Lonestar Resources Investor Presentation- March...

Lonestar ResourcesUpdate to Investors

March, 2014

2

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.

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 berelied 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 orcompleteness 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 andliability is expressly disclaimed by Lonestar and its respective affiliates, subsidiaries, directors, agents, officers, advisers and employees for any errors, misstatements, misrepresentations in or omissions fromthis 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 productadvice, 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 inrespect 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 shouldbe 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 ofnatural 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 representvalue 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 forward‐looking 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 toexpectations, projections or other characterizations of future events or circumstances are forward‐looking statements. Statements relating to “reserves” are deemed to be forward‐looking statements asthey 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 factsbut 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 ofmanagement 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 inthe 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, actualresults 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 notlimited 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 andLonestar 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.

3

Lonestar Resources: Corporate Snapshot

ASX code LNR

Ordinary shares on issue * 752m

Current share price (27 February 2014) AUD$0.27

Market Capitalization US$182 mm

Net Debt (proforma Acquisition) US$179 mm

Enterprise Value US$361mm

Capital Structure

Corporate History Share Price History

*Assumes issuance of Deferred Consideration Shares related to Amadeus merger. Refer to Company announcements in connection with the merger transaction for further information.

$0.000$0.025$0.050$0.075$0.100$0.125$0.150$0.175$0.200$0.225$0.250$0.275$0.300$0.325

LNR ‐D

aily Share Price

Jun. 2010‐ Company was founded by Ecofin, Ltd.

Jan. 2012‐ Current Executive Management Team put in place, corporate strategy focused on building in‐house staff, with a drilling and acquisition program focused on Eagle Ford Shale trend.

Jan. 2013‐ Lonestar merged with Amadeus Energy, Ltd., creating a publicly‐traded vehicle on the Australian Stock Exchange (ASX)

Dec. 2013‐ In 2 years, Lonestar reaches ~10,000 net acres in the Eagle Ford Shale trend, boosting Proved Reserves 168% and SEC‐PV10 by 277%

Feb. 2014‐ Lonestar acquires Eagle Ford Shale trend assets, increasing net leasehold to >23,000 acres

EWPO 55.5%

Lonestar Management 5.9%

Wyllie Group Pty Ltd 5.3%

Adam Smith Asset Management 1.2%

Colonial First State Global AM 1.0%

Industry Funds Management 1.0%

Major Shareholders

4

Lonestar’s Track Record of Rapid Growth

Proved Reserves1

EBITDAX

Net Acreage‐ Eagle Ford Shale Trend

Proved PV‐102

$0

$50

$100

$150

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Dec ‐10 Dec‐1 1 Dec‐12 Today

1P PV10 ($mm)

Ba rnett EFSA MU

0

5,000

10,000

15,000

20,000

25,000

Dec-11 Dec-12 Dec-13 Today

Net

Acr

es

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1P R

eser

ves

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BOE)

Eagle Ford Conventional Barnett

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V-10

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Annu

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EBI

TDA

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Qua

rterly

EBI

TDA

($US

MM

)

5

Lonestar’s Business Philosophy

Build an Eagle Ford Shale Leasehold of Consequence‐ +400% in The Last 12 Months

Mitigate Risk Lonestar seeks to only acquire acreage immediately offsetting wells with demonstrated productivity and declines

Whatever It Takes Lonestar has used a Variety of Techniques to Aggregate its 23,079 net acre Eagle Ford Position

Primary Term Leases Beall Ranch, Gonzo, Pirate, 2014 Acquisition

Bankruptcies Asherton

Conservatively Manage Our Financial Position

Limit Leverage Target Incurred Net Debt at a Ceiling of 3.0x LTM EBITDAX

Maintain Flexibility Goal of 2.0x Net Debt / NTM EBITDAX‐ Provides Liquidity for Both Drilling Acceleration and Capacity for Acquisitions

Hedge Oil Price Risk Lock in Cash Flow and Returns‐ Current Oil Production Hedged 85% in 2014, 53% in 2015, 37% in 2016

Top Leasing

Property Purchases

Gonzo, 2014 Acquisition

Beall Ranch, 2014 Acquisition

Lonestar is Highly Focused on the Crude Window of the Eagle Ford Shale trend

Depths Lonestar’s position lies between 6,500’ and 8,000’

