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Lonestar ResourcesPresentation to Investors

August, 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. The information in thispresentation 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 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.

Currency

All amounts in this presentation are US$ unless otherwise stated. Lonestar’s presentation currency is $US.

3

Share Price History

Company Profile

Financial Profile Asset Profile 3

Lonestar is a rapidly growing E&P company focused on the Eagle Ford Shale

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

Ticker: OTCQX:LNREF ASX: LNR Share Price1: $0.51 Shares Out : 752.2 MM Market Cap1 : $384 MM Cash 2: $14 MM Long Term Debt 2 : $220 MM PF TEV : $590 MM 2014 EBITDAX Guidance: $105‐125 MM

1P Reserves (YE’13): 25.8 MMBoe Liquids (%): 87% Proved Developed (YE’13): 9.4 MMBoe 1P PV‐10 (YE’13): $564 MM 2P PV‐10 (YE’13): $679 MM 3P PV‐10 (YE’13): $778 MM R/P Ratio: 15.7x

NGLs9%

Crude Oil78%

Crude Oil76%

NGLs9%

1 In U.S. dollars, as of August 5th, 20142 In U.S. dollars, as of June 30th, 2014

3 Please see the reserves disclosures at the end of this presentation

0.0

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Jan‐13 Apr‐13 Jul‐13 Oct‐13 Jan‐14 Apr‐14 Jul‐14

Volume (M

M Sha

res)

Share Pr

ice (U

S$)

Volume Share Price

4

Lonestar’s Track Record of Rapid Growth

Reserves1

EBITDAX 2

Net Acreage‐ Eagle Ford Shale Trend

PV‐101

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Dec ‐10 Dec‐1 1 Dec‐12 Today

1P PV10 ($mm)

Ba rnett EFSA MU

1 Please see the reserves disclosures at the end of this presentation2 Please see the EBITDAX assumptions at the end of this presentation

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LNR CWEI Recently Acquired

Engine

ered

5

Lonestar’s Footprint 1

1. Please see the reserves and EBITDAX disclosures at the end of this presentation

BAKKEN ‐ THREE FORKS35,000 net acres

Resource Assessment3‐D Seismic Complete

41 Conventional Prospects identifiedIntense Fracturing in Unconventional Targets

EAGLE FORD SHALE30,306 net acres

Active Acquisition & Development40.0 MMBOE of Engineered Reserves95% of Lonestar’s 2014 Capital Budget

CONVENTIONAL OIL & GAS

Mature Producing Assets3.8 MMBOE of Engineered Reserves

$14 MM of EBITDAX, $2 MM of Capital Spending

Management TeamBackground and Track Record

7

High Caliber Management Team

Frank D. Bracken, III

Chief Executive Officer

Over 27 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

Executive Previous Experience Biography

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 30 Years of Average Experience

Gerrity Oil & Gas

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

GOG

8

High Caliber Management Team (Cont’d)

Executive Previous Experience Biography

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

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

Service Drilling

High Caliber Executive Team with Deep Industry Expertise and 30 Years of Average Experience

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

Eagle Ford ShaleGrowth and Development Plan

10

Lonestar’s Business Vision

Use Balance Sheet to Achieve Target of 40‐50,000 net acre Eagle Ford Shale positionMitigate

Risk Build mass around existing acreage hubs via primary‐term leasing, farm‐ins and purchases (1,000 – 5,000 acres)

When market conditions allow, achieve step‐change growth via asset or corporate acquisitions (~10,000 acres)

Conservatively Manage Our Financial Position‐ Drill with Cash Flow, Grow with Balance Sheet

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 80% in 2014, 78% in 2015, 78% in 2016

Execute Growth Plan on Existing Asset Base

Seasoned Team Drilling & Completion team has completed 75 Eagle Ford Shale wells

High Margins /Low Costs Lonestar’s Cash Margins per BOE averaged $66.43 in 2013, average well costs ~$6.0 million

