 30, PV-10 is the net present value of future net revenue, after deductions for operating and capital expenses, production taxes, but before corporate income tax and corporate overheads, using a real, pre-tax discount rate of 10%. 2. Drilling schedule and estimates of capex per well based on current Lonestar estimates, which are subject to change in industry conditions. 3. Production rates for the month ended September,

13 Eagle Ford Shale - Beall Ranch Capital and Reserves Information- Per Well 1 Production Type Curve 1, 2 Capital Costs ($MM) Drilling $2.0 Completion $4.0 Total Completed Well Costs $6.0 Oil NGLs Gas Total Reserves MBO MBOE MMCFG MBOE Gross Net of Royalty Production (Boepd) Day Max Production Rates: Crude Oil bopd NGL's- 103 blpd Gas Mcfgpd Leasehold Map and Drilling Locations Months on Production Net Cash Flow Profile 1 UPDATE Cumulative Cash Flow ($MM) $14.0 $12.0 $10.0 $8.0 $6.0 $4.0 $2.0 $0.0 -$2.0 -$4.0 NPV10: $9.6mm -$ Months on Production 1. Internal estimates of capital costs. Reserve estimates, production type curves and net cash flow from W.D. Von Gonten & Co., as of December 31, 2012 for 5,000 lateral day max production rates for each hydrocarbon phase do not all occur simultaneously, as the Company s choke management practices intentionally delays peak gas production. 3. Refer to the Reserves Information in the Appendix 13

14 Eagle Ford Shale - Asherton Leasehold and activity map WI% 97.0% Royalty% 24.0% How Acquired Operator Purchased core acreage out of bankruptcy, added on additional acreage through primary lease Lonestar Resources, Inc. Gross Acres 711 Net Acres 690 Reserves 1 PV-10 1, 3 Recent Production Drilling Schedule 2 Comments 2 1P: 2.2 mmboe (81% liquids) 2P: 2.8 mmboe 1P Reserves- US$45.2 million 2P Reserves- US $52.5 million 416 BOEPD in 3Q13 8 drilling locations remaining 2013: 2 wells 2014: 2 wells 2015: 2 wells Excellent access to roads, pipelines Anadarko and Chesapeake are actively permitting and drilling offsets to the south and east Recent wells completed for US$5.5 million 1. Reserves are from W.D. Von Gonten & Co. engineering estimates, as of June 30, Drilling schedule and capex per well based on current Lonestar estimates, which are subject to change in industry conditions. 3. Refer to the Reserves Information in the Appendix 14

15 Eagle Ford Shale - Asherton Capital and Reserves Information- Per Well 1 Capital Costs ($MM) Drilling $1.7 Completion $3.8 Total Completed Well Costs $5.5 Oil NGLs Gas Total Reserves MBO MBOE MMCFG MBOE Gross Net of Royalty Production Type Curve 1,2 Production (Boepd) Day Max Production Rates: Crude Oil- 287 bopd NGL's- 101 blpd Gas Mcfgpd 0 Leasehold Map and Drilling Locations Months on Production Net Cash Flow Profile 1 #2H-N Cumulative Cash Flow ($MM) $10.0 $8.0 $6.0 $4.0 $2.0 $0.0 -$2.0 -$4.0 NPV10: $6.2mm -$ Months on Production #6H-S 1. Internal estimates of capital costs. Reserves estimates, production type curves and net cash flow are from W.D Von Gonten & Co., as of June 30, day max production rates do not all occur simultaneously, as the Company s choke management practices intentionally delays peak gas production. 15

16 Eagle Ford Shale - Gonzo WI% 100.0% Leasehold and activity map Royalty% 24.1% How Acquired Operator Primary Term Leases, Acquisitions, Top Leases Lonestar Resources, Inc. Gross Acres 3,383 Net Acres 3,383 Reserves Expected to be submitted at fiscal year end 2013 PV-10 1 Expected bookings in 2013 Recent Production >700 BOEPD (recent) Drilling 21 to 28 drilling locations remaining (1,000 to 700 ) Schedule : 2 wells (now producing) 2014: 4 wells 2015: 6 wells Comments 1 Acquired in multiple transactions with original leases on primary terms. Offset by Forest Oil s Holmes #1H (30-day IP > 500 bopd, 114,000 bbls produced to date) Forest s type curve is 300,000 boe per well Gonzo A-3H & B-1H drilled, completed & fracked Currently optimizing pump rates Internal estimate of capex per well US$5.5 million 1. Drilling schedule and capex per well based on current Lonestar estimates, which are subject to change in industry conditions. 16