High Cash Margins Lonestar’s Cash Margins per BOE averaged $66.43 in 2013, which it considers among the highest in the Eagle Ford

Longer Laterals Wherever Lease geometry allows, Lonestar has been increasing Laterals from 5,000’ towards 7,500’

Low Well Costs Lonestar’s Completed Well Costs have ranged from $4.9 MM to $7.0 MM

Mitigate Risk

Whatever It Takes

Limit Leverage

6

Lonestar’s Operating Strategy

Maximize Control Through Operations

Aim to Operate 100% of Wells to Control Method of Completions, Costs & Flowback

Control Pace of Capital Spending When ~100% of Properties are Operated, Lonestar Can Control Its Pace of Spending

“Leading Edge, Not Bleeding Edge”

Get Spacing Right Early

Infill Drilling Hurts Recoveries & Returns. Lonestar drilled the first 500’‐spaced wells in the Eagle Ford Shale trend in Feb ‘11

Be Efficient All of Lonestar’s Wells Have Been Pad Drilled to Cut Costs. All of Lonestar’s Wells have Been Zipper Fracked or Batch Fracked

Soak Time Equalizes near wellbore pressures, allows fines to stabilize, reduces water recovery

Maximize Fracs Zipper fracs, Proppant / ft > 1,500#, Large‐Mesh Proppant, Non‐Geometric Perforations

Drill, Review and Optimize

Review Operated Production Results (and offset operators), then Modify Drilling, Completion & Flowback Procedures

Harvest After Optimizing Practices, Accelerate Development Program

Choke Management

3‐D Seismic

Improves fracture conductivity, depletes reservoir more normally, reduces gas breakout

Employ where available to optimize lateral placement in most productive rock in the Eagle Ford Shale section

Returns, Not Press Releases Focus on Maximizing EUR’s and IRR’s, Not IP Rates for Press Releases

Control Completions &

Costs

Drill Early Drill Initial Wells within 6 Months of Closing, to Enhance Present Value / IRR’s

Appraise &Improve

7

Recent Acquisitions Expand Eagle Ford Trend Acreage

Western Eagle Ford

Central Eagle Ford

Eastern Eagle Ford

Eagle Ford Shale Trend

Lonestar Acreage

Acquired Acreage

Legend

Acquired Today

Net Acres 13,156 23,079

Engineered Locations 56 136

Avg. W.I. 91.1% 95.6%

Proved Reserves (MMBOE)

7.4 21.8

Proved & Probable Reserves (MMBOE)

10.6 32.2

Acquired Today

Net Acres 4,001 7,073


Avg. W.I. 66.7% 88.3%

Proved Reserves(MMBOE)

2.0 15.2


2.7 16.6

Acquired Today

Net Acres 4,133 10,984


Avg. W.I. 94.7% 98.4%


3.3 4.5


5.0 12.7Acquired Today

Net Acres 5,022 5,022


Avg. W.I. 100.0% 100.0%


2.1 2.1


3.0 3.0

8

LONESTAR ACQUIRED PROFORMA INCREASE

EAGLE FORD SHALE TREND ACREAGEGross Acres‐ Eagle Ford Shale Trend 10,632 15,232 25,864 143%Net Acres‐ Eagle Ford Shale Trend 9,923 13,156 23,079 133%Net Acres‐ Held By Production 5,865 8,467 14,331 144%"Engineered Acreage" 9,923 7,648 17,571 77%"Upside Acreage" 0 5,508 5,508

RESERVES (MMBOE)Proved Developed Producing 8.1 1.0 9.1 13%Proved Developed Non Producing 0.2 0.0 0.2 0%Proved Undeveloped 10.0 6.3 16.3 63%PROVED 18.2 7.4 25.6 40%Probable 7.2 3.3 10.4 46%

PROVED & PROBABLE 25.4 10.6 36.0 42%

Possible 0.0 4.8 4.8 N/MPROVED, PROBABLE & POSSIBLE 25.4 15.4 40.8 61%

SEC PV‐10 ($MM)Proved Developed Producing $244.6 $38.4 $283.0 16%Proved Developed Non Producing $3.7 $0.0 $3.7 0%Proved Undeveloped $179.8 $99.9 $279.7 56%PROVED $428.1 $138.3 $566.4 32%