Self‐Funded After $25 MM shortfall in 2014, Lonestar’s 21‐well, $130 MM 2015 Budget expected to be funded with cash flow at current Strip

High Growth Lonestar’s Eagle Ford Program capable of ultimately increasing EBITDAX by 4‐Fold vs. 2013 results of $55 MM

Organic Additions

Acquisitions

Limit Leverage

Bolt‐Ons Increase net leasehold adjacent to current leasehold via leases, purchases and farm‐ins

Bulk‐Ups Add new leasehold in proximity to successful wells to add scale in focus areas

Basin Exits Acquire whole positions, via unsolicited offers and data rooms, but maintain discipline

Farm‐ins Add drilling inventory for Lonestar, accelerate NPV for existing lease owner

1

2

3

11

Portfolio Focused on the Eagle Ford

Total Eagle Ford

Net Acres 30,306

Gross Engineered Locations 136

Additional Locations 86

Avg. W.I. 89%

Eastern

Net Acres 10,877



Avg. W.I. 88%

Central

Net Acres 11,320



Avg. W.I. 98%

Western

Net Acres 8,108



Avg. W.I. 79%

Engineered Acreage

Non‐Engineered Acreage

Non Recently Acquired Acreage

12

Eagle Ford Lease Map

Western Eagle Ford Acreage Map Central Eagle Ford Acreage Map Eastern Eagle Ford Acreage Map

Engineered Acreage Recently Acquired Acreage Producing Eagle Ford Well Permitted Eagle Ford Well

Ranger Beall Ranch

Asherton

Burns Ranch Area

Western Eagle Ford Acreage Table Central Eagle Ford Acreage Table Eastern Eagle Ford Acreage Table

Pirate

Gonzo

Gross Net WILeasehold‐ April, 2014 8,565 7,073 82.6%

Recent Acquisitions 1,755 1,035 59.0%

Current Leasehold 10,320 8,108 78.6%

Acquisition Cost ($MM) $3.2

Cost Per Acre $3,043


Recent Acquisitions 6,050 5,855 96.8%





Recent Acquisitions 546 336 61.6%




So. Gonzales

Upside Acreage

Aguila Vado

13

0

100

200

300

400

500

0 12 24 36 48 60 72 84 96 108

120

Prod

uction (Boe

pd)

Months on Production

Oil

NGLs

Dry Gas

Western Region Summary

Note: Type curves engineered by W. D. Von Gonten & Co.(1) Assumes flat natural gas price of $4.00 / Mcf.(2) Assumes flat LLS differential of $3.00 / bbl.

Single Well IRR Sensitivities(1,2)

Engineered Acreage

Upside Acreage

Producing Eagle Ford Well

Permitted Eagle Ford Well

Type Curve Assumptions

Lateral Length (Ft.) 5,000’

D&C Costs ($MM): $5.8

Gross EUR (MBoe): 392

% Oil: 77%

% Gas: 23%

30‐Day Sales IP (Boe/d): 568

LOE ($/Boe): $9.68

Sev. Tax – Oil (%): 4.6%

Sev. Tax – Gas (%): 7.1%

Ad Valorem Tax (%): 1.7%

Lateral Length (Ft.) 4,000’ 5,000’ 6,000’

Capex ($MM) $4.9 $5.8 $6.3

Oil Pr

ice

($/ B

bl)

$80.00 39% 46% 60%

$90.00 53% 62% 81%

$100.00 70% 82% 105%

Western Region Composite Type Curve

Overview

LEASE & DRILLING SUMMARYGross Leasehold 10,320Net Leasehold 8,108% HBP 87.2%Top EPS 6,500' to 7,900'Lateral Lengths 3,900' to 7,500'Assumed Spacing 500'

RESERVES SUMMARY# Oil NGL's Gas Equiv. PV‐10

Category Wells (MMBbls) (MMBbls) (Bcf) (MMBOE) ($MM)