17 Gonzo 1-Well Sensitivity Analysis 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% IIRR % IRR% Analysis $5.00 $5.25 $5.50 $5.75 $6.00 Completed Well Cost (US$MM) 500 bbl IP 400 bbl IP 300 bbl IP IRR% Matrix Capex ($MM) 500 bopd IP 400 bopd IP 300 bopd IP $ % 61.6% 35.9% $ % 53.2% 30.6% $ % 46.1% 26.2% $ % 40.2% 22.5% $ % 35.1% 19.4% Oil EUR: PV-10 ($mm) $5.0 $4.5 $4.0 $3.5 $3.0 $2.5 $2.0 $1.5 $1.0 $0.5 $0.0 PV-10 Analysis $5.00 $5.25 $5.50 $5.75 $6.00 Completed Well Cost (US$MM) 500 bbl IP 400 bbl IP 300 bbl IP PV-10 Matrix Capex ($MM) 500 bopd IP 400 bopd IP 300 bopd IP $5.00 $4.7 $3.5 $2.1 $5.25 $4.4 $3.2 $1.8 $5.50 $4.2 $3.0 $1.6 $5.75 $3.9 $2.7 $1.3 $6.00 $3.7 $2.5 $1.1 17

18 Eagle Ford Shale- Pirate Offset Operator IP s Wilson / Karnes County Locator Map P. Moczygemba B #1H Warnken #1H Max 30 Oil Max 30 Gas Max 30 BOE 526 bopd 169 Mcfgpd 554 BOEPD Max 30 Oil Max 30 Gas Max 30 BOE 427 bopd 226 Mcfgpd 464 BOEPD P. Moczygemba #1H Max 30 Oil Max 30 Gas Max 30 BOE 445 bopd 233 Mcfgpd 483 BOEPD Warnken C#1H Max 30 Oil Max 30 Gas Max 30 BOE 675 bopd 215 Mcfgpd 710 BOEPD Yosko B#1H Max 30 Oil Max 30 Gas Max 30 BOE 603 bopd 336 Mcfgpd 659 BOEPD Dunn #1H Max 30 Oil Max 30 Gas Max 30 BOE 658 bopd 349 Mcfgpd 716 BOEPD Source: Drilling Info 18

19 Eagle Ford Shale Pirate WI% 98.4% Leasehold and activity map Royalty% 25.0% Operator Lonestar Resources Gross Acres 3,525 Net Acres 3,468 Reserves 1 Initial bookings likely at year-end 2013 PV-10 1 Initial bookings likely at year-end 2013 Recent Production No current Eagle Ford Shale production on tracts Drilling Schedule Comments 20 total drilling locations 2013: 2 wells 2014: 2 wells 2015: 4 wells Acquired via combination of farm-in and primary term leases Hunt Oil wells in immediate area have generated Max- 30 IP s of 464 to 716 BOEPD. Beach head in an area with several thousand acres which may also be acquirable 1. Internal estimates of capital costs. Reserve estimates, production type curves and net cash flow are from internal engineering estimates for the Company s average lateral length of 6,000 feet 19

20 Eagle Ford Shale Pirate Capital and Reserves Information- Per Well 1 Production Type Curve 1, 2 Capital Costs ($MM) Drilling $2.6 Completion $3.6 Total Completed Well Costs $6.2 Oil NGLs Gas Total Reserves MBO MBOE MMCFG MBOE Gross Net of Royalty Leasehold Map and Drilling Locations Production (Boepd) Day Max Production Rates: Oil Bopd NGL's - 11 Blpd Dry Gas - 87 Mcfgpd Months on Production Net Cash Flow Profile 1 Cumulative Cash Flow ($MM) $6.0 $4.0 $2.0 $0.0 -$2.0 -$4.0 -$6.0 NPV10: $4.0mm -$ Months on Production 1. Internal estimates of capital costs. Reserve estimates, production type curves and net cash flow are from internal engineering estimates for the Company s average lateral length of 6,000 feet 20