Probable $62.7 $49.0 $111.7 78%

PROVED & PROBABLE $490.8 $187.3 $678.1 38%

Possible $0.0 $94.7 $94.7 N/M

PROVED, PROBABLE & POSSIBLE $490.8 $282.0 $772.8 57%

Lonestar Resources ‐ Impact of Acquisition

• Increases Net Eagle Ford trend leasehold by 143%

• Acquired Acreage is 64% HBP’d, 2014 Drilling expected to increase HBP percentage to ~90%

Provides Scale & Portfolio

Diversification

• Increases Proved & Probable reserves by 42%

• Acquisition is 94% Crude Oil & NGL’s

• Lonestar’s current drilling plans target several Possible locations, which it rates among the highest IRR’s in its portfolio

Boosts Total Reserves by 61%

• After debt incurred to purchase, Acquisition adds $116.3MM of 2P PV‐10, or $0.15 per Lonestar share

• If Possibles are considered, acquisition would add $211.0 MM of PV‐10, or $0.28 per Lonestar share

Highly Accretiveper Lonestar

Share

9

Recent Acquisition‐ Evaluation of Accretion

SEC PV‐10 Per Share‐ Lonestar SEC PV‐10 Per Share‐ Proforma

Note- All calculations of PV-10 are internal, and based on SEC Pricing, Share price in $AUD

Debt$0

$100

$200

$300

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$800

TEV PV‐10

SEC‐PV

10 (U

S$MM)

Proved P + P

$0

$100

$200

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$500

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$700

$800

TEV PV‐10

SEC PV

‐10 (US$MM)

Proved P + P

$0.27per share

A$0.47per share

$0.27 per share

A$0.57per share

Net Debt

Net Debt

Mkt.Cap.

Mkt.Cap.

Management TeamBackground and Track Record

11

Frank D. Bracken, IIIManaging DirectorChief Executive Officer

Over 28 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

Tom H. OlleSenior Vice President –Operations

Over 37 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

Doug W. BanisterChief Financial Officer

CPA with 29 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

Scott E. SabatkaVice President – Geosciences

Over 35 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

Allen W. PaschalSenior Vice President‐Land & Administration

Co‐founder of Lonestar Resources’ predecessor company Over 35 years experience in senior management positions Long track record of building / monetising companies in combination with major private investors / private equity

Joe YoungManager‐ Drilling & Completions

Engineer with 14 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 HindmanManager‐Field Logistics

Over 32 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

Rod HicksManager – Field Operations

Over 34 years of oil and gas drilling, completion and operations experience Held positions of increasing responsibility at Kerr‐McGee, Encore Acquisition Corp, and Quantum Resources

Management Team Biographies

Eagle Ford ShaleGrowth and Development Plan

13

Recent Acquisitions Expand Eagle Ford Trend Acreage

Western Eagle Ford

Central Eagle Ford

Eastern Eagle Ford

Eagle Ford Shale Trend

Lonestar Acreage

Acquired Acreage

Legend

Acquired Today

Gross Acres 15,232 25,864

Net Acres 13,156 23,079

Net Acres‐ HBP 8,467 14,331

Avg. W.I. 91.1% 95.6%

Avg. Royalty 20.8% 23.5%

Acquired Today


Net Acres 4,001 7,073


Avg. W.I. 66.7% 88.3%


Acquired Today


Net Acres 4,133 10,984


Avg. W.I. 94.7% 98.4%


Acquired Today


Net Acres 5,022 5,022


Avg. W.I. 100.0% 100.0%


14

Eagle Ford Shale – Western Region

Western Eagle FordGross / Net Acres 8,565 / 7,073Net Acres HBP 7,073 Avg. WI / Avg. Royalty 88.3% / 23.9%Eagle Ford Depth 6,500’ to 8,000’Well Cost $4.9 to $7.0 MMLateral Lengths 3,900’ to 7,000’Reserves Per Well 391,000 to 572,000 BOE4Q2013 Production 2,845 BOEPD (71% oil)Eagle Ford Producers 19 gross/ 18 netProved Locations 38 gross/ 36 netProbable & Possible Locations 10 gross/7 net

Ranger Beall Ranch

Asherton

Burns Ranch Area

LEGENDEngineered Acreage

Upside Acreage

Producing EF Well

Permitted EF Well

30 Day Max Rate300

15

Net Acres / HBP 2,318 / 2,318

W.I. / Royalty% 97.7% / 25.0%

Operator Lonestar Resources, Inc.