PDP 19 3.9 0.6 4.4 5.3 $175.4PUD 38 6.9 1.4 9.8 9.9 $180.2Proved 57 10.8 2.0 14.2 15.2 $355.6Probable 9 0.9 0.2 1.5 1.3 $19.3Possible 1 0.1 0.0 0.2 0.2 $1.9Total Reserves 67 11.9 2.2 15.8 16.8 $376.7Please see the Reserves disclosures at the end of this presentation

Beall Ranch

Asherton

Burns Ranch

Recent Acquisition

14

Western Region Leasehold Detail

Beall Ranch Asherton

Permitted EFS Well

Burns Ranch Area

Beall Ranch

Gross Net2Q14 Production (BOEPD) 2,213 1,622

Producing Eagle Ford Wells 18 13.2

Engineered Acreage 2,373 2,318Drilling LocationsProved 20 20Probable 0 0Possible 0 0Engineered Locations 1 20 20

Additional Acreage 0 0Drilling LocationsUpside Acreage 0 0Recently Acquired 0 0Additional Locations 1 0 0

Asherton Burns Ranch Area

Gross Net2Q14 Production (BOEPD) 758 553

Producing Eagle Ford Wells 4 3.9

Engineered Acreage 711 690Drilling LocationsProved 6 6Probable 2 2Possible 0 0Engineered Locations 1 8 8

Additional Acreage 0 0Drilling LocationsUpside Locations 0 0Recently Acquired 0 0Additional Locations 1 0 0


Producing Eagle Ford Wells 0 0

Engineered Acreage 1,325 819Drilling LocationsProved 7 6Probable 4 2Possible 1 1Engineered Locations 1 12 8

Additional Acreage 3,516 3,182Drilling LocationsUpside Locations 0 0Recently Acquired 16 10Additional Locations 1 16 10

Engineered Acreage Upside Acreage Producing EFS WellPUD Probable Possible

1 Gross and Net locations may not always correspond due to rounding

Recently Acq’d

15

Central Region Summary


Engineered Acreage

Upside Acreage







% Oil: 93%

% Gas: 7%


LOE ($/Boe): $13.19

Sev. Tax – Oil (%): 4.6%

Sev. Tax – Gas (%): 7.1%



Capex ($MM) $5.3 $6.1 $6.9

Oil Pr

ice

($/ B

bl)

$80.00 21% 25% 28%

$90.00 31% 35% 40%

$100.00 42% 47% 53%

Central Region Composite Type Curve

0

100

200

300

400

0 12 24 36 48 60 72 84 96 108

120

Prod

uction (Boe

pd)


Oil

NGLs

Dry Gas


Overview





Pirate

Gonzo

Recently Acq’d

So. Gonzales

16

Central Region Leasehold Detail

Pirate South Gonzales


Gonzo

Pirate South Gonzales Gonzo

Engineered Acreage Upside Acreage Producing Eagle Ford WellPUD Probable Possible












Engineered Acreage 0 0Drilling LocationsProved 0 0Probable 0 0Possible 0 0Engineered Locations 1 0 0


Recently Acq’d

17

Eastern Region Summary


Engineered Acreage

Upside Acreage







% Oil: 95%

% Gas: 5%


LOE ($/Boe): $11.66

Sev. Tax – Oil (%): 4.6%

Sev. Tax – Gas (%): 7.1%



Capex ($MM) $6.3 $6.9 $7.4

Oil Pr

ice

($/ B

bl)

$80.00 26% 34% 44%

$90.00 37% 48% 61%

$100.00 50% 65% 82%

Eastern Region Composite Type Curve

0

100

200

300

400

500

600

0 12 24 36 48 60 72 84 96 108

120

Prod

uction (Boe

pd)


Oil

NGLs

Dry Gas


Overview





Aguila Vado

Recent Acquisitions

18

Eastern Region‐ Engineered Acreage

Eastern Eagle Ford Region



Engineered Acreage 3,839 3,449Drilling LocationsProved 6 6Probable 3 3Possible 16 16Engineered Locations 25 25