21 Eagle Ford Shale Drilling- Engine For Growth 1 8, , Production (BOEPD) 6,000 5,000 4,000 3,000 2,000 1, Net Eagle Ford Producers 0 0 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Jan-14 Mar-14 May-14 Jul-14 Sep-14 Nov-14 Jan-15 Mar-15 May-15 Jul-15 Sep-15 Nov-15 Eagle Ford Shale Conventional Barnett Shale Net Eagle Ford Producers 1. Drilling schedule and capex per well based on current Lonestar estimates, which are subject to change in industry conditions. 21

22 Conventional Assets Stability & Free Cash Flow

23 Conventional Assets 4.1 MMBOE- Proved Reserves 79% Crude Oil 24% of Lonestar s Total Proved Reserves 734 BOEPD- 3Q13 Production 72% Crude Oil & NGL s 25% of Lonestar s Total Production Long-Lived Reserves with Low Capital Requirements Reserves/Production ratio of 13.4 years Current Capital Plans <$3 MM annually West Texas North Texas East Texas 1, South Texas Net Production (BOEPD) North Texas West Texas East Texas South Texas Other 1. Refer to the Reserves Information in the Appendix 23

24 Bakken-Three Forks Growth and Development Strategy

25 Bakken/Three Forks - West Poplar Daniels Sheridan Divide Burke Williston Basin renowned for highly successful Bakken / Three Forks play Historical industry activity concentrated on oil in acreage to south of the Brockton-Froid fault Lonestar adopted contrarian approach by acquiring West Poplar with 50,000 acres in Roosevelt County, to the north of Brockton- Froid fault Industry group-think has been that Bakken was cooked west of Brockton-Froid Fault Acreage selected due to its proximity to the Poplar Dome, which should provide enhanced fracturing in the target zones FORT PECK RESERVATION Roosevelt West Poplar Project POPLAR DOME Richland Williams Mackenzie Billings NESSON ANTICLINE Mountrail PARSHALL FIELD Dunn Multiple conventional targets are productive in the area (Charles, Amsden, Nisku, etc.) 25

26 Bakken/Three Forks - West Poplar June 2011 Lonestar and its partners drilled the Clark Farms #29-10 in July, 2012 as a vertical completion Encountered three prospective non-conventional zones which comprise a 120 to 150 horizontal drilling target 50,192 gross acres Tested light crude oil from: Lower Lodgepole ( 43.3 API) Bakken ( 41.2 API) Three Forks (45.8 API) POPLAR DOME Established Bakken peak oil generation on the Project, which positively contrasts with offset well data Ro Tmax: 457o 26

27 Bakken/Three Forks - West Poplar Since this well test, nearly 1 million new acres have been leased north of the Brockton-Froid fault, suggesting validation of the West Poplar potential July 2012 Lonestar is currently seeking to improve the value of this project, pre-drill Archeological studies completed EA approval now in hand (FONSI) 3-D seismic survey test lines have been shot, data acquisition expected to commence shortly 50,192 gross acres 27

28 Summary of Investment Considerations A Significant New Oil & Gas Company Listed on The ASX Merger of Lonestar Resources and Amadeus Energy, Ltd completed January 2nd, 2013 Market capitalization of $184 million 1 Total Enterprise Value of $287 million 1 With A Robust Asset Value Underpinned By Proved Reserves Proved reserves of 16.8 MMBOE 2 Proved PV-10 of $365.6 million 2 CY12 EBITDAX of US$25 million 3, CY13 EBITDAX of US$63-$75 million 3 Significant, Self-funded, Organic Growth In Production & Cash Flow From Existing Assets ~75 net horizontal drilling locations in inventory in Eagle Ford Shale planned for drilling over next 4 to 5 years Gonzo and Pirate have potential to yield substantial increase in oil reserves in CY13-CY14 U.S.-based management team with significant operating experience and a track record of growth Management s members have track records of growth in value and liquidity events at successful U.S. publicly traded Energy companies Have more than doubled reserves and more than tripled PV-10 in less than two years. Focus on Increasing Leasehold In the Eagle Ford Shale Crude Oil Window Fully integrated operating team with high-margin Crude Oil Window expertise Evaluating several additional leasehold opportunities in the Eagle Ford Shale 1. Assumes current share price of A$0.275 applied to 697m shares. Refer to the Reserves Information in the Appendix 2. As at June 30, PV-10 is net present value of future net revenue, after deductions for operating and capital expenses, production taxes and ad valorem taxes, but before corporate income tax and corporate overheads, using a real, pre-tax discount rate of 10%. 3. See Appendix for assumptions 28