Top EFS 7,700’

Well Costs $4.9 to $6.0 MM

Lateral Length 3,900’ to 7,000’

Assumed Spacing 500‐foot

Reserves Per Well 399,000 to 572,000 BOE (78% liquids)

RecentProduction 1

Gross ~3,248 boepd from 15 wells Net ~2,380 boepd from 15 wells

EngineeredLocations

20 drilling locations remaining‒ Proved: 20‒ Probable & Possible: 0

Comments Lonestar pioneered 500‐foot spacing at Beall Ranch in February 2011

All wells pad drilled 14 of 15 wells zipper fracked 2013 capex per well‐US$6.3 million (now

actual)


Ranger Beall Ranch

Beall Ranch #19H605 BOEPD


Upside Acreage

Producing EF Well

Permitted EF Well

30 Day Max Rate300

Ritchie Farms#25H903 BOEPD

Arena Roja #4H741 BOEPD

ARZ Unit #G3H300 BOEPD

1 Recent production from 4Q2013

16

Net Acres / HBP 690 / 690

W.I. / Royalty% 97.0% / 24.6%


Top EFS 6,500’

Well Costs $5.5 MM



Reserves Per Well 423,000 BOE (72% liquids)

RecentProduction 1

Gross ~474 boepd from 2 wells Net ~347 boepd from 2 wells

Engineered Locations


Comments Acquired property in May, 2012 Completed initial wells in 1Q13 All wells pad drilled Set single‐bit trip record for Eagle Ford Shale Soak‐time and Choke management 2014 Drilling plans‐ 2 wells (waiting on frac)


Asherton

McCain #1H477 BOEPD

Towers #A1H526 BOEPD

CMWW #B1H465 BOEPD

CMWW #A1H736 BOEPD

Asherton #6HN459 BOEPD


Upside Acreage

Producing EF Well

Permitted EF Well

30 Day Max Rate300

1 Recent production from 4Q2013

17

Net Acres / HBP 4,001 / 4,001

W.I. / Royalty% 66.7% / 21.6%


Top EFS 8,000’

Well Costs $6.0 MM to $7.0 MM




RecentProduction 3 None

Drilling Locations 2


Comments Acquired property in January, 2014 Currently evaluating tack‐on acquisitions

to cheaply expand inventory 1,000 HBP acres can add locations via

pooling 2,361 acres in Frio County prospective for

Buda 2014 Drilling plans‐ 2 wells


Burns Ranch Area

Burns Ranch I #B1H526 BOEPD

Burns Ranch IV #G1H464 BOEPD

Gray Unit I #A1H390 BOEPD

Wilson #F6H393 BOEPD


Upside Acreage

Producing EF Well

Permitted EF Well

30 Day Max Rate300

18

Eagle Ford Shale – Central Region

Pirate Area

Gonzo Area


Upside Acreage

Producing EF Well

Permitted EF Well

30 Day Max Rate300

Central Eagle FordGross / Net Acres 11,041 / 10,984Net Acres HBP 3,888 Avg. WI / Avg. Royalty 98.4% / 24.2%Eagle Ford Depth 6,700’ to 7,900’Well Cost $5.9 to $7.0 MMLateral Lengths 5,000’ to 7,000’Reserves Per Well 249,000 to 344,000 BOE4Q2013 Production 520 BOEPD (99% oil)Eagle Ford Producers 6 gross/ 6 netProved Locations 17 gross/ 17 netProbable & Possible Locations 46 gross/46 net

19

Net Acres / HBP 7,658 / 2,793

W.I. / Royalty% 97.6% / 22.8%


Top EFS 7,900’





RecentProduction 3

Gross: 337 boepd from 4 wells Net: 270 boepd from 4 wells

Drilling Locations 2 Engineered Drilling Locations: 40 ‒ Proved: 14‒ Probable & Possible: 26