Additional Acreage 7,805 6,897Drilling LocationsUpside Acreage 12 10Recently Acquired 49 40Additional Locations 1 61 50

Engineered Acreage Recently Acquired Producing Eagle Ford WellPUD Probable Possible Permitted Eagle Ford Well


Brazos

Eastern Eagle Ford Locator Map

19

Eastern Region – Downdip Play Expansion

Upside Acreage Recently Acquired Producing Eagle Ford Well Permitted Eagle Ford Well

McCullough‐Wineman #2H1,455 BOEPD

Jones #2H782 BOEPD

Cervelo #1HTesting

RobertsonEastern Eagle Ford Locator Map

Brazos

Texas World Speedway #2HProducing

Henry #1H774 BOEPD

Stifflemire #1H661 BOEPD

2014 Downdip WellActive Rig

Conventional AssetsStability & Free Cash Flow

21

West Texas

North Texas

South Texas

Conventional Assets

3.8 MMBOE‐ Proved Reserves 1 79% Crude Oil 15% of Lonestar’s Total Proved Reserves

605 BOEPD‐ 2Q14Production 75% Crude Oil & NGL’s 15% of Lonestar’s Total Production

Long‐Lived Reserves with Low Capital Requirements Reserves/Production ratio of 15 years Current Capital Plans <$2 MM annually

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

East Texas

1. Please see Reserves disclosures at the end of this presentation

Daily Production

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

Jan‐14

Feb‐14

Mar‐14

Apr‐14

May

‐14

Jun‐14

Net Produ

ction (BOEPD)

North Texas West Texas East Texas South Texas Other

Bakken‐Three Forks Resource Assessment

23

Bakken/Three Forks

Billings

PARSHALL FIELD

Dunn

Divide

Williams

Mackenzie

BurkeSheridanDaniels

Roosevelt

Richland

Mountrail

FORT PECK RESERVATION

NES

SON ANTICL

INE

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 “over‐cooked” north and west of Brockton‐Froid Fault

Acreage was selected due to its proximity to the Poplar Dome, which Lonestar believed would yield enhanced fracturing in the uncoventional target zones

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

Greater Williston BasinWest Poplar Resource Assessment

24

Bakken/Three Forks

50,192 gross acresLNR 65% WI

Stone Turtle Exploratory Unit (proposed)

Lonestar and its partners drilled the Clark Farms #29‐10 in July, 2012 as a vertical completion

Tested light crude oil from three zones that comprise a 150’ horizontal drilling target:

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

Lonestar has materially improved the prospectivity of this leasehold, pre‐drill

EA approval obtained (FONSI) 3‐D seismic survey has been completed,

processed and interpreted Anisotropy reveals excellent fracture

quality in Lodgepole, Bakken, Three Forks Identified 11 Nisku prospects/leads, 24

Charles prospects/leads, 7 Mississippian prospects/leads

52,559 acre Stone Turtle Exploratory Unit approved by Tribal Council, with delivery to BLM scheduled for June 30th

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

POPLARDOME

Lonestar’s Progress

25

Bakken/Three Forks

Nisku Formation TargetsCharles Formation Locations

Appendix

27

$0

$100

$200

$300

$400

$500

$600

$700

$800

$900

TEV Proved PV‐10 2P PV‐10 3P PV‐10

SEC PV

‐10 (US$MM)

Pv‐10 & Share Price Valuation

1. Please see the Reserves disclosures at the end of this presentation

Net Debt

Equity$0.52

per share

$0.48per share

$0.63per share

$0.77per share

28

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.

29

Reserves InformationReserves Reporting:

Pursuant to ASX Listing Rules (“LR”) the reserves information in this document:

(i) is effective as at 1 January, 2014 (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 generally disclosed in the Company announcement related to the initial acquisition of the 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.

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 Gontenholds 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 2004 through 2006). 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‐10 have bee 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, 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 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 affecting the price received at the wellhead."

30

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 2013). Operating expenditure for each asset is based on the most recent Lease Operating Statements for each asset (as of 31 December 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

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