29 Metrics & Valuation Lonestar Resources, Ltd. (LNR: ASX)

30 A Non-Conventional Oil Company of Significant Scale Net 1P Reserves 1 (mmboe) Net Production 2 (boepd) Aurora Oil & Gas Aurora Oil & Gas Lonestar Resources Sundance Energy Antares Energy Lonestar Resources Sundance Energy Red Fork Energy Red Fork Energy Empire Energy Empire Energy Antares Energy AusTex Oil AusTex Oil Samson Oil & Gas Samson Oil & Gas ,000 10,000 15, Unless otherwise stated, it has been assumed that the attributable reserves, as quoted in the companies' announcements, are net of royalties. 2. Average net daily production over the September 2013 quarter. Source: Company announcements. 30

31 Attractive Valuation Relative to ASX-Listed Peers Enterprise Value 1 / 1P Reserves 2 (A$/BOE) Enterprise Value 1 / 2P Reserves 2 (A$/BOE) Samson Oil & Gas Sundance Aurora Oil Lonestar Red Fork Antares Empire AusTex Oil Aurora Oil Samson Oil Sundance 3 3 Energy & Gas Resources Energy Energy Energy & Gas & Gas Energy Lonestar Resources Red Fork Energy Empire Energy AusTex Oil Antares Energy 1. Lonestar Enterprise Value is calculated on a $0.275 / share price and 697.2m shares. All companies Enterprise Values are calculated on a diluted basis (assuming exercise of in-the-money options) and based on net debt including hedging, value of marketable securities and cash from exercise of in the money options. Net debt is calculated on latest company announcements available. 2. Unless otherwise stated, it has been assumed that the attributable reserves, as quoted in the companies' announcements, are net of royalties. 3. Does not consider the sale of Williston Basin Phoenix Prospect which was announced on October 31, Source: Bloomberg as at November 1, 2013, company announcements. 31

32 Attractive Valuation Relative to ASX-Listed Peers Enterprise Value 1 / Production 3 (A$/BOED) Enterprise Value 1 / CY13F EBITDA 2 (x) 250, x 9.0x 7.6x 148, , x 128, , , x 54,377 42,711 Samson Oil & Gas Antares Energy Red Fork Energy Aurora Oil & Gas Sundance 4 Energy Lonestar AusTex Oil Resources Empire Energy Antares Energy 4 Sundance Energy Red Fork Energy Aurora Oil & Gas Lonestar Resources 1. Lonestar Enterprise Value is calculated on a $0.275 / share price and 697.2m shares. All companies Enterprise Values are calculated on a diluted basis (assuming exercise of in-the-money options) and based on net debt including hedging, value of marketable securities and cash from exercise of in the money options. Net debt is calculated on latest company announcements available. 2. Lonestar CY13 EBITDA based on mid-point of estimate range. Aurora, Sundance and Antares CY13EBITDA forecasts based on Bloomberg consensus estimates for CY13. Red Fork CY13 EBITDA estimated by taking 50% of the sum of FY13 and FY14 Bloomberg consensus estimates. 3. Average net daily production over the September 2013 quarter. 4. Does not consider the sale of Williston Basin Phoenix Prospect which was announced on October 31, Source: Bloomberg as at November 1, 2013, company announcements. 32

33 Attractive Valuation Relative to ASX-Listed Peers Enterprise Value 1 / 1P Reserves PV-10 2 (x) Enterprise Value 1 / 2P Reserves PV-10 2 (x) Aurora Oil & Gas Sundance Samson Oil Antares Red Fork Lonestar Empire AusTex Oil Aurora Oil Sundance 3 3 Energy & Gas Energy Energy Resources Energy & Gas Energy Red Fork Energy Samson Oil & Gas Lonestar Resources Antares Energy Empire Energy AusTex Oil 1. Lonestar Enterprise Value is calculated on a $0.275 / share price and 697.2m shares. All companies Enterprise Values are calculated on a diluted basis (assuming exercise of in-the-money options) and based on net debt including hedging, value of marketable securities and cash from exercise of in the money options. Net debt is calculated on latest company announcements available. 2. Unless otherwise stated, it has been assumed that the attributable reserves PV-10s, as quoted in the companies' announcements, are net of royalties. 3. Does not consider the sale of Williston Basin Phoenix Prospect which was announced on October 31, Source: Bloomberg as at November 1, 2013, company announcements. 33