Comments Acquired October, 2013 to February, 2014 Hunt has completed 33 wells offsetting

Pirate Current production from Hunt wells totals Lonestar has purchased 3‐D to optimize

lateral location within high resistivity pay 2014 Drilling plans‐ 4 wells (2 in progress)


Pirate Area

Warnken #1H464 BOEPD

Yosko #1H659 BOEPD

Dunn #1H716 BOEPD

Warnken C #1H710 BOEPD

Moczygemba #B1H554 BOEPD

Moczygemba #1H483 BOEPD


Upside Acreage

Producing EF Well

Permitted EF Well

30 Day Max Rate300

20

Net Acres / HBP 3,383 / 1,096

W.I. / Royalty% 100.0% / 25.0%


Top EFS 6,600’ to 6,900’


Lateral Length 6,000’ to 7,000


Reserves Per Well 249,000 BOE (92% liquids)

RecentProduction 3



Comments Initially acquired 2011 Offsets Forest Oil’s core development with

Schlumberger Lonestar re‐evaluating lateral location within

Eagle Ford / Chalk section 2014 Drilling plans‐ 2 to 4 wells (permitted) Additional Comments


Gonzo Area

Holmes #1H505 BOEPD


Upside Acreage

Producing EF Well

Permitted EF Well

30 Day Max Rate300

B.Manford #1H566 BOEPD

Colwell Cook #1H465 BOEPD

Moos Cook #1H508 BOEPD

T.Lawley#1H466 BOEPD

21

Eagle Ford Shale – Eastern Region

El Halcon Area


Upside Acreage

Producing EF Well

Permitted EF Well

30 Day Max Rate300

Eastern Eagle FordGross / Net Acres 6,257 / 5,022Net Acres HBP 3,370 Avg. WI / Avg. Royalty 100% / 20.9%Eagle Ford Depth 7,700’ to 8,300’Well Cost $6.3 to $7.4 MMLateral Lengths 5,000’ to 7,000’Reserves Per Well 363,000 BOE4Q2013 Production 269 BOEPD (91% oil)Eagle Ford Producers 3 gross/ 3 netProved Locations 6 gross/ 6 netProbable & Possible Locations 19 gross/19 net

22

Net Acres / HBP 3,449 / 3,370

W.I. / Royalty% 100.0% / 20.9%


Top EFS 7,300’ to 8,300’




Reserves Per Well 363,000 BOE

RecentProduction 3



Comments Acquired February, 2014 Prior operator drilled 3 Eagle Ford wells Engineered leasehold is surrounded by 29

Halcon Resources’ Eagle Ford producers (El Halcon)

Leasehold directly offset by wells with 30‐day IP’s of 500 to 800 BOEPD

Halcon and others have permitted 10 wells offsetting LNR’s acreage

2014 Drilling plans‐ 2 to 4 wells

Eagle Ford Shale – El Halcon

El Halcon Area

Stasny‐Honza #1H800 BOEPD

Mustang #1H660 BOEPD

Falcon #1H709 BOEPD

McDonald #1H706 BOEPD

Coyote #1H521 BOEPD

Moose #1H541 BOEPD


Upside Acreage

Producing EF Well

Permitted EF Well

30 Day Max Rate300

23

Net Acres / HBP 1,573 / 1,573

W.I. / Royalty% 62.0% / 20.7%


Comments Area 1‐ Productive in Cretaceous, Austin Chalk, Eagle Ford, Buda, Georgetown

Area 2‐ Productive in Cretaceous, Taylor, Austin Chalk, Eagle Ford, Buda, Georgetown

Area 3‐ Productive in Austin Chalk, Eagle Ford, Woodbine, Buda, Georgetown

Area 4‐ Productive in Wilcox, Cretaceous, Austin Chalk, Eagle Ford, Woodbine, Buda

Area 5‐ Productive in Tertiary, Yegua, Austin Chalk, Georgetown

Area 6‐ Productive in Austin Chalk, Sub‐Clarksville, Buda, Georgetown, Glen Rose

Brazos / Burleson County‐ Upside To Be Evaluated

Eagle Ford / Buda / Eaglebine / Woodbine


Upside Acreage

Producing EF Well

Permitted EF Well

Scout Information300

1

2

3

4

5

6Halcon Jones #1H

6,700 bo in Dec ‘13

Apache Reveille #7

21,200 bo in 76 days

Apache Leone #2H

4,900 bo in Dec ‘13

ApacheMcCullough‐Wineman #2H

Spud 11/21/2013

LaredoTxWorld Speedway#2a

Drilling

Conventional AssetsStability & Free Cash Flow

25

West Texas

North Texas

South Texas

Conventional Assets

3.8 MMBOE‐ Proved Reserves 79% Crude Oil

15% of Lonestar’s Total Proved Reserves

676 BOEPD‐ 4Q13 Production 72% Crude Oil & NGL’s

18% 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

East Texas

0

100

200

300

400

500

600

700

800

900

1,000

Jan‐12

Feb‐12

Mar‐12

Apr‐12

May

‐12

Jun‐12

Jul‐1

2

Aug‐12

Sep‐12

Oct‐12

Nov

‐12

Dec‐12

Jan‐13

Feb‐13

Mar‐13

Apr‐13

May

‐13

Jun‐13

Jul‐1

3

Aug‐13

Sep‐13

Oct‐13

Nov

‐13

Dec‐13

Net Produ

ction (BOEPD)

North Texas West Texas East Texas South Texas Other

1. Refer to the Reserves Information in the Appendix

Bakken‐Three Forks Growth and Development Strategy

27

West Poplar‐ Bakken/Three Forks

Billings

PARSHALL FIELD

Dunn

Divide

Williams

Mackenzie

BurkeSheridanDaniels

Roosevelt

Richland

Mountrail

FORT PECK RESERVATION

NES

SON

AN

TIC

LIN

E

POPLARDOME

West PoplarProject

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 was 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

Multiple conventional targets are productive in the immediate area, which provide good “bailout” potential (Charles, Amsden, Nisku, etc.)

28

West Poplar‐ Bakken/Three Forks

50,192 gross acres

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

Tested light crude oil from:

Lower Lodgepole ( 43.3 API) Bakken ( 41.2 API) Three Forks (45.8 API)

Established Bakken peak oil generation on the Project, which positively contrasts with offset well data

Ro‐ 0.88 Tmax: 457o

POPLARDOME

29

Bakken/Three Forks ‐West Poplar

July 2012

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

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 has been completed

and processing is underway. Leasing and regulatory filings necessary

for the formation of a 50,000 acre Federal Exploratory Unit are approaching completion

Seeking to maintain its focus in the Eagle Ford Shale, Lonestar will seek a farm‐in partner upon completion of its technical work

50,192 gross acres

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

31

Attractive Valuation Relative to Peers

Enterprise Value1 / 2014E EBITDAX

1. Lonestar Enterprise Value is calculated on a $0.27 / share price and 752.0m 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.Source: Bloomberg, company announcements and presentations.

0.0x

1.0x

2.0x

3.0x

4.0x

5.0x

6.0x

7.0x

8.0x

FST MTDR SN PVA AXAS AUT.AU LNR.AU RFE.AU SEA.AU

32

Attractive Valuation Relative to Peers

Enterprise Value1 / Proved Reserves (USD$/BOE)

1. Lonestar Enterprise Value is calculated on a $0.27 / share price and 752.0 mm 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. Does not consider the sale of Williston Basin Phoenix Prospect which was announced on October 31, 2013. Source: Bloomberg as at November 1, 2013, company announcements.

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$35.00

$40.00

SN MTDR AUT.AU PVA LNR.AU SEA.AU AXAS FST RFE.AU

33

$0

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

$140,000

Attractive Valuation Relative to PeersEnterprise Value1 / 2014E Production

1. Lonestar Enterprise Value is calculated on a $0.27 / share price and 752.0 mm 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, 2013. Source: Company presentations and press releases for U.S companies. Bloomberg as at November 1, 2013, company announcements.

3

Appendix

35

Fort Worth

EAGLE FORD SHALE

BAKKEN‐THREE FORKS

Significant Portfolio Focused On Unconventional Oil

Geographic Split of Proved Reserves 1

Hydrocarbon Split of Proved Reserves 1

Natural Gas20.6 Bcf

SEC‐PV10

Map of Major Assets

NGL’s2.3 MMBBLS

Crude Oil18.7 MMBO

Eagle Ford Shale19.3 MMBOE

Conventional4.2 MMBOE

Unconventional Assets

Conventional Assets

LEGEND

Eagle Ford Shale21.5 MMBO

Conventional4.1 MMBO

Eagle Ford Shale$483.9

Conventional$82.5

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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.