34 Appendix

35 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. 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

36 Footnotes In accordance with Chapter 5 of the Listing Rules, please be advised that: Lonestar's Proved 1P reserves are estimated in accordance with the Society of Petroleum Engineers - Petroleum Resource Management System (SPE-PRMS). The Company's Proved (1P) reserves on its Proved reserve regions have been estimated as follows: Eagle Ford Shale - Asherton Project The Proved (1P) reserves on the Asherton Project have been independently estimated as at June 30, 2013, by William D. Von Gonten, Jr.,P.E., and Taylor D. Matthes of W. D. Van Gonten & Co. Eagle Ford Shale - Beall Ranch The Proved (1P) reserves on the Beall Ranch Project were independently estimated as at December 31, 2012, by William D. Von Gonten, Jr.,P.E., and Taylor D. Matthes of W. D. Van Gonten & Co. As outlined on page 1, given there was no significant completion activity on the Beall Ranch project in the 6 months to June 30, 2013, the report was updated by Mr. Tom Olle, the Company s Senior Petroleum Engineer to roll it forward to an effective date of June 30, Conventional - Texas, Oklahoma and Louisiana The Proved (1P) reserves on the Conventional Properties in Texas, Oklahoma and Louisiana were independently estimated as at December 31, 2012, by William M. Kaman of La Roche Petroleum Consultants, Ltd. This report was updated for recent production history and rolled forward to the effective date of June 30, 2013 by Mr. Tom Olle, the Company s Senior Petroleum Engineer. Mr. Tom Olle, the Company's Senior Petroleum Engineer, performed the roll-forward calculations outlined above. Mr. Olle is a Petroleum Engineer and a member of the Society of Petroleum Engineers with over 36 years experience. W. D. Van Gonten & Co. and La Roche Petroleum Consultants, Ltd. are petroleum engineering firms that are certified by the Society of Petroleum Engineers and using the SPE - Petroleum Resource Management System. In accordance with Listing Rule 5.13, each person above has consented to the inclusion of the information in the form and context in which is appears. 36

37 Reserves, PV-10 and EBITDA Assumptions Lonestar s Proved and Probable reserves and PV10 estimates have been estimated based upon the following assumptions: Detail of field by field estimates of production, operating costs, capital costs, timing, analysis of production profiles, depletion statistics, log characteristics and other technical data for the recompletion, maintenance and workovers of existing wells, the drilling of new development wells and the extension drilling on the acreage positions held by Lonestar. 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) 2013 $96.37 $ $90.85 $ $86.08 $ $83.02 $ $80.94 $ $79.32 $ $78.17 $ $77.39 $ $77.00 $5.92 Thereafter Flat Flat The assumptions upon which Lonestar s Proved and Probable reserves and PV10 estimates have been estimated based upon the following assumptions: 500 foot spacing on Beall Ranch for a total of 33 wells (9 producing, 24 to be developed) and 500 spacing on Asherton for a total of 10 wells (none producing, 10 to be developed) Single well capex of US$6.6million for Beall Ranch and US$5.5 million for Asherton Oil prices and gas prices are based on a NYMEX futures pricing scenario as set out in the table above. Pricing adjustments are made to these prices for individual assets to account for quality, transportation fees, marketing bonuses and regional price differentials. Pro-forma CY12 and CY13 EBITDA estimates are based on the following assumptions: Production estimates as set out in this presentation. Oil prices and gas prices are based on a NYMEX futures pricing scenario as set out in the table below. Pricing adjustments are made to these prices for individual assets to account for quality, transportation fees, marketing bonuses and regional price differentials. Year Oil (US$/bbl) Gas (US$/MMBtu) 2013 $96.93 $ $94.19 $3.99 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 30 September 2013). Operating expenditure for each asset is based on the most recent Lease Operating Statements for each asset (as of 30 September 2013). 37