37

Footnotes

Reserves Reporting:

In accordance with Australian Securities Exchange (“ASX”) Listing Rule 5 and the new reporting requirements for oil and gas companies which applied from 1 December, 2013, please be advised that:

Lonestar’s Proved, Probable and Possible reserves have been estimated in accordance with the classification and reporting requirements of the Society of Petroleum Engineers’ –Petroleum Resources Management System (SPE – PRMS). Lonestar’s reserves are reported according to Lonestar’s economic interest in each of the reserves, in accordance with LR 5.25.5. In accordance with LR 5.25.5, Lonestar advises that its reserves estimates are calculated using a deterministic approach, under SPE‐PRMS.

Lonestar operates all of its Eagle Ford Shale and Conventional properties, other than its Conventional properties in South Texas and East Texas, which are non‐operated. All of Lonestar’s properties are held by standard oil and gas lease arrangements. The Company’s Working‐Interest ownership (WI%) and Net‐Revenue‐Interest ownership (NRI%) in relation to each of its material projects are included in the Company’s investor presentations, which are available on either the ASX website or the Company’s website (www.lonestarresources.com).

Well‐cost assumptions are based on historical costs achieved by Lonestar and/or other operators in areas proximate to Lonestar’s acreage. The reasonableness of these costs is assessed by the independent reserve evaluators. Indicative drilling timing on the Company’s projects is included in the Company’s investor presentations, which are available on the ASX website. The following well spacing assumptions and other details apply to the Company’s Eagle Ford Shale Properties:

Property Net Acres Well Locations Well Spacing WI NRI OperatorBeall Ranch: 2,318 20 500’ 97.7% 73.3% LonestarAsherton: 690 8 500’ 97.0% 73.2% LonestarCentavo 64 8 500’ 11.0% 9.1% ChesapeakeGonzo: 3,383 20 700’ 100.0% 75.0% LonestarPirate: 3,468 20 700’ 98.4% 73.1% LonestarLa Salle Frio 4,001 12 500’ 73.1% 57.2% VariousWilson County 4,133 19 750’ 97.2% 77.8% LonestarBrazos/Robertson 5,022 25 750’ 99.5% 78.8% Lonestar

Qualifications of Petroleum Reserve Evaluators:

The Proved and Probable reserves on the Company’s Eagle Ford Shale properties have been independently estimated as at December 31, 2013, by Mr. William D. Von Gonten, Jr., P.E., and, Mr. Taylor D. Matthes, of W. D. Von Gonten & Co. (“Von Gonten”). Messrs. Von Gonten and Taylor are licensed professional petroleum engineers and maintain active membership of the Society of Petroleum Engineers. They are employees of Von Gonten. Von Gonten is an independent petroleum‐engineering firm. Messrs. Von Gonten and Taylor consent to the inclusion in this report of the information and context in which it appears.

The Proved reserves on the Company’s Conventional properties have been independently estimated as at December 31, 2013, by Mr. William M. Kazmann, of La Roche Petroleum Consultants, Ltd. (“La Roche”). Mr. Kazmann is a licensed professional petroleum engineer and maintains active membership of the Society of Petroleum Engineers. He is an employee of La Roche. La Roche is an independent petroleum‐engineering firm. Mr. Kazmann consents to the inclusion in this report of the information and context in which it appears.

Commodity Pricing Used:

Lonestar’s estimated Proved and Probable Reserves, PV‐10 were determined using index prices determined in accordance with US SEC guidelines for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first‐day‐of‐the‐month prices for the year ended December 31, 2013 were $96.94 per Bbl for oil and $3.66 per MMBtu for natural gas and for the year ended December 31, 2012 were $95.05 per Bbl for oil and $2.78 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

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Reserves, PV‐10 and 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 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). 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)2014 $92.55 $4.252015 $86.55 $4.19

Lonestar Resources Investor Presentation- March...